UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Act of 1934
For the fiscal year ended December 31, 1996
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ______ to ______
Commission file Number: 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 73-1268729
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Eleven Greenway Plaza, Suite 1606, Houston, Texas 77046
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code: (713) 621-3993
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock $.01 par value
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value (estimated solely for purposes of this
calculation) of the voting stock held by non-affiliates of the registrant as of
March 19, 1997, was approximately $10,367,360.
As of March 19, 1997, there were outstanding 66,819,125 shares of
Common Stock, par value $.01 per share, of the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
The registrant's definitive proxy statement for the 1997 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.
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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.
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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 13 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. Crude oil and condensate storage capacity
was increased from 70,000 Bbls to 85,000 Bbls in 1996.
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 three field gathering lines connected to the main
20-inch line, two 6 inch 8 mile lines and one 4-inch 6 mile line. The field
gathering lines were acquired in 1995 and 1996. These new
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lines expand the System's market penetration. The System's onshore segment
consists of approximately 2 miles of 16-inch pipeline for transportation of
natural gas from the shore facility to a sales point at a Freeport, Texas
chemical plants' complex and intrastate pipeline system tie-in.
Various fees are charged to producer/shippers for provision of
transportation and other services at the shore facility. Blue Dolphin Pipeline
System throughput averaged approximately 30% of capacity during 1996. Current
System capacity is approximately 160 million cubic feet ("MMcf") per day of gas
and 7,000 Bbls per day of oil and condensate. Ninety eight percent of gas
volumes transported and 99% of oil and condensate volumes transported are
attributable to production from third party producer/shippers. See Note 13 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 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, attraction and retention to the system, and execution
of contracts with producer/shippers to gather and transport their oil and gas
production through the Blue Dolphin Pipeline 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.
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Operation of the field is conducted from two platforms located in waters
averaging approximately 65 feet in depth.
The Company owns a 100% working interest in the Buccaneer Field (81.33% net
revenue interest), less and except 100% of the Operating Rights covering 4,230
acres as to certain depths, which are assigned to the Farmee pursuant to a
Farmout Agreement entered into in 1993. The Company retains a 6.33% overriding
royalty interest before payout in the Operating Rights assigned. See Note 12 to
Consolidated Financial Statements of Blue Dolphin Energy Company and
Subsidiaries included in Item 8 and incorporated herein by reference. The
Buccaneer Field leasehold interests represent 100% of the discounted present
value of estimated future net revenues from Proved Reserves of the Company as of
December 31, 1996. 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, 1996, 1995 and 1994. 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 1997.
From October 1995 through September 1996, the Company received a fixed monthly
price of $1.70/MMBtu. From October 1996 through September 1997 a fixed monthly
price of $2.02/MMBtu is in effect. Buccaneer Field gas sales represented 90% of
oil and gas sales revenues and 8% of total revenues of the Company for the year
ended December 31, 1996.
Buccaneer Field condensate sales are based on spot market prices at the
time of sale. Sale of condensate from the Buccaneer Field represented 10% of oil
and gas sales revenues and 1% of total revenues of the Company for the year
ended December 31, 1996.
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, 1996, the sinking fund totalled approximately $570,000. 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 one third party producer/shipper. During
1996, revenues attributable to provision of contract operation and maintenance
services represented 10% of the Company's total revenues.
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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
period ending July 31, 1999, to acquire 3-D seismic data. In addition to
recovering prospect development costs, BDEX will retain a reversionary working
interest in each prospect sold. 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 43.75% interest in
each of the three 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, or commercial
quantities of oil and gas will be found.
Concurrent with the sales effort, BDEX is seeking funding for a multi-year
prospect generation and exploration drilling and development program. Such
funding, if obtained, would allow BDEX to retain an initial working interest in
future prospects developed and sold.
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.
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, 1996, by Gerald W.
DuPont Enterprises, Inc., independent petroleum engineers.
The following table summarizes the estimates of Proved Reserves, Proved
Developed Reserves (as hereinafter defined), future net revenues and the
discounted present value of future net revenues from Proved Reserves before
income taxes to the net interest of the Company in oil and gas properties as of
December 31, 1996, using the SEC Method (defined below).
PROVED RESERVES INFORMATION
AS OF DECEMBER 31, 1996
Net Oil Net Gas Future Discounted Future
Reserves Reserves Net Revenues Net Revenues (3)
Buccaneer Field: (MB) (MMCF) ($000) ($000)
-------- -------- ------------ ------------
Proved Reserves (1) 194 32,715 $ 51,111 $ 24,322
======== ======== ============ ============
Proved Developed Reserves (2) 118 19,591 $ 34,209 $ 17,113
======== ======== ============ ============
MB = THOUSAND BARRELS MMCF = MILLION CUBIC FEET
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- ----------
(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 15 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 presented in the evaluations
summarized above reflect capital expenditures totalling $250,000, $2,250,000,
$2,275,000 and $2,000,000 in the years ending December 31, 1998, 1999, 2000 and
2001, respectively. Management will continue to evaluate its capital expenditure
program based on, among other things, demand and prices obtainable for the
Company's production. The availability of capital resources may affect the
Company's timing for further development of the Buccaneer Field, and there can
be no assurance that the timing of the development of such reserves will be as
currently planned.
The discounted present value of estimated future net revenues attributable
to Proved Reserves has been prepared in accordance with the SEC Method after
deduction of royalties and other third-party interests, lease operating
expenses, and estimated production, development, workover and recompletion
costs, but before deduction of income taxes, general and administrative costs,
debt service and depletion and amortization. Estimated future net revenues are
based on prices of oil and gas in effect at the end of the year without
escalation except to the extent contractually committed. Lease operating
expenses, and production and development costs, were estimated based on such
costs in effect at the end of the year, assuming the continuation of existing
economic conditions and without adjustment for inflation or other factors. The
present value of estimated future net revenues is computed by discounting future
net revenues at a rate of 10% per annum. Revenues from wells not currently
producing are included at the time they are expected to be placed into
production based upon estimates of future development; workover and recompletion
costs are included at the time they are expected to be incurred. Of the
Company's total Proved Developed Reserves, 8% of its estimated gas reserves and
9% of its estimated oil reserves were being produced at December 31, 1996.
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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 15 - 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, 1996.
ACREAGE AND WELLS
Productive Wells (1) Developed Undeveloped
----------------------------- ------------- -------------
Gross Net Acres (1) Acres (1)
----------------------------- ------------- -------------
Oil Gas Oil Gas Gross Net Gross Net
----- ----- ----- ----- ------- ----- ------- -----
Buccaneer Field 0 2 0 1.1 8730 8730 5930 5930
- ----------------
(1) "Productive wells" are producing wells and wells capable of production,
and include gas wells awaiting pipeline connections or necessary
governmental certifications to commence deliveries and oil wells to be
connected to production facilities. "Developed acres" include all acreage
as to which proved reserves are attributed, whether or not currently
producing, but exclude all producing acreage as to which the Company's
interest is limited to royalty, overriding royalty, and other similar
interests. "Undeveloped acres" are considered to be those acres on which
wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas regardless of whether
such acreage contains Proved Reserves. "Gross" as it applies to wells or
acreage refers to the number of wells or acres in which a working
interest is owned, while "net" applies to the sum of the fractional
working interests in gross wells or acreage.
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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,
-----------------------------------------
1996 1995 1994
----------- ----------- -------------
Gas:
Production (Mcf) 180,269 326,388 490,587
Revenue $ 342,119 $ 645,727 $ 1,073,324
Average Mcf Per Day 492.5 894.2 1,344.1
Average Sales Price
per Mcf $ 1.90 $ 1.98 $ 2.19
Oil:
Production (Bbls) 1,887 2,327 3,791
Revenue (1) $ 36,147 $ 38,934 $ 58,312
Average Bbls per day 5.2 6.4 10.4
Average Sales Price
per BBL $ 19.16 $ 16.73 $ 15.38
Production Costs:
Per Equivalent Mcf (2): $ 3.42 $ 2.76 $ 1.93
- ----------
(1) Recognition of Buccaneer Field oil revenue is based upon production,
when such production is available for sale.
(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 90% of oil and gas sales and 8% of total revenues of the Company
in the year ended December 31, 1996. Condensate sales accounted for 10% of oil
and gas sales during the year ended December 31, 1996.
DRILLING ACTIVITY. There was one unsuccessful exploratory well drilled in
1996 on a prospect generated and sold to third parties by the Company. There was
no drilling activity during 1995. There was one unsuccessful Farmout well
drilled in 1994 and one successful Farmout well drilled in 1993, with production
commencing in 1994.
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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. by 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 offshore terminal and storage facility
will receive and store crude oil and refined products with deliveries into Gulf
Coast markets. 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 and the 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, long-term storage of crude oil and products.
Ownership, construction and operation of the Petroport facility must
conform to the requirements of a number of federal, state and local laws and
regulations. 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.
To date the Company has focused its development efforts on pre-licensing
activities, certain regulatory issues associated with the Oil Pollution Act of
1990 ("OPA 90"), specifically addressing deepwater ports, and amendment of the
1974 Deepwater Port Act. See "Competition, Markets and Regulation Governmental
Regulations" below. Major pre-licensing activities include: development of
support for the project from both federal and state agencies that have
jurisdiction over or impact deepwater port licensing, construction and
operation; facility commercial profile development; development of the
engineering design and capital and operating cost estimates; development of an
estimate of the cost of obtaining the necessary license and permits; and
development of a financing strategy.
In addition to the Company's successful efforts addressing the impact of
OPA 90 on the proposed facility and passage of The Deep Water Port Modernization
Act in 1996 (see "Competition, Markets and Regulation Governmental
Regulations"), a major component of the projects commercial profile was
completed in fourth quarter 1996. The commercial profile is expressed in terms
of both current conditions and conditions expected to prevail through 2015.
Results of the work are being evaluated to determine additional analysis
required, definition of the facility's market niche and the effects thereof on
facility design.
Two favorable offshore sites have been identified for location of the
primary facility.
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The Petroport deepwater port license application and related permit
requests are expected to be submitted in 1998, with operations expected to
commence in the year 2001.
Approximately $615,000 has been incurred through December 31, 1996
associated with acquisition and development of Petroport. Total cost of the
facility is currently estimated at approximately $500 million.
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.
Notwithstanding recent increases in natural gas and crude oil prices, the
prices of crude oil, natural gas, and refined petroleum products, generally,
have declined significantly in the past ten years as a result of an oversupply
relative to the demand for such products. The spot market price for certain
grades of
11
<PAGE>
crude oil has declined from a high price of approximately $40 per Bbl in 1981 to
an average of approximately $19.95 per Bbl in 1996, discounting volatile market
fluctuations.
GOVERNMENTAL REGULATION
The production, processing, marketing and transportation of oil and natural
gas and planned terminaling and storage of imported crude oil by the Company are
subject to federal, state and local regulations which can have a significant
impact upon the Company's overall operations.
FEDERAL REGULATION OF NATURAL GAS TRANSPORTATION. 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. Among other things, Order No. 636 (i) required interstate
pipelines to provide transportation and storage services to all customers
(including third-party gas sellers) on a comparable basis, (ii) required
interstate pipelines to design their rates using a straight-fixed-variable
methodology, under which all of the pipeline's fixed costs are allocated to the
pipeline's reservation charges, and (iii) provided several mechanisms by which
unused interstate pipeline transportation capacity can be reallocated in the
marketplace. Although the pipelines have gone through Order No. 636
restructuring, 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 pending 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
Commission overruled his decision, on the condition, however, that Transco must
first file a new rate case and conduct an "open season" to permit customers to
elect production service area under this new rate design. Transco has not taken
these steps.
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<PAGE>
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 will proceed in the future. 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. 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.
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<PAGE>
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. At the
same time, the FERC launched an inquiry to explore ways to improve the
collection of data on oil pipeline costs. Because Buccaneer Pipeline has not
taken action to become subject to Order No. 561, the Company cannot predict
whether or how an indexed rate system will affect the Buccaneer Pipeline's
rates. Similarly, it is not possible to predict the impact of possible
additional reporting requirements.
REGULATION OF DEEPWATER PORTS: PERMITTING AND LICENSING. The ownership,
construction and operation of a deepwater crude oil port and storage facility,
such as the Company's proposed Petroport facility, must conform to the
requirements of a number of Federal, State and local laws. A license from the
Department of Transportation ("DOT") is required under the Deepwater Port Act of
1974 ("DWPA"), as amended. Department of the Interior, U.S. Army Corps of
Engineers and various state permits are also required to construct ancillary
port facilities, such as pipelines and onshore facilities.
The DWPA empowers the Secretary of Transportation 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 principle 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 power or reservation over
proposed projects. 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 the proposed projects 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".
14
<PAGE>
Given the nature, complexity and costs associated with obtaining the
necessary license and permits, there can be no assurance that the Company will
be successful in developing the necessary data for submission of the various
applications, and if the applications are developed and submitted, will be
successful in the review and approval process, with ultimate issuance of a
Deepwater Port license and other necessary permits.
LIMITS OF LIABILITY AND CERTIFICATE OF FINANCIAL RESPONSIBILITY
REQUIREMENTS FOR DEEPWATER PORTS. In February 1995, DOT published a Notice of
Proposed Rulemaking under OPA 90, which among other things, would have resulted
in a limit of liability for Petroport under OPA 90 and required Petroport
provide a Certificate of Financial Responsibility ("COFR") before a license
under DWPA would be issued, of $350,000,000. The limit of liability and
associated COFR could be reduced by the Secretary of DOT to as low as
$50,000,000, through a separate rulemaking procedure, if the results of a study
evaluating a deepwater port's risks, including spill history (meaning the
facility must be up and running), warranted a limit reduction.
In August 1995, the DOT issued its' final rule providing that the Secretary
of DOT, through a separate rulemaking, can set the limit of liability/COFR for
future deepwater ports (i.e., Petroport) concurrent with the overall processing
of the license application, as opposed to after the facility is up and running.
The development of the liability limit would be based upon engineering and
environmental analyses provided in the licensing process. While this is a major
compromise on the part of DOT, the uncertainty as to what the revision to the
limit, if any, would be, still presented a significant obstacle to Petroport,
affecting the ability to raise funding for permitting activities and obtain
future throughput commitments.
In an effort to remove this uncertainty, and allow the project to proceed,
the Company prepared and submitted to DOT a preliminary "Detailed Analysis of
Spill Potential and A Determination of Expected Oil Spill Quantities" for the
proposed Petroport facility. The results of the analysis indicated that the
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 in U.S. waters. The number of barrels as
determined by DOT in the Oil Spill Risk Analysis for LOOP, was multiplied by the
maximum cost per barrel for cleanup of a barrel of oil of $11,965, also as
determined by DOT, resulting in a reduced liability limit of $62,000,000 for
LOOP. Per the Company's analysis, if DOT applied this same methodology in
determining Petroport's 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.
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<PAGE>
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 planned, poses no greater oil spill risk to the
environment than does LOOP, (2) that Petroport's offshore storage caverns show
virtually zero spill potential, (3) that Petroport's credible worst case spill
would be 2308 barrels, and (4) that the preliminary risk analysis for Petroport
is based upon valid 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 seward of the seward boundary of a state, including
properties used for oil transportation. The Company currently maintains this
statutory $35,000,000 coverage.
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<PAGE>
Federal and state legislative rules and regulations are pending that, if
enacted, could significantly affect the oil and gas industry. It is impossible
to predict which of those federal and state proposals and rules, if any, will be
adopted and what effect, if any, they would have on the operations of the
Company.
In addition, various federal, state and local laws and regulations covering
the discharge of materials into the environment, occupational health and safety
issues, or otherwise relating to the protection of public health and the
environment, may affect the Company's operations, expenses and costs. The trend
in such regulation has been to place more restrictions and limitations on
activities that may impact the general or work environment, such as emissions of
pollutants, generation and disposal of wastes, and use and handling of chemical
substances. It is not anticipated that, in response to such regulation, the
Company will be required in the near future to expend amounts that are material
relative to its total capital structure. However, it is possible that the costs
of compliance with environmental and health and safety laws and regulations will
continue to increase. Given the frequent changes made to environmental and
health and safety regulations and laws, the Company is unable to predict the
ultimate cost of compliance.
ITEM 2. PROPERTIES
Information appearing in Item 1 describing the Company's properties under
the caption "Business and Properties" is incorporated herein by reference.
In addition, the Company leases, under a lease expiring September 30, 1998,
6,069 square feet for its corporate and subsidiaries' executive offices in
Houston, Texas.
ITEM 3. LEGAL PROCEEDINGS
Neither the Company nor any of its property is subject to any material
pending legal proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matter to a vote of security holders during
the quarter ended December 31, 1996.
17
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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, 1997, 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, 1995 ............. $.38 $.22 $.44 $.25
Quarter Ended June 30, 1995 .............. .34 .16 .41 .19
Quarter Ended September 30, 1995 ......... .56 .22 .59 .25
Quarter Ended December 31, 1995 .......... .41 .31 .44 .34
Quarter Ended March 31, 1996 ............. .41 .28 .50 .34
Quarter Ended June 30, 1996 .............. .53 .34 .56 .38
Quarter Ended September 30, 1996 ......... .34 .28 .41 .31
Quarter Ended December 31, 1996 .......... .38 .28 .44 .34
The Company currently intends to retain earnings for its capital needs and
expansion of its business and does not anticipate paying cash dividends on the
Common Stock in the foreseeable future. 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 8 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated
herein by reference.
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RECENT SALES OF UNREGISTERED SECURITIES
During April 1996, warrants to purchase 16,575,578 shares of Common Stock
were exercised at an exercise price of $.10 per share. The Company relied on an
exemption under Section 4(2) of the Securities Act in effecting this
transaction.
During the year ended December 31, 1996, Directors, Officers and other
employees exercised options to purchase 308,333 shares of Common Stock pursuant
to the Company's 1985 Stock Option Plan at exercise prices ranging from $.06250
to $.21250 per share. The Company relied on an exemption under Section 4(2) of
the Securities Act in effecting these transactions.
Effective December 31, 1996, the Company issued 14,560,475 shares of Common
Stock upon conversion of outstanding shares of Series A Cumulative Convertible
Preferred Stock, $.10 par value per share. The Company relied on an exemption
under Section 3(a)9 of the Securities Act in effecting this transaction.
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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, 1996, 1995,
1994, 1993 and 1992. 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,
---------------------------------------------------------------------------
1996 1995 1994 1993 (2) 1992
----------- ----------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Operating Revenues $ 4,128,568 $ 5,123,053 $ 6,792,765 $ 5,220,330 $ 3,105,296
Income (Loss) from
continuing operations 92,302 7,355,686(3) 930,659 358,694 (1,143,305)
Income (Loss) from
continuing operations
per primary Common
Share (1) -- $ .15 $ .02 -- ($ .05)
Weighted average number of
common shares and common
share equivalents
outstanding, primary 50,832,889 47,525,088 47,626,300 38,479,361 27,268,659
Income (Loss) from continuing
operations per fully dilluted
Common Share (1) -- $ .11 $ .01 -- ($ .05)
Weighted average number of
common shares and dilutive
common share equivalents
outstanding 65,378,844 62,763,059 62,278,671 67,817,957 27,268,659
Net Income 92,302 7,355,686 1,542,699 855,799 (958,269)
Working Capital (deficit) 917,113 659,692 (1,415,091) (2,282,435) (2,240,206)
Total Assets 24,226,611 25,069,178 20,759,338 21,351,080 20,070,712
Long-term obligations
Bonds -- -- -- 2,500,000 4,100,000
Other long-term debt 2,060,600 10,000 4,450,000 2,642,303 3,282,496
</TABLE>
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(1) Income from continuing operations per share of Common Stock in 1996, 1995,
1994 and 1993 is based on the weighted average number of common and common
equivalent shares outstanding. The loss from continuing operations per
share of Common Stock for 1992 is based on the weighted average number of
common shares outstanding. See Note 5 to Consolidated Financial Statements
of Blue Dolphin Energy Company and Subsidiaries included in Item 8 and
incorporated herein by reference.
(2) The Company changed its method of accounting for income taxes in 1993. See
Note 4 to Consolidated Financial Statements of Blue Dolphin Energy Company
and Subsidiaries included in Item 8 and incorporated herein by reference.
(3) Includes the gain on sale of a one-third interest in the Blue Dolphin
Pipeline System effective August 1, 1995.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is a review of certain aspects of the financial condition and
results of operations of the Company and should be read in conjunction with the
Consolidated Financial Statements of 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, 1996, the Company's working capital (current assets less
current liabilities) increased to $917,113, representing an improvement of
$257,421 as compared with working capital of $659,692 at December 31, 1995, due
primarily to proceeds the Company received in 1996 from warrants exercised.
Pursuant to the rules of the full cost method of accounting for oil and gas
properties, $1,902,995 of oil and gas prospect development and lease acquisition
costs, which the Company expects to recover in 1997 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 November 1, 1996, the
borrowing base was adjusted to $1,925,000 reducing by $75,000 per month
beginning December 1, 1996. The borrowing base and reducing amount
21
<PAGE>
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.
From March 1994 through September 1995, warrants to purchase 681,562 shares
of Common Stock at $.10 per share were exercised. In April 1996, remaining
warrants to purchase 16,575,578 shares of Common Stock at $.10 per share were
exercised. There are currently no warrants outstanding.
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 8 to Consolidated Financial
Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8
and incorporated herein by reference.
Offshore activity in the vicinity of the Blue Dolphin Pipeline System has
remained active. In October 1996, a new discovery was tied-in to the System. The
additional throughput resulted in a 37% increase in daily gas volumes
transported and a 24% increase in pipeline revenues in fourth quarter 1996
compared to third quarter 1996. In addition, in February 1997, a second
discovery was tied-in to the System. Approximately an 8% increase in first
quarter 1997 daily gas volumes transported is expected as compared to the fourth
quarter 1996.
A 4-inch 6 mile producer flowline tied into the main 20-inch Blue Dolphin
Pipeline was acquired in 1996. To further expand the System's market penetration
and to help maintain existing throughput, significant new line additions are
currently being evaluated. Future utilization of the Company's pipelines and
related facilities will depend upon the success of drilling programs in the Blue
Dolphin Pipeline corridor, attraction and retention to the System, and execution
of contracts with producer/shippers to transport their gas and oil through the
Blue Dolphin Pipeline System. (See Business and Properties - Pipeline Operations
and Activities). Additionally, certain rate designs associated with interstate
pipeline restructuring under Order No. 636 and other issues before FERC may
affect the Company when competing for future pipeline system transportation
volumes. Impact on the Company if its interstate pipeline competitors implement
such rate designs or are successful in other regulatory matters cannot
accurately be predicted at this time (See "Competition, Markets and Regulation -
Governmental Regulation").
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 late 1997 or 1998.
In August 1996, the U.S. Minerals Management Service ("MMS") conducted an
annual inspection of the Buccaneer Field production platforms and facilities. In
addition to certain repairs, the Company was
22
<PAGE>
required to remove piping and other equipment that was no longer in use.
Additionally, certain major modifications and repairs were required to an
existing producing well. The well was off production from August 1996 until late
December 1996. As of December 31, 1996, costs associated with removal and
partial abandonment activities, and costs associated with repairs to the
platforms and well, totalled approximately $464,000 and $483,000, respectively.
The removal and abandonment work, and the repairs to the platforms and well,
were completed in March 1997. Additionally, the Company plans to plug and
abandon a previously inactive well and remove the associated satellite platform
at a cost estimated to be approximately $500,000.
The reserves and future net revenues presented in Item 1 "Business - Oil
and Gas Exploration and Production Activities", reflect capital expenditures
totalling $250,000, $2,250,000, $2,275,000, and $2,000,000 in the years ending
December 31, 1998, 1999, 2000 and 2001, respectively. Management will continue
to evaluate its capital expenditure program based on, among other things, field
reservoir performance, availability and cost of drilling and rework 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 acquired four lease blocks prospective for oil and gas in the
High Island Area in the September 1995 Federal Western Gulf of Mexico lease
sale. Approximately $2,000,000 was invested to acquire the necessary acreage for
further prospect development, in addition to costs of approximately $400,000
associated with technical development of the prospects. A remaining 75% interest
in one of these prospective lease blocks was sold in June 1996. Proceeds
received were approximately $390,000. An unsuccessful well was drilled and has
been plugged and abandoned. A 43.75% interest in each of the three remaining
prospective lease blocks has been sold. Efforts to sell the remaining interests
in each block are ongoing. Additionally, the Company is seeking funding for a
multi year 3-D seismic based prospect generation and exploration and development
drilling program. Such funding will enable the Company to participate as an
initial working interest owner and possible operator rather than participating
on an after payout basis, as the prospect generation program was originally
structured. In August 1994, the Company entered into a multi year 3-D seismic
data acquisition and licensing agreement whereby a minimum of $1,500,000 has
been committed to acquire 3-D seismic data.
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. Major pre-licensing activities
include: development of support for the project from both Federal and State
agencies that have jurisdiction over or impact deepwater port 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 obtaining the necessary license and permits; and
development of a financing strategy.
It is currently estimated that pre-licensing costs will total between
$1,000,000 - $1,250,000. Approximately $615,000 has been committed through
December 31, 1996. Total cost of the facility is currently estimated at
approximately $500 million.
The Company expects to submit the Petroport deepwater port license
application and associated permit requests in 1998, with operations commencing
in the year 2001.
23
<PAGE>
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, 1996 ("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 is 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.
1995 net income of $7,355,686, represented a $5,812,987 or 377 percent
increase over net income of $1,542,699 reported for the year ended December 31,
1994 ("1994"). The increase in earnings was primarily due to the Pipeline Sale,
effective August 1, 1995. Results for the year ended December 31, 1995, included
a provision for income taxes of $1,840,183. Of this amount, $827,039 was a
non-cash charge in lieu of taxes allocated directly to paid-in capital
reflecting utilization of net operating loss carryforwards that were incurred
prior to a quasi-reorganization recorded at December 31, 1989. $756,602 was
recorded as a deferred tax liability partially offset by a current tax asset of
$173,188.
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.
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.
1995 VS. 1994. In 1995, the Company recorded as other income a pretax
gain of $8,693,228 from the Pipeline Sale.
Revenues from pipeline system operations decreased by $1,123,695 or 22% in
1995 from those of 1994, due primarily to a 29% reduction in gas transportation
volumes which resulted in a $911,000 reduction in revenues and the Pipeline
Sale, which resulted in a $586,161 reduction in revenues. The decrease in gas
transportation revenues was partially offset by an increase in revenues from oil
transportation of $307,974, resulting from an increase in throughput volumes.
24
<PAGE>
Revenues from oil and gas sales and operating fees decreased by $546,017 in
1995 from those of 1994. Gas sales decreased $408,099 or 40% due to a 33%
decrease in production and a 7% decrease in the average sales price received.
Operating fees declined $99,000 due to termination of production activities by a
producer for whom the Company provided contract operation and maintenance
services.
COSTS AND EXPENSES
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, partially offset by lower 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 discussed
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.
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.
1995 VS. 1994. Pipeline system operating expenses decreased $242,120 in
1995 from those in 1994. The decrease was due to a $189,625 reduction in costs
resulting from the Pipeline Sale and a reduction of approximately $240,000
associated with repairs to the Blue Dolphin Pipeline System incurred in 1994.
Partially offsetting these decreases were an increase in contract labor costs of
$117,822 associated with a new labor contract effective April 1995, $35,782 in
costs associated with repairs made to the Company's onshore oil storage tanks
and an $18,316 increase in salt water disposal fees.
Depletion, depreciation and amortization expense decreased by $113,133 in
1995 from 1994. The decrease was primarily due to the Pipeline Sale.
Interest expense decreased by $201,986 in 1995 from 1994. The Company
retired substantially all of its debt in August 1995.
25
<PAGE>
NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 1996, the Company adopted SFAS No. 123, Accounting for
Stock-Based Compensation. This SFAS 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. Accordingly, there was no significant impact as a result of
the Company's adoption of SFAS No. 123.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements: Page
----
Independent Auditors' Report ....................................... 27
Consolidated Balance Sheets, at December 31, 1996 and 1995 ......... 28
Consolidated Statements of Operations, for the years
ended December 31, 1996, 1995, and 1994 ....................... 30
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1996, 1995, and 1994 ................. 31
Consolidated Statements of Cash Flows, for the years
ended December 31, 1996, 1995, and 1994 ....................... 32
Notes to Consolidated Financial Statements ......................... 33
26
<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, 1996 and 1995, 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, 1996.
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, 1996 and 1995, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1996, in conformity with generally
accepted accounting principles.
KPMG Peat Marwick LLP
Houston, Texas
March 17, 1997
27
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1996 and 1995
Assets 1996 1995
----------- ----------
Current assets:
Cash and cash equivalents ....................... $ 1,207,323 2,748,467
Trade accounts receivable ....................... 744,283 860,691
Crude oil inventory, at market .................. 28,460 19,180
Prepaid expenses and other assets ............... 70,340 72,824
Current deferred taxes .......................... -- 173,188
----------- ----------
Total current assets ....................... 2,050,406 3,874,350
----------- ----------
Property and equipment, at cost:
Oil and gas properties, including
$1,902,995 and $2,402,796 of leases
held for sale at December 31, 1996
and 1995, respectively (full-cost method) ...... 20,853,859 20,561,239
Onshore separation and handling facilities ...... 2,038,865 1,845,791
Land ............................................ 1,133,333 1,133,333
Pipelines ....................................... 1,020,457 848,198
Other property and equipment .................... 116,776 80,150
----------- ----------
25,163,290 24,468,711
Less accumulated depletion, depreciation and
amortization ................................... 4,535,945 4,267,431
----------- ----------
20,627,345 20,201,280
----------- ----------
Other assets ..................................... 1,548,860 993,548
----------- ----------
$24,226,611 25,069,178
=========== ==========
See accompanying notes to consolidated financial statements.
28
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1996 and 1995
Liabilities and Stockholders' Equity 1996 1995
----------- ----------
Current liabilities:
Trade accounts payable ............................. $ 1,086,220 1,008,251
Lease bonus payable ................................ -- 1,375,488
Current portion of accrued abandonment costs ....... -- 547,948
Other liabilities and accrued expenses ............. 8,253 32,871
Income taxes payable ............................... 38,820 250,100
----------- ----------
Total current liabilities ..................... 1,133,293 3,214,658
----------- ----------
Long-term debt, less current portion ................ 2,060,600 10,000
Deferred federal income taxes ....................... 633,956 756,602
Accrued abandonment costs, less current portion ..... 798,185 1,242,615
Dividends payable on preferred stock ................ -- 1,747,646
----------- ----------
Total long-term liabilities ................... 3,492,741 3,756,863
----------- ----------
Stockholders' equity:
Cumulative convertible preferred stock,
Series A, $.10 par value. 25,000,000 shares
authorized; -0- and 14,560,475 shares issued and
outstanding at December 31, 1996 and 1995 ......... -- 1,456,048
Common stock, $.01 par value. 100,000,000
shares authorized; 66,769,125 shares issued
and outstanding at December 31, 1996; 35,324,739
shares issued and outstanding at December 31, 1995 667,691 353,247
Additional paid-in capital ......................... 17,007,087 14,163,661
Retained earnings since January 1, 1990 ............ 1,925,799 2,124,701
----------- ----------
Total stockholders' equity .................... 19,600,577 18,097,657
Commitments and contingencies ....................... -- --
----------- ----------
$24,226,611 25,069,178
=========== ==========
See accompanying notes to consolidated financial statements.
29
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
Years ended December 31, 1996, 1995, and 1994
<TABLE>
<CAPTION>
1996 1995 1994
------------ ----------- -----------
<S> <C> <C> <C>
Revenue from operations:
Pipeline operations .................................................. $ 3,276,520 3,893,770 5,017,465
Oil and gas sales and operating fees ................................. 852,048 1,229,283 1,775,300
------------ ----------- -----------
Revenue from operations .......................................... 4,128,568 5,123,053 6,792,765
------------ ----------- -----------
Cost of operations:
Pipeline operating expenses .......................................... 871,305 1,049,747 1,089,935
Lease operating expenses ............................................. 609,805 833,314 794,754
Repairs and maintenance .............................................. 895,357 377,634 620,373
Depletion, depreciation and amortization ............................. 388,406 619,586 732,719
General and administrative expenses .................................. 1,315,256 1,410,175 1,463,578
------------ ----------- -----------
Cost of operations ............................................... 4,080,129 4,290,456 4,701,359
------------ ----------- -----------
Income from operations ........................................... 48,439 832,597 2,091,406
Other income (expense):
Interest expense ..................................................... (16,790) (405,980) (607,966)
Gain on sale of assets ............................................... 4,397 8,693,228 --
Interest and other income ............................................ 119,045 76,024 39,390
------------ ----------- -----------
Income before income taxes and
extraordinary item .............................................. 155,091 9,195,869 1,522,830
------------ ----------- -----------
Income taxes .......................................................... (62,789) (1,840,183) (592,171)
Extraordinary item - gains from early retirement of debt
(net of income tax charge of $315,293 in 1994) ....................... -- -- 612,040
------------ ----------- -----------
Net income ....................................................... 92,302 7,355,686 1,542,699
Dividend requirements on preferred stock .............................. (291,204) (291,204) (291,204)
------------ ----------- -----------
Net income attributable to
common stockholders ............................................. $ (198,902) 7,064,482 1,251,495
============ =========== ===========
Primary earnings per common share:
Income before extraordinary item and after
dividend requirements on preferred stock ............................. $ -- 0.15 0.02
Extraordinary item .................................................... -- -- 0.01
------------ ----------- -----------
Net income ............................................................ $ -- 0.15 0.03
============ =========== ===========
Weighted average number of common shares
and common share equivalents outstanding ............................. 50,832,889 47,525,088 47,626,300
============ =========== ===========
Fully diluted earnings per common share:
Income before extraordinary item ...................................... $ -- 0.11 0.01
Extraordinary item .................................................... -- -- 0.01
------------ ----------- -----------
Net income ............................................................ $ -- 0.11 0.02
============ =========== ===========
Weighted average number of common shares
and dilutive common share equivalents outstanding .................... 65,378,844 62,763,059 62,278,671
============ =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
30
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended December 31, 1996, 1995, and 1994
<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, 1993 ........................ $ 336,515 1,456,048 12,259,384 (6,191,276) 7,860,671
Exercise of 420,941 warrants ....................... 4,209 -- 37,885 -- 42,094
Exercise of 436,668 stock options .................. 4,367 -- 75,052 -- 79,419
Cancellation of common stock ....................... (1,300) -- 1,300 -- --
Pre-quasi reorganization net operating
loss carryforwards utilized ....................... -- -- 809,663 -- 809,663
Dividend requirements on preferred
stock ............................................. -- -- -- (291,204) (291,204)
Net income ......................................... -- -- -- 1,542,699 1,542,699
Other .............................................. -- -- 27,070 -- 27,070
--------- ---------- ---------- ---------- -----------
Balance at December 31, 1994 ........................ 343,791 1,456,048 13,210,354 (4,939,781) 10,070,412
--------- ---------- ---------- ---------- -----------
Exercise of 260,620 warrants ....................... 2,606 -- 23,456 -- 26,062
Exercise of 693,336 stock options .................. 6,850 -- 102,812 -- 109,662
Pre-quasi reorganization net operating
loss carryforwards utilized ....................... -- -- 827,039 -- 827,039
Dividend requirements on preferred
stock ............................................. -- -- -- (291,204) (291,204)
Net income ......................................... -- -- -- 7,355,686 7,355,686
--------- ---------- ---------- ---------- -----------
Balance at December 31, 1995 ........................ 353,247 1,456,048 14,163,661 2,124,701 18,097,657
--------- ---------- ---------- ---------- -----------
Exercise of 16,575,578 warrants .................... 165,755 -- 1,490,802 -- 1,656,557
Exercise of 308,333 stock options, net of
tax benefit ....................................... 3,084 -- 39,157 -- 42,241
Dividend requirements on preferred
stock ............................................. -- -- -- (291,204) (291,204)
Conversion of 14,560,475 shares of
preferred stock ................................... 145,605 (1,456,048) 1,307,634 -- (2,809)
Other .............................................. -- -- 5,833 -- 5,833
Net income ......................................... -- -- -- 92,302 92,302
--------- ---------- ---------- ---------- -----------
Balance at December 31, 1996 ........................ $ 667,691 -- 17,007,087 1,925,799 19,600,577
========= ========== ========== ========= ==========
</TABLE>
See accompanying notes to consolidated financial statements.
31
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended December 31, 1996, 1995, and 1994
<TABLE>
<CAPTION>
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
Operating activities:
Net income ........................................................... $ 92,302 7,355,686 1,542,699
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Extraordinary gains-early retirement of debt ....................... -- -- (612,040)
Depletion, depreciation and amortization ........................... 388,406 619,586 732,719
Deferred income taxes .............................................. 50,542 1,410,363 494,370
Gain on sale of property and equipment ............................. (4,397) (8,693,228) --
Gain on sale of government bonds and
related accretion ................................................ -- -- (38,676)
Changes in operating assets and liabilities:
(Increase) decrease in trade accounts receivable .................. 116,408 (86,329) 342,990
(Increase) decrease in crude oil inventory,
prepaid expenses and other assets ................................ (6,796) 39,100 (276,615)
(Decrease) in trade accounts payable,
accrued interest and other liabilities ........................... (157,929) (135,979) (2,320,825)
----------- ---------- ----------
Net cash provided by (used in)
operating activities .......................................... 478,536 509,199 (135,378)
----------- ---------- ----------
Investing activities:
Oil and gas prospect generation costs ................................ (1,960,217) (924,039) --
Proceeds from sales of oil and gas prospect
generation leases ................................................... 397,178 -- --
Purchases of property and equipment .................................. (529,893) (602,309) (479,028)
Increase in other assets ............................................. (224,893) (338,489) --
Proceeds from sales of property and equipment ........................ 7,050 9,824,165 --
Proceeds from redemption of government bonds ......................... -- -- 306,000
Abandonment of oil and gas properties ................................ (1,047,908) -- --
Funds escrowed for abandonment costs ................................. (374,569) (457,642) (112,174)
----------- ---------- ----------
Net cash provided by (used in)
investing activities .......................................... (3,733,252) 7,501,686 (285,202)
----------- ---------- ----------
Financing activities:
Proceeds from borrowings ............................................. -- 925,000 5,916,653
Payments on borrowings ............................................... -- (6,757,299) (5,819,362)
Payments on borrowings from related parties .......................... -- -- (15,000)
Net proceeds from the exercise of stock
options and warrants ............................................... 1,713,572 135,724 121,513
----------- ---------- ----------
Net cash provided by (used in)
financing activities .......................................... 1,713,572 (5,696,575) 203,804
----------- ---------- ----------
Increase (decrease) in cash .................................... (1,541,144) 2,314,310 (216,776)
Cash and cash equivalents at beginning of year ........................ 2,748,467 434,157 650,933
----------- ---------- ----------
Cash and cash equivalents at end of year .............................. $ 1,207,323 2,748,467 434,157
=========== ========== ==========
Supplementary cash flow information:
Interest paid ........................................................ $ 17,000 406,000 915,000
=========== ========== ==========
Income taxes paid .................................................... $ 226,519 235,030 106,572
=========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
32
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 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, processing and
marketing. It was formed pursuant to a reorganization effective June 9,
1986.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of the Company include the
accounts of its wholly-owned subsidiaries. All significant intercompany
balances and transactions have been eliminated in consolidation.
ACCOUNTING ESTIMATES
Management has made a number of estimates and assumptions relating to
the reporting of assets and liabilities and to the disclosure of
contingent assets and liabilities 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 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.
(Continued)
33
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Included in oil and gas properties are $1,902,995 and $2,402,796 of
leases acquired with the intention of selling to third party
participants as drillable oil and gas prospects as of December 31, 1996
and 1995, respectively. The separate prospects are individually
reviewed for recoverability and are excluded from amortization unless
impairment is indicated. The Company sold the remaining 75% of one
lease in 1996 and the proceeds of $390,550 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 75% of the remaining leases
and substantially recover this cost in 1997. Also included in oil and
gas properties at December 31, 1996 are $584,728 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.
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. Aggregate abandonment
liability is estimated to be approximately $4,250,000 and $4,000,000 at
December 31, 1996 and 1995, respectively.
STOCK-BASED COMPENSATION
Effective January 1, 1996, the Company adopted SFAS No. 123, ACCOUNTING
FOR STOCK-BASED COMPENSATION. This SFAS 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. Accordingly, there was no significant impact
as a result of the Company's adoption of SFAS No. 123.
(Continued)
34
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Statement 109, deferred
tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases and operating loss and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The
effect on deferred tax assets and liabilities of a change in tax rates
is recognized in income in the period that includes the enactment date.
NET INCOME PER SHARE
Net income per common share is computed after consideration of dividend
requirements on preferred stock, using the weighted average number of
common shares outstanding and common share equivalents during each of
the years presented. Outstanding stock options and warrants are common
share equivalents and are considered when the effect is dilutive.
Cumulative convertible preferred stock are other potentially dilutive
securities and are considered in fully diluted net income per share
when the effect is dilutive. Net income per common share in 1996 was
less than $.01 per share.
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 (see note 8).
The Company purchased oil and gas leases during 1995, of which
$1,375,488 was paid in 1996.
(Continued)
35
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) QUASI-REORGANIZATION
In connection with the Company's emergence from Chapter 11 proceedings
in 1989, the Board of Directors authorized the Company to revalue its
consolidated balance sheet at December 31, 1989 to fair value in
accordance with principles of accounting for quasi-reorganizations. The
principal adjustments to fair value included an $810,000 increase in
the carrying value of land and the elimination of the remaining
deferred debt offering costs associated with the Convertible
Subordinated Notes of $994,192, resulting in a net charge to the
accumulated deficit of $184,192.
The Company's remaining assets and liabilities at December 31, 1989
approximated fair value; accordingly, the accumulated depletion,
depreciation and amortization at December 31, 1989 was eliminated
against the original cost of the assets. The accumulated deficit of
$14,031,556 at December 31, 1989 was then transferred to additional
paid-in capital. Any benefits realized upon the utilization of tax
operating losses generated prior to January 1, 1990 were credited to
additional paid-in capital (see note 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 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, 1996, as there was no significant change in prime rate
since issuance of the note payable in December 1996.
(5) INCOME TAXES
Income taxes were allocated as follows for 1996, 1995 and 1994:
1996 1995 1994
------- --------- -------
Income from continuing operations . $62,789 1,840,183 592,171
Extraordinary gains ............... -- -- 315,293
--------- -------
$62,789 1,840,183 907,464
======= ========= =======
(Continued)
36
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income tax expense attributable to continuing operations for 1996, 1995
and 1994 consists of:
1996 1995 1994
---------- --------- -------
Current:
Federal .......... $ -- 189,500 29,000
State ............ 12,247 240,320 68,801
Deferred Federal .... 50,542 1,410,363 494,370
---------- --------- -------
$ 62,789 1,840,183 592,171
========== ========= =======
During 1995 and 1994, the valuation allowance decreased approximately
$2,272,000 and $809,000, respectively. As a result of the quasi-
reorganization described in note 2, the benefits of the reduction in
1994 and $827,000 of the reduction in 1995 were recorded directly to
stockholders' equity and the statements 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, 1996 and 1995 are presented below.
1996 1995
----------- ----------
Deferred tax assets:
Accrued abandonment costs ...................... $ 249,356 400,068
Net operating loss carryforwards ............... 2,435,537 2,230,409
Alternative minimum tax credit ................. 228,897 230,240
----------- ----------
Total gross deferred tax assets ...... 2,913,790 2,860,717
Deferred tax liabilities:
Bases differences in property and equipment .... (3,527,171) (3,444,131)
State tax ...................................... (20,575) --
----------- ----------
Total gross deferred tax liability ... (3,547,746) (3,444,131)
----------- ----------
Net deferred tax liability ........... $ 633,956 583,414
=========== ==========
1996 1995
----------- ----------
Allocated as follows:
Current deferred taxes ......................... $ -- (173,188)
Noncurrent deferred tax liability .............. 633,956 756,602
----------- ----------
$ 633,956 583,414
=========== ==========
In assessing the realizability of deferred tax assets, management
considers whether it is more likely than not that some portion or all
of the deferred tax assets will not be realized. The Company does not
believe a valuation allowance is necessary because the benefit of such
deferred tax assets are expected to be fully utilized.
(Continued)
37
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company's effective tax rate applicable to continuing operations in
1996, 1995 and 1994 differs from the expected tax rate of 34% due to
the following:
1996 1995 1994
---- ---- ----
Expected tax rate .......................... 34% 34% 34%
State taxes, net of federal benefit ........ 5 2 3
Expenses not deductible for tax purposes ... 1 -- 2
Decrease in valuation allowance recognized
in earnings ............................ -- (16) --
-- --- --
40% 20% 39%
== === ==
At December 31, 1996, the Company had the following estimated net
operating loss carryforwards (NOL):
YEAR OF NET OPERATING LOSS
EXPIRATION CARRYFORWARDS
---------- -------------
2002 $ 1,572,310
2003 1,954,812
2004 2,066,517
2006 1,011,469
2007 402,349
2011 104,173
----------
$ 7,111,630
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
1996. 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
$228,897 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.
(Continued)
38
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(6) LONG-TERM DEBT
In January 1994, the Company arranged a reducing revolving credit
facility (Loan Agreement) with Bank One, Texas, N.A. (Bank One), in an
amount of $10,000,000. At December 31, 1996, the borrowing base under
the Loan Agreement was $1,850,000 reducing $75,000 per month. The
borrowing base is determined 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.
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. Upon consummation of
the Loan Agreement in January 1994, debt totaling $6,350,379, including
$2,000,000 of the Series B Notes (see note 7) and accrued interest were
retired for approximately $5,460,000. The resulting gain was recorded
as an extraordinary item in 1994.
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, mature
in four years 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, 1996 and 1995 is as follows:
DECEMBER 31,
-------------------
1996 1995
---------- ------
$10,000,000 bank credit facility, interest payable
monthly at prime rate (8.25% at December 31, 1996)
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 --
2,060,600 10,000
Less current maturities .................................. -- --
---------- ------
$2,060,600 10,000
========== ======
(Continued)
39
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(7) CONVERTIBLE SUBORDINATED NOTES
In June 1986, the Company issued $8,000,000 of 7-1/2% convertible
subordinated notes due 2001, convertible at $4.80 per share into
2,083.25 shares of common stock for each $10,000 note. Pursuant to the
note agreement, a portion of the proceeds were reserved as collateral.
At December 31, 1993, $500,000 face amount of the notes were
collateralized by government bonds (Series A Notes) scheduled to mature
in May 2001 for $500,000. The remaining $2,000,000 of the notes at
December 31, 1993 were collateralized by a third lien on oil and gas
properties (Series B Notes). The net proceeds of the notes were
originally used to acquire and develop oil and gas properties.
In 1994, the $500,000 of notes collateralized by government bonds, plus
accrued interest of approximately $25,000, were purchased at a cost of
approximately $470,000 and the remaining $2,000,000 of Series B Notes,
plus accrued interest of approximately $87,500, were purchased at a
cost of approximately $1,250,000. The government bonds collateralizing
the Series A Notes purchased was released to the Company and sold. The
$928,000 gain ($612,040 net of related income tax) on the early
retirement of these notes and the indebtedness in note 6 was recorded
as an extraordinary item in 1994.
(8) 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.
(Continued)
40
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(9) 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, in its 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 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, 1996. 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, 1996, the Company has reserved a total of 8,686,959
shares of Common Stock for issuance under the above mentioned stock
option plans, of which 2,009,997 shares relate to options granted prior
to 1996, under the previous stock option plan. The outstanding stock
options granted to key employees, officers and directors, for the
purchase of shares of the Company's Common Stock, are as follows:
EXERCISE
PRICE PER SHARE
------------------
SHARES FROM TO
---------- ------ ------
Balance, December 31, 1994 ............. 2,128,334 $.0625 .3453
Granted ............................ 910,000 .1859 .1859
Exercised .......................... (693,337) .1594 .3453
---------- ------ ------
Balance, December 31, 1995 ............. 2,344,997 .0625 .2922
========== ====== ======
Granted ............................ 945,000 .2656 .2656
Exercised .......................... (308,333) .0625 .2125
Expired ............................ (26,667) .1594 .2125
---------- ------ ------
Balance, December 31, 1996 ............. 2,954,997 $.0625 .2922
========== ====== ======
The weighted average exercise price per share was $.1370 and $.1582 in
1996 and 1995, respectively.
(Continued)
41
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 1996, 661,676 options are immediately exercisable.
Pursuant to the requirements of FASB No. 123, the weighted average fair
market value of options granted during 1996, 1995 and 1994 are $.17,
$.17 and $.27, respectively. The closing bid prices for the Company's
stock at the date the options were granted during 1996, 1995 and 1994
are $.31, $.22 and $.34, 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 67%, 122% and 126% and risk-free interest rates
of 5.89%, 6.17%, and 6.52% for grants in 1996, 1995 and 1994,
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
1996, 1995 or 1994 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:
YEAR ENDED DECEMBER 31,
-------------------------
1996 1995
-------- ---------
Net income (loss) As reported $ 92,302 7,355,686
Pro forma (33,483) 7,269,282
Primary earnings (loss) As reported -- 0.15
per share Pro forma (.01) 0.15
Fully diluted earnings As reported -- 0.11
(loss) per share Pro forma -- 0.11
Outstanding options at December 31, 1996 expire between January 15,
1997 and November 11, 2001.
The outstanding exercisable warrants to purchase shares of the
Company's Common Stock at $.10 per share per warrant, issued in
connection with debt refinancings are as follows:
WARRANTS
-----------
Balance, December 31, 1994 ................. 16,836,199
Exercised .................................. (260,621)
-----------
Balance, December 31, 1995 ................. 16,575,578
Exercised .................................. (16,575,578)
-----------
Balance, December 31, 1996 ................. --
===========
(Continued)
42
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
(10) 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 which a
director of the Company is a principal, for business development
consulting services. The Company paid $91,600 under the contract in
1996 and $90,000 in 1995 and 1994.
(11) LEASES
The Company's lease for a vapor recovery unit was capitalized and
included in property, plant and equipment in 1993. The lease expired in
1995. The Company paid $405,000 during the term of the lease to acquire
the vapor recovery unit.
In addition, the Company has various noncancelable operating leases
which continue through 1998.
The following is a schedule of future minimum lease payments required
under long-term noncancelable operating leases at December 31, 1996:
YEARS ENDING
DECEMBER 31,
------------
1997 .................................. $ 146,844
1998 .................................. 108,483
-------
$ 255,327
Rental expense under operating leases for the years indicated were as
follows:
YEARS ENDED
DECEMBER 31,
------------
1996 ................................. $ 213,603
1995 ................................. 253,430
1994 ................................. 225,576
(Continued)
43
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(12) 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), formerly Ivory
Production Co., to provide additional security to ensure it could meet
the future abandonment obligations associated with the Buccaneer Field.
In February 1994, BDEX and the MMS agreed on the form of such security
and the amount of the future obligations.
As additional security for the future Buccaneer Field abandonment 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 the
greater of the net proceeds from Buccaneer Field farmout acreage or
$250,000 annually will be set aside until a total of approximately
$2,400,000 has been accumulated to meet end of lease abandonment and
site clearance obligations. The Company estimates the remaining 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. BDEX's minimum commitment during
the remainder of the agreement is $1,050,000.
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.
(Continued)
44
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(13) 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 pipeline
and pipeline system. The intercompany revenues and expenses are
eliminated in consolidation. Information concerning these segments for
the years ended December 31, 1996, 1995 and 1994 is as follows:
<TABLE>
<CAPTION>
OPERATING DEPLETION,
INTERSEGMENT INCOME IDENTIFIABLE DEPRECIATION AND
REVENUES REVENUES (LOSS)(1) ASSETS AMORTIZATION(2)
--------- ------------ ---------- ------------ ----------------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 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
========= ======== ========= ========== =======
Year ended December 31, 1994:
Oil and gas exploration
and production $ 1,775,300 -- (34,273) 14,774,449 443,563
Pipeline operations 5,122,238 104,773 2,681,451 2,557,582 218,715
Consolidated 6,792,765 -- 2,091,406 20,759,338 732,719
========= ========= ========= ========== =======
</TABLE>
(1) Consolidated income from operations includes $358,465, $328,013,
and $380,558 in unallocated general and administrative expenses,
and unallocated depletion, depreciation and amortization of
$52,760, $81,168, and $70,441 for the years ended December 31,
1996, 1995 and 1994, respectively.
(2) Pipeline depletion, depreciation and amortization includes a
provision for pipeline abandonment of $26,340, $33,970 and
$39,420 for each of the years ended December 31, 1996, 1995 and
1994, respectively. Oil and gas depletion, depreciation and
amortization includes a provision for abandonment costs of
platforms and wells of $29,190, $51,898, and $33,760 for the
years ended December 31, 1996, 1995 and 1994, respectively.
See the supplemental disclosures for oil and gas producing activities
(see note 15) for discussion of capitalized costs incurred for oil and
gas production operations. Capital expenditures of $365,333 were
incurred for pipeline operations for the year ended December 31, 1996.
(Continued)
45
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company's primary market area is the Texas Gulf Coast region of the
United States. The Company has a concentration of credit risk with
customers in the energy and chemical industries. The Company's
customers may be similarly affected by changes in economic, regulatory
or other factors. Trade receivables are generally not collateralized;
however, the Company's customers' historical and future credit
positions are thoroughly analyzed prior to extending credit. Revenues
from major customers exceeding 10% of segment revenues were as follows
for the periods indicated:
<TABLE>
<CAPTION>
OIL AND GAS
SALES AND PIPELINE
OPERATING FEES OPERATIONS TOTAL
<S> <C> <C> <C>
Year ended December 31, 1996: -------------- ---------- -----------
The Coastal Corporation $ 49,085 1,281,147 1,330,232
Apache Oil Corp. 401,265 696,319 1,097,584
The Dow Chemical Company 342,119 120,636 462,755
=========== ======= ==========
Year ended December 31, 1995:
Apache Oil Corp. $ 395,321 779,432 1,174,753
The Coastal Corporation 46,218 922,096 968,314
The Dow Chemical Company 645,727 97,930 743,657
The Louisiana Land and Exploration Co. -- 453,036 453,036
=========== ======= ==========
Year ended December 31, 1994:
The Dow Chemical Company $ 1,073,324 137,709 1,211,033
Apache Oil Corp. 362,630 711,653 1,074,283
Seagull Energy Corporation -- 873,088 873,088
The Coastal Corporation 65,567 729,576 795,143
Houston Exploration Company -- 558,156 558,156
============= ======= ==========
</TABLE>
(14) 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 port 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 9,000,000 shares of Company Common Stock, with
issuance dependent upon successful completion of the facility and
maintaining a prespecified throughput volume. As of December 31, 1996,
the Company has capitalized $465,000 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.
(Continued)
46
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
The following supplemental information regarding the oil and gas
activities of the Company is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange Commission
(SEC) and Statement of Financial Accounting Standards No. 69
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Statement 69).
At December 31, 1996, 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 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.
(Continued)
46
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OIL GAS
QUANTITY OF OIL AND GAS RESERVES (BBLS) (MCF)
-------------------------------- ---- ---
Total proved reserves at December 31, 1993 ...... 224,294 37,766,430
-------- -----------
Revisions to previous estimates ................. (25,098) (3,800,747)
Production ...................................... (3,791) (490,587)
-------- -----------
Total proved reserves at December 31, 1994 ...... 195,405 33,475,096
-------- -----------
Revisions to previous estimates ................. 9,088 (51,572)
Production ...................................... (2,327) (326,388)
-------- -----------
Total proved reserves at December 31, 1995 ...... 202,166 33,097,136
-------- -----------
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
======== ===========
Proved developed reserves:
December 31, 1996 ........................... 117,724 19,591,098
December 31, 1995 ........................... 126,088 19,973,190
December 31, 1994 ........................... 119,327 20,351,150
======== ===========
CAPITALIZED COSTS OF OIL AND
GAS PRODUCING ACTIVITIES
The following table sets forth the aggregate amounts of capitalized
costs relating to the Company's oil and gas producing activities and
the aggregate amount of related accumulated depletion, depreciation and
amortization as of the dates indicated.
DECEMBER 31,
---------------------------
1996 1995
------------ -----------
Unproved properties and prospect generation costs
not being amortized .......................... $ 2,590,347 2,402,796
Proved properties being amortized ................ 18,263,512 18,158,443
Less accumulated depletion, depreciation and
amortization ................................... (3,835,649) (3,687,474)
Net capitalized costs ................. $ 17,018,210 16,873,765
============ ===========
Accrued offshore platform and
well abandonment costs ......................... $ 244,190 1,262,908
============ ===========
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, 1997.
(Continued)
48
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
--------------------------------
1996 1995 1994
---------- --------- -------
Property acquisition costs - unproved
properties and prospect generation ...... $ 584,728 2,402,796 103,449
Exploration costs .......................... -- -- 136,290
Development costs .......................... 105,069 349 249,050
---------- --------- -------
$ 689,797 2,403,145 488,789
========== ========= =======
Depletion expense per Mcf
equivalent produced ................. $ .97 1.05 .86
========== ========= =======
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,
----------------------------
1996 1995
------------ -----------
Future cash inflows ........................... $ 75,422,337 63,264,355
Future development costs ...................... (10,156,601) (9,935,722)
Future production costs ....................... (14,154,887) (14,136,174)
------------ -----------
Future net cash inflows
before income taxes ........................ 51,110,849 39,192,459
Future income taxes ........................... (15,236,647) (11,293,210)
------------ -----------
Future net cash flows ......................... 35,874,202 27,899,249
10% discount factor ........................... (17,680,462) (13,420,440)
------------ -----------
Standardized measure of discounted
future net cash inflows .......... $ 18,193,740 14,478,809
============ ===========
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, 1996, such prices were $24.55 per barrel of oil and $2.16 per Mcf
of gas) and (2) deducting estimated expenditures to be incurred during
each year to develop and produce the proved reserves (based on current
costs). In general, oil prices declined in early 1997. 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.
(Continued)
49
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company cautions readers that the standardized measure information
which places a value on proved reserves is not indicative of either
fair market value or present value of future cash flows. Other logical
assumptions could have been used for this computation which would
likely have resulted in significantly different amounts. Such
information is disclosed solely in accordance with Statement 69 and the
requirements promulgated by the SEC to provide readers with a common
base for use in preparing their own estimates of future cash flows and
for comparing reserves among companies. Management of the Company does
not rely on these computations when making investment and operating
decisions.
Principal changes in the STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS attributable to the Company's proved oil and gas reserves
for the periods indicated are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------
1996 1995 1994
----------- ---------- -----------
<S> <C> <C> <C>
Sales and transfers, net of production costs * $ 996,305 397,517 (47,212)
Net change in estimated future development
costs ..................................... (105,110) 7,222 840,437
Net change in income taxes ................... (1,748,864) (1,201,592) 7,453,049
Revisions in previous quantity estimates ..... (209,443) 1,734 (3,147,268)
Net changes in sales and transfer prices,
net of production costs ................... 5,566,602 (2,502,045) (13,437,157)
Accretion of discount ........................ 1,885,846 1,838,675 3,471,079
Change in production rates (timing)
and other ................................. (2,670,405) 728,610 (4,003,917)
----------- ---------- -----------
Net change .......................... $ 3,714,931 (729,879) (8,870,989)
=========== ========== ===========
</TABLE>
* 8% of the Company's estimated gas reserves and 9% of its estimated
oil reserves were being produced at December 31, 1996.
50
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
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 1997 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 1997 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 1997 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 1997 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.
51
<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, 1996
and 1995 .................................................. 28
Consolidated Statements of Operations, for the
years ended December 31, 1996, 1995, and 1994 ............. 30
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1996, 1995, and 1994 ............. 31
Consolidated Statements of Cash Flows, for the
years ended December 31, 1996, 1995, and 1994 ............. 32
Notes to Consolidated Financial Statements .................. 33
52
<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
4.1 (2) Specimen Certificate of Blue Dolphin Energy Company Common Stock
* 10.3 (5) Blue Dolphin Energy Company 1985 Employee Stock Option Plan
* 10.4 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
53
<PAGE>
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 as of August 31, 1995.
10.28 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.
* Management Compensation Plan.
(b) Reports on Form 8-K
None
54
<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 31, 1997
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 31, 1997
Michael J. Jacobson executive officer)
/s/ G. BRIAN LLOYD Treasurer/Secretary March 31, 1997
G. Brian Lloyd
/s/ IVAR SIEM Chairman March 31, 1997
Ivar Siem
/s/ HARRIS A. KAFFIE Director March 31, 1997
Harris A. Kaffie
/s/ DANIEL B. PORTER Director March 31, 1997
Daniel B. Porter
/s/ MICHAEL S. CHADWICK Director March 31, 1997
Michael S. Chadwick
/s/ CHRISTIAN HYSING-DAHL Director March 31, 1997
Christian Hysing-Dahl
55
BLUE DOLPHIN ENERGY COMPANY
1996 STOCK OPTION PLAN
I. PURPOSE OF THE PLAN
The BLUE DOLPHIN ENERGY COMPANY 1996 STOCK OPTION PLAN (the "Plan") is
intended to provide a means whereby certain employees of BLUE DOLPHIN ENERGY
COMPANY (the "Company"), and its subsidiaries may develop a sense of
proprietorship and personal involvement in the development and financial success
of the Company, and to encourage them to remain with and devote their best
efforts to the business of the Company, thereby advancing the interests of the
Company and its shareholders. Accordingly, the Company may grant to directors
and certain employees ("Optionees") the option ("Option") to purchase shares of
the common stock of the Company ("Stock"), as hereinafter set forth. Options
granted under the Plan may only be options which DO NOT constitute Incentive
Stock Options under the terms of Section 422 of the Internal Revenue Code of
1986, as amended (the "Code").
II. ADMINISTRATION
The Plan shall be administered by a committee (the "Committee") of, and
appointed by, the Board of Directors of the Company (the "Board"), and the
Committee shall be comprised solely of two or more directors. The Committee
shall have sole authority to select the Optionees from among those individuals
eligible hereunder and to establish the number of shares which may be issued
under each Option; provided, however, that, notwithstanding any provision in the
Plan to the contrary, the Committee shall not grant Options which (together with
any other Options which are exercisable under applicable provisions of the Plan)
may become exercisable in any one calendar year to purchase more than one-third
of the aggregate number of shares of Stock which may be issued under Options
granted under the Plan as provided in Paragraph V below (subject to adjustment
in the same manner as provided in Paragraph VIII hereof with respect to shares
of Stock subject to Options then outstanding). In selecting the Optionees from
among individuals eligible hereunder and in establishing the number of shares
that may be issued under each Option, the Committee may take into account the
nature of the services rendered by such individuals, their present and potential
contributions to the Company's success and such other factors as the Committee
in its discretion shall deem relevant. The Committee is authorized to interpret
the Plan and may from time to time adopt such rules and regulations, consistent
with the provisions of the Plan, as it may deem advisable to carry out the Plan.
All decisions made by the Committee in selecting the Optionees, in establishing
the number of shares which may be issued under each Option and in construing the
provisions of the Plan shall be final.
III. OPTION AGREEMENTS
Each Option shall be evidenced by a written agreement between the Company
and the Optionee ("Option Agreement") which shall contain such terms and
conditions as may be approved by the Committee. The terms and conditions of the
respective Option Agreements need not be identical. An Option Agreement may
provide for the payment of the option price, in whole or in part, by the
delivery of a number of shares of Stock (plus cash if necessary) having a fair
market value equal to such option price.
-1-
<PAGE>
For all purposes under the Plan, the fair market value of a share of Stock
on a particular date shall be equal to the mean of the high and low sales prices
of the Stock (i) reported by the National Market System of NASDAQ on that date
or (ii) if the Stock is listed on a national stock exchange, reported on the
stock exchange composite tape on that date; or, in either case, if no prices are
reported on that date, on the last preceding date on which such prices of the
Stock are so reported. If the Stock is traded over-the-counter at the time a
determination of its fair market value is required to be made hereunder, its
fair market value shall be deemed to be equal to the average between the
reported high and low bid prices of Stock on the most recent date on which Stock
was publicly traded. In the event Stock is not publicly traded at the time a
determination of its value is required to be made hereunder, the determination
of its fair market value shall be made by the Committee in such manner as it
deems appropriate.
Each Option and all rights granted thereunder shall not be transferable
other than by will or the laws of descent and distribution or pursuant to a
qualified domestic relations order as defined by the Code or Title I of the
Employee Retirement Income Security Act of 1974, as amended, or the rules
thereunder, and shall be exercisable during the Optionee's lifetime only by the
Optionee or the Optionee's guardian or legal representative.
IV. ELIGIBILITY OF OPTIONEE
Options may be granted only to individuals who are Directors or key
employees (including officers who are also key employees) of the Company or any
parent or subsidiary corporation (as defined in section 424 of the Code) of the
Company at the time the Option is granted. Options may be granted to the same
individual on more than one occasion.
V. SHARES SUBJECT TO THE PLAN
The aggregate number of shares which may be issued under Options granted
under the Plan shall not exceed in the aggregate 10% of the sum of (x) the
number or issued and outstanding shares of Stock plus (y) the number of shares
of Stock issuable upon conversion of outstanding shares of convertible preferred
stock of the Company. Such shares may consist of authorized but unissued shares
of Stock or previously issued shares of Stock reacquired by the Company. Any of
such shares which remain unissued and which are not subject to outstanding
Options at the termination of the Plan shall cease to be subject to the Plan,
but, until termination of the Plan, the Company shall at all times make
available a sufficient number of shares to meet the requirements of the Plan.
Should any Option hereunder expire or terminate prior to its exercise in full,
the shares theretofore subject to such Option may again be subject to an Option
granted under the Plan. The aggregate number of shares which may be issued under
the Plan shall be subject to adjustment in the same manner as provided in
Paragraph VIII hereof with respect to shares of Stock subject to Options then
outstanding. Exercise of an Option in any manner, including an exercise
involving a Stock Appreciation Right, shall result in a decrease in the number
of shares of Stock which may thereafter be available, both for purposes of the
Plan and for sale to any one individual, by the number of shares as to which the
Option is exercised.
VI. OPTION PRICE
The purchase price of Stock issued under each Option shall be determined
by the Committee, but such purchase price shall not be less than 85% of the fair
market value of Stock subject to the Option on the date the Option is granted.
-2-
<PAGE>
VII. TERM OF PLAN
The Plan shall be effective upon the date of its adoption by the Board.
Except with respect to Options then outstanding, if not sooner terminated under
the provisions of Paragraph IX, the Plan shall terminate upon and no further
Options shall be granted after the expiration of ten years from the date of its
adoption by the Board.
VIII. RECAPITALIZATION OR REORGANIZATION
(a) The existence of the Plan and the Options granted hereunder shall not
affect in any way the right or power of the Board or the shareholders of the
Company to make or authorize any adjustment, recapitalization, reorganization or
other change in the Company's capital structure or its business, any merger or
consolidation of the Company, any issue of debt or equity securities, the
dissolution or liquidation of the Company or any sale, lease, exchange or other
disposition of all or any part of its assets or business or any other corporate
act or proceeding.
(b) The shares with respect to which Options may be granted are shares of
Stock as presently constituted, but if, and whenever, prior to the expiration of
an Option theretofore granted, the Company shall effect a subdivision or
consolidation of shares of Stock or the payment of a stock dividend on Stock
without receipt of consideration by the Company, the number of shares of Stock
with respect to which such Option may thereafter be exercised (i) in the event
of an increase in the number of outstanding shares shall be proportionately
increased, and the purchase price per share shall be proportionately reduced,
and (ii) in the event of a reduction in the number of outstanding shares shall
be proportionately reduced, and the purchase price per share shall be
proportionately increased.
(c) If the Company recapitalizes, reclassifies its capital stock, or
otherwise changes its capital structure (a "recapitalization"), the number and
class of shares of Stock covered by an Option theretofore granted shall be
adjusted so that such Option shall thereafter cover the number and class of
shares of stock and securities to which the Optionee would have been entitled
pursuant to the terms of the recapitalization if, immediately prior to the
recapitalization, the Optionee had been the holder of record of the number of
shares of Stock then covered by such Option. If (i) the Company shall not be the
surviving entity in any merger, consolidation or other reorganization (or
survives only as a subsidiary of an entity other than a previously wholly-owned
subsidiary of the Company), (ii) the Company sells, leases or exchanges all or
substantially all of its assets to any other person or entity (other than a
wholly-owned subsidiary of the Company), (iii) the Company is to be dissolved
and liquidated, (iv) any person or entity, including a "group" as contemplated
by Section 13(d)(3) of the 1934 Act, acquires or gains ownership or control
(including, without limitation, power to vote) of more than 50% of the
outstanding shares of the Company's voting stock (based upon voting power), or
(v) as a result of or in connection with a contested election of directors, the
persons who were directors of the Company before such election shall cease to
constitute a majority of the Board (each such event is referred to herein as a
"Corporate Change"), no later than (a) ten days after the approval by the
shareholders of the Company of such merger, consolidation, reorganization, sale,
lease or exchange of assets or dissolution or such election of directors or (b)
thirty days after a change of control of the type described in Clause (iv), the
Committee, acting in its sole discretion without the consent or approval of any
Optionee, shall act to effect one or more of the following alternatives, which
may vary among individual Optionees and which may vary among Options held by any
individual Optionee: (1) accelerate the time at which Options then outstanding
may be exercised and waive any limitations set forth in or imposed by Paragraph
II so that such Options may be exercised in full for a limited period of time on
or before a specified date (before or after such Corporate Change) fixed by the
-3-
<PAGE>
Committee, after which specified date all unexercised Options and all rights of
Optionees thereunder shall terminate, (2) require the mandatory surrender to the
Company by selected Optionees of some or all of the outstanding Options held by
such Optionees (irrespective of whether such Options are then exercisable under
the provisions of the Plan) as of a date, before or after such Corporate Change,
specified by the Committee, in which event the Committee shall thereupon cancel
such Options and the Company shall pay to each Optionee an amount of cash per
share equal to the excess, if any, of the amount calculated in Subparagraph (d)
below (the "Change of Control Value") of the shares subject to such Option over
the exercise price(s) under such Options for such shares, (3) make such
adjustments to Options then outstanding as the Committee deems appropriate to
reflect such Corporate Change (provided, however, that the Committee may
determine in its sole discretion that no adjustment is necessary to Options then
outstanding) or (4) provide that the number and class of shares of Stock covered
by an Option theretofore granted shall be adjusted so that such Option shall
thereafter cover the number and class of shares of stock or other securities or
property (including, without limitation, cash) to which the Optionee would have
been entitled pursuant to the terms of the agreement of merger, consolidation or
sale of assets and dissolution if, immediately prior to such merger,
consolidation or sale of assets and dissolution, the Optionee had been the
holder of record of the number of shares of Stock then covered by such Option.
(d) For the purposes of clause (2) in Subparagraph (c) above, the "Change
of Control Value" shall equal the amount determined in clause (i), (ii) or
(iii), whichever is applicable, as follows: (i) the per share price offered to
shareholders of the Company in any such merger, consolidation, reorganization,
sale of assets or dissolution transaction, (ii) the price per share offered to
shareholders of the Company in any tender offer or exchange offer whereby a
Corporate Change takes place, or (iii) if such Corporate Change occurs other
than pursuant to a tender or exchange offer, the fair market value per share of
the shares into which such Options being surrendered are exercisable, as
determined by the Committee as of the date determined by the Committee to be the
date of cancellation and surrender of such Options. In the event that the
consideration offered to shareholders of the Company in any transaction
described in this Subparagraph (d) or Subparagraph (c) above consists of
anything other than cash, the Committee shall determine the fair cash equivalent
of the portion of the consideration offered which is other than cash.
(e) Any adjustment provided for in Subparagraphs (b) or (c) above shall be
subject to any required shareholder action.
(f) Except as hereinbefore expressly provided, the issuance by the Company
of shares of stock of any class or securities convertible into shares of stock
of any class, for cash, property, labor or services, upon direct sale, upon the
exercise of rights or warrants to subscribe therefor, or upon conversion of
shares or obligations of the Company convertible into such shares or other
securities, and in any case whether or not for fair value, shall not affect, and
no adjustment by reason thereof shall be made with respect to, the number of
shares of Stock subject to Options theretofore granted or the purchase price per
share.
IX. AMENDMENT OR TERMINATION OF THE PLAN
The Board in its discretion may terminate the Plan at any time with
respect to any shares for which Options have not theretofore been granted. The
Board shall have the right to alter or amend the Plan or any part thereof from
time to time; provided, that no change in any Option theretofore granted may be
made which would impair the rights of the Optionee without the consent of such
Optionee.
-4-
<PAGE>
X. COMPLIANCE WITH LAWS
The Company shall not be required to sell or issue any shares of Stock
under any Option if the issuance of such shares constitute a violation by the
Optionee or the Company of any provision of any law, statute, or regulation of
any governmental authority whether it be Federal or State. Specifically in
connection with the Securities Act of 1993 (as now in effect or hereafter
amended), upon exercise of any Option, unless a registration statement under
such Act is in effect with respect to the shares of Stock covered by such
Option, the Company shall not be required to issue such shares unless the
Committee has received evidence satisfactory to it to the effect that the holder
of such Option is acquiring such shares of Stock for investment and not with a
view to the distribution thereof and that such shares of Stock may otherwise be
issued without registration under such Act or state securities laws. Any
determination in this connection by the Committee shall be final, binding and
conclusive. The Company may, but shall in no event be obligated to, register any
securities covered hereby pursuant to the Securities Act of 1933 (as now in
effect or as hereafter amended). The Company shall not be obligated to take any
affirmative action in order to cause the exercise of an Option or the issuance
of shares pursuant thereto to comply with any law or regulation of any
governmental authority.
-5-
THIRD AMENDMENT TO
LOAN AGREEMENT DATED JANUARY 14, 1994
BY AND AMONG BLUE DOLPHIN ENERGY COMPANY,
BLUE DOLPHIN PIPE LINE COMPANY, BUCCANEER PIPE LINE CO.,
MISSION ENERGY, INC. D/B/A MEI MISSION ENERGY, INC.,
BLUE DOLPHIN EXPLORATION COMPANY, PREVIOUSLY KNOWN AS
IVORY PRODUCTION CO,. BLUE DOLPHIN SERVICES CO.,
AND BANK ONE, TEXAS, N.A.
THIS THIRD AMENDMENT TO LOAN AGREEMENT (this "AMENDMENT") is entered into
as of November 05, 1996, by and between BLUE DOLPHIN ENERGY COMPANY., BLUE
DOLPHIN PIPE LINE COMPANY, BUCCANEER PIPELINE CO., MISSION ENERGY, INC. D/B/A
MEI MISSION ENERGY, INC., BLUE DOLPHIN EXPLORATION COMPANY, PREVIOUSLY KNOWN AS
IVORY PRODUCTION CO., AND BLUE DOLPHIN SERVICES CO. ("collectively, the
Borrowers"), and BANK ONE, TEXAS, N.A., a NATIONAL ASSOCIATION ("BANK").
WHEREAS, Borrower and Bank entered into that certain Loan Agreement dated
as of January 14, 1994, as amended from time to time (collectively, the "LOAN
AGREEMENT"); and
WHEREAS, the Loan Agreement currently governs Borrower's revolving line of
credit in the maximum amount of $10,000,000.00 (the "LINE OF CREDIT"), as
currently evidenced by that certain promissory note dated January 14, 1994
payable by Borrower to the order of Bank in the stated principal amount of
$10,000,000.00 (the "NOTE"); and
WHEREAS, the Loan Agreement, the Note and all other documents evidencing,
securing, governing, guaranteeing and/or pertaining to the Note are hereinafter
referred to collectively as the "LOAN DOCUMENTS"; and
WHEREAS, the parties hereto now desire to modify the Loan Agreement as
hereinafter provided;
NOW, THEREFORE, in consideration of the mutual covenants, representations,
warranties, and agreements contained herein, and for other valuable
consideration, the receipt and legal sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:
<PAGE>
ARTICLE I
DEFINITIONS
Section 1.01 The terms used in this Amendment to the extent not otherwise
defined herein shall have the same meanings as in the Loan Agreement.
Section 1.02 Effective as of the date hereof the term "Termination Date" as
defined on page 10 of the loan agreement, shall mean January 14, 2000.
Section 1.03 Effective as of the date hereof the term "Bank One Base Rate "
as defined on page 2 shall mean the rate of interest per annum then most
recently established by the Bank, from time to time, as its Bank One Base Rate,
which is Eight and one- fourth percent (8.25) as of the date of this Agreement
Section 1.04 Effective as of the date hereof the term "Floating Rate" as
defined on page 4 of the Loan Agreement " shall mean the Bank One Base Rate in
effect from time to time plus one and one-fourth percent (1.25%)."
ARTICLE II
AMENDMENTS
Section 2.01 Effective as of the date hereof, The first sentence of Section
2.04 of the Loan Agreement is hereby amended in its entirety to read as follows:
"The Borrowing Base is hereby established at $1,925,000.00 effective
as of November 05, 1996, declining in the amount of $75,000.00 monthly,
beginning December 01, 1996, and at the beginning of each successive month
thereafter."
Section 2.02 Effective as of the date hereof, Paragraph 6.20 of the Loan
Agreement is hereby amended in its entirety to read as follows:
GENERAL AND ADMINISTRATIVE EXPENSEs:
"Maintain consolidated general and administrative expenses at a level
that is not greater than $1,500,000.00 for each of the Fiscal Years 1996
and 1997 ( effective January 01, 1996 ). Effective January 01, 1998 ( for
FY98 and thereafter ), modify the G & A expense to a maximum of 25% of
total oil & gas and pipeline, related revenues."
Section 2.03 Effective as of the date hereof, Paragraph 7.03
subsection (b) is amended by changing $400,000.00 for 1995 to $600,000.00
for 1996.
<PAGE>
Section 2.04 Effective as of the date hereof, Paragraph 7.14 is amended to
read:
CERTAIN CAPITAL EXPENDITURES
"Make any capital expenditures in 1996 for items other than the
Petroport project, offshore abandonment program and acquisitions costs
exceeding $600,000.00. Effective January 01, 1997 BDEC's Maximum capital
expenditures will be $250,000.00 for 1997 and each year thereafter."
ARTICLE III
WAIVERS
Section 3.01 This amendment will also serve as a waiver for the
noncompliance of the following covenants:
a. The G&A covenant from 12/31/95 through 9/30/96
b. The Capital Expenditure covenant violations from 3/31/96
through 9/30/96
ARTICLE IV
NOTE
4.01 Contemporaneously with the execution hereof, Borrower agrees to
execute and deliver to Bank a promissory note (the "RENEWAL NOTE") in the stated
principal amount of $10,000,000.00, in form and substance satisfactory to Bank,
in renewal and extension of the Note.
ARTICLE V
REPRESENTATIONS, WARRANTIES, RATIFICATION AND REAFFIRMATION
Section 5.01 Borrower hereby represents and warrants that: (i) the
representations and warranties contained in the Loan Agreement are true and
correct on and as of the date hereof as though made on and as of the date
hereof, (ii) no event has occurred and is continuing that constitutes an Event
of Default or would constitute an Event of Default but for the requirement of
<PAGE>
notice or lapse of time or both, and (iii) there are no claims or offsets
against, or defenses or counterclaims to, the Note, the indebtedness evidenced
thereby or the liens securing same (including without limitation, any defenses
or offsets resulting from or arising out of breach of contract or duty, the
amount of interest charged, collected or received on the Note heretofore, or
breach of any commitments or promises of any type).
Section 5.02 The terms and provisions set forth in this Amendment shall
modify and supersede all inconsistent terms and provisions set forth in the Loan
Agreement, but except as expressly modified and superseded by this Amendment,
the terms and provisions of the Loan Agreement are ratified and confirmed and
shall continue in full force and effect, Borrower hereby agreeing that the Loan
Agreement and the other Loan Documents are and shall continue to be outstanding,
validly existing and enforceable in accordance with their respective terms.
ARTICLE VI
MISCELLANEOUS
Section 6.01 Each of the Loan Documents is hereby amended so that any
reference in the Loan Documents to the Loan Agreement shall mean a reference to
the Loan Agreement as amended hereby.
Section 6.02 This Amendment may be executed simultaneously in one or more
counterparts, each of which shall be deemed an original, but all of which
together shall constitute one and the same instrument.
Section 6.03 This Amendment has been entered into in Harris County, Texas
and shall be performable for all purposes in Harris County, Texas. THIS
AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE
STATE OF TEXAS AND THE APPLICABLE LAWS OF THE UNITED STATES OF AMERICA. Courts
within the State of Texas shall have jurisdiction over any and all disputes
arising under or pertaining to this Amendment, and venue in any such dispute
shall be the courts located in Harris County, Texas.
Section 6.04 This Amendment shall be binding upon and inure to the benefit
of the parties hereto and their respective successors and assigns.
THE WRITTEN LOAN AGREEMENT REPRESENTS THE FINAL AGREEMENT BETWEEN THE PARTIES
AND MAY NOT BE CONTRADICTED BE EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT
ORAL AGREEMENTS OF THE PARTIES
THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
<PAGE>
EXECUTED as of the date first above written.
BORROWERS:
BLUE DOLPHIN ENERGY COMPANY.
By:________________________________
Name: Michael J. Jacobson
Title: President
BLUE DOLPHIN PIPE LINE COMPANY
By:________________________________
Name: Michael J. Jacobson
Title: President
BUCCANEER PIPE LINE CO.
By:________________________________
Name: Michael J. Jacobson
Title: President
MISSION ENERGY, INC. D/B/A
MEI MISSION ENERGY INC.
By:________________________________
Name: Michael J. Jacobson
Title: President
BLUE DOLPHIN EXPLORATION
COMPANY PREVIOUSLY KNOWN AS
IVORY PRODUCTION CO.
By:________________________________
Name: Michael J. Jacobson
Title: President
<PAGE>
BLUE DOLPHIN SERVICES CO.
By: __________________________
Name: Michael J. Jacobson
Title: President
BANK:
BANK ONE, TEXAS, NATIONAL
ASSOCIATION
By:________________________________
Name: Jeffrey W. Baker
Title:Vice President
GERALD DUPONT ENTERPRISES, INC.
PETROLEUM ENGINEER
P.O. BOX 1590
SUGAR LAND, TEXAS 77487-1590
(713)240-2822 FAX (713)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
interest owned by Blue Dolphin Energy Company in the Galveston Block 288 Field,
dated December 31 1996, included in the Annual Report on Form 10-K of Blue
Dolphin Energy Company for the year ended December 31, 1996.
Petroleum Engineer
Date: FEBRUARY 18, 1997
<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>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 1,207,323
<SECURITIES> 0
<RECEIVABLES> 744,283
<ALLOWANCES> 0
<INVENTORY> 28,460
<CURRENT-ASSETS> 2,050,406
<PP&E> 25,163,290
<DEPRECIATION> 4,535,945
<TOTAL-ASSETS> 24,226,611
<CURRENT-LIABILITIES> 1,133,293
<BONDS> 2,060,600
0
0
<COMMON> 667,691
<OTHER-SE> 18,935,878
<TOTAL-LIABILITY-AND-EQUITY> 24,226,611
<SALES> 378,266
<TOTAL-REVENUES> 4,128,568
<CGS> 1,320,485
<TOTAL-COSTS> 4,080,129
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 16,790
<INCOME-PRETAX> 155,091
<INCOME-TAX> 42,214
<INCOME-CONTINUING> 112,877
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (178,327)
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
