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, 1998
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from to
Commission file Number: 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 73-1268729
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
801 Travis, Suite 2100, Houston, Texas 77002 (Address of
principal executive office) (Zip Code)
Registrant's telephone number, including area code: (713) 227-7660
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock $.01 par value
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.[X]
The aggregate market value (estimated solely for purposes of this
calculation) of the voting stock held by non-affiliates of the registrant as of
March 2, 1999, was approximately $11,419,230.
As of March 2, 1999, there were outstanding 4,504,627 shares of Common
Stock, par value $.01 per share, of the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
The registrant's definitive proxy statement for the 1999 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 gathering
and transportation of natural gas and condensate, exploration and acquisition of
oil and gas properties, and development of an offshore terminal and storage
facility to handle 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
("BDEX"), a Delaware corporation, Mission Energy, Inc., a Delaware corporation
d/b/a MEI Mission Energy, Inc. ("MEI"), Blue Dolphin Pipe Line Company ("BDPC"),
a Delaware corporation, Buccaneer Pipe Line Co. ("BPC"), a Texas corporation,
Blue Dolphin Services Co., a Texas corporation, Petroport, Inc.("Petroport"), a
Delaware corporation, Black Marlin Energy Company, a Delaware corporation and
Black Marlin Pipeline Company ("BMPC"), a Texas Corporation.
The principal executive office of the Company is located at 801 Travis,
Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660. Shore base
facilities are maintained in Freeport and Texas City, Texas serving Gulf of
Mexico operations. The Company has 20 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," "plan," "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 publish revised forward-looking statements to
reflect events or circumstances after the date hereof or to reflect the
occurrence of unanticipated events. Readers are also urged to carefully review
and consider the various disclosures made by the Company which attempt to advise
interested parties of the factors which affect the Company's business, including
the disclosures made under the caption "Management's Discussion and Analysis of
Financial Condition and Results of
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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.
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 condensate pipeline gathering facilities. The Company's oil and
gas exploration and production activities include the exploration, acquisition,
development, operation and, when appropriate, disposition of oil and gas
properties. The Company also develops for sale to third parties, oil and gas
exploration prospects in the Gulf of Mexico. See Note 12 to Consolidated
Financial Statements of Blue Dolphin Energy Company and Subsidiaries included in
Item 8 and incorporated herein by reference for information relating to
revenues, operating profit or loss and identifiable assets of the Company's
business segments. The Company has 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.
PIPELINE OPERATIONS AND ACTIVITIES
The Company's pipeline assets are held and operations conducted by BDPC,
MEI, BPC, and BMPC all wholly owned subsidiaries of the Company.
On March 1, 1999 the Company acquired Black Marlin Pipeline Company from
Enron Pipeline Company ("Enron"), for $5,404,270 cash. Black Marlin Pipeline
Company is the owner of the 75 mile Black Marlin Pipeline System, as defined
below. This acquisition was funded by selling a one-sixth (1/6) undivided
interest in the Company's Blue Dolphin Pipeline System, the Black Marlin
Pipeline System and the Omega Pipeline to WBI Southern, Inc. ("WBI") for
$3,713,000 and selling a one-third (1/3) undivided interest in the Black Marlin
Pipeline System to MCNIC Pipeline Processing Company ("MCNIC") for $1,801,423.
MCNIC owns a one-third (1/3) undivided interest in the Blue Dolphin Pipeline
System.
The Company owns a 50% undivided interest (subsequent to the above
mentioned transaction) in the Blue Dolphin Pipeline System (the "Blue Dolphin
System") and the Black Marlin Pipeline System (the "Black Marlin System"). The
Blue Dolphin System includes the Blue Dolphin Pipeline, Buccaneer Pipeline,
onshore facilities for condensate and gas separation and dehydration, 85,000
barrels ("Bbls") of above-ground tankage for storage of condensate, a barge
loading terminal on the Intracoastal Waterway and 360 acres of land in Brazoria
County, Texas where the Blue Dolphin Pipeline comes ashore and on which are
located the pipeline system shore facilities, pipeline easements and
rights-of-way.
The Blue Dolphin System gathers and transports natural gas and condensate
from the Buccaneer Field and other offshore fields in the area to shore
facilities located in Freeport, Texas. After processing, the gas is transported
to an end user and a major intrastate pipeline system with further downstream
tie-ins to other intrastate and interstate pipeline systems and end-users. The
Buccaneer Pipeline, an 8" condensate pipeline, transports condensate from the
storage tanks to the Company's barge loading terminal on the Intracoastal
Waterway near Freeport, Texas for sale to third parties.
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The Blue Dolphin Pipeline consists of two separate segments. The offshore
segment transports both natural gas and condensate and is comprised of
approximately 36 miles of 20-inch pipeline from the Buccaneer Field platforms to
shore and 4 miles to the shore facility at Freeport, Texas. Additionally, the
offshore segment includes five field gathering lines totalling 37.5 miles,
connected to the main 20-inch line. The field gathering lines were acquired in
the last four years. Addition of these field gathering 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 shore facility services. Blue Dolphin System throughput
averaged approximately 43% of capacity during 1998. Current System capacity is
approximately 160 million cubic feet ("MMcf") per day of gas and 7,000 Bbls per
day of condensate. During 1998, 99% of gas volumes transported and 99.4% of
condensate volumes transported were attributable to production from third party
producer/shippers. See Note 12 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated
herein by reference.
The Black Marlin System includes the Black Marlin Pipeline, onshore
facilities for condensate and gas separation and dehydration, 3,000 Bbls of
above ground tankage for storage of condensate, a truck loading facility for oil
and condensate, and 5 acres of land in Galveston County, Texas where the Black
Marlin Pipeline comes ashore and on which are located the pipeline system's
shore facilities.
BMPC is classified as a "natural gas company" pursuant to the Natural Gas
Act of 1938 ("NGA") and the Black Marlin Pipeline is classified as an
"interstate pipeline" pursuant to the Natural Gas Policy Act of 1978 ("NGPA")
and thus subject to the Federal Energy Regulatory Commission ("FERC")
regulation. Gas and condensate from various producer/shippers in the High Island
and Galveston Areas of the Gulf of Mexico are gathered and transported through
the Black Marlin Pipeline to its shore facilities. After separation and
dehydration, gas is transported to an industrial end-user or to either of two
major intrastate pipeline systems with further downstream tie-ins to other
intrastate and interstate pipeline systems and end-users. Condensate is either
delivered to a liquids pipeline or transported by truck.
The Black Marlin Pipeline consists of two segments. The offshore segment
transports natural gas and condensate and is comprised of approximately 67 miles
of 16-inch pipeline from a High Island Block 136 platform including an extension
from a platform in High Island Block A-6 to an interconnection in High Island
Block 137, extending across Galveston Bay to the onshore facilities at Texas
City, Texas. The offshore segment also includes approximately 7 miles of 8-inch
pipeline from a platform in High Island Block 199 to an interconnection to the
main line High Island Block 171. The onshore segment consists of approximately 2
miles of 16-inch pipeline from the shore facilities to various end users and
pipeline system tie-ins.
The Company also holds a five-sixths (5/6) undivided interest in the
currently inactive Omega Pipeline, WBI holds the other one-sixth (1/6) interest.
The Omega Pipeline is located in West Cameron Block 342 extending to High
Island, East Addition Block A-173, where it was previously connected to the High
Island Offshore System ("HIOS"). It could either be reconnected to HIOS, or a
lateral pipeline could be constructed connecting into the Black Marlin Pipeline
approximately 14 miles to the west. Utilization of the Omega Pipeline is
dependent upon drilling activity around it and successfully attracting such
discoveries to the system.
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The economic return to the Company on its pipeline system investments are
solely dependent upon the amounts of gas and condensate gathered and transported
through the pipeline systems. Competition for provision of gathering and
transportation services, similar to those provided by the Company, is intense in
the market areas served by the Company. See Competition, Markets and Regulation
- - Competition below. Since contracts for provision of such services between the
Company and third party producer/shippers are generally for a specified time
period, there can be no assurance that current or future producer/shippers will
not subsequently tie-in to alternative transportation systems or that current
rates charged by the Company will be maintained in the future.
The Company actively markets gathering and transportation services to
prospective third party producer/shippers in the vicinity of its pipeline
systems. Future utilization of the pipelines and related facilities will depend
upon the success of drilling programs around the pipelines, and attraction, and
retention, of producer/shippers to the systems.
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
The Company's oil and gas assets are held, and operations conducted by,
BDEX, a wholly-owned subsidiary.
The following is a description of the Company's major oil and gas
exploration and production assets and activities:
THE BUCCANEER FIELD. The Buccaneer Field is comprised of interests in parts
of four lease blocks covering 14,660 acres located in the Gulf of Mexico
approximately 36 miles south of Freeport, Texas. Operation of the field is
conducted from two platforms located in waters averaging approximately 65 feet
in depth.
The Company owns a 100% working interest in the Buccaneer Field (81.33% net
revenue interest). 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, 1998. 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, 1998, 1997 and 1996.
See "Proved Oil and Gas Reserves" below.
Buccaneer Field condensate and natural gas production is delivered to the
Blue Dolphin 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 1999 at
a fixed monthly price of $2.08/MMBtu, which price has been received since
October 1997. Buccaneer Field gas sales represented 95% of oil and gas sales
revenues and 11% of total revenues of the Company for the year ended December
31, 1998.
Buccaneer Field condensate sales are based on spot market monthly average
prices. Sale of condensate from the Buccaneer Field represented 5% of oil and
gas sales revenues and 0.6% of total revenues of the Company for the year ended
December 31, 1998.
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The U. S. Department of the Interior, Minerals Management Service ("MMS")
requires that security is provided for the estimated future abandonment
obligations associated with the Buccaneer Field. BDEX provides the MMS surety
bonds in the amount of $1,300,000. Additionally, a sinking fund is provided
wherein $250,000 annually is set aside until a total of approximately $2,400,000
has been accumulated to meet end of lease abandonment and site clearance
obligations. As of December 31, 1998, the sinking fund totalled approximately
$1,117,500. The Company estimates the remaining life of its major Buccaneer
Field facilities to be in excess of ten years.
In addition to conducting traditional oil and gas production operations for
itself, the Company operates and maintains oil and gas production facilities for
third party producers who also utilize the Blue Dolphin System for gathering and
transportation of their production. Currently, such contract operation and
maintenance services are provided to one third party producer/shipper. During
1998, revenues attributable to provision of contract operation and maintenance
services represented 10% of the Company's total revenues.
OFFSHORE OIL AND GAS PROSPECT GENERATION ACTIVITIES. In August 1994, BDEX
initiated a program to develop oil and gas exploration prospects in the Gulf of
Mexico for sale to third parties. The program utilizes the latest in 3-D seismic
processing technology. The Company has access to 3-D seismic data for over
2,000,000 acres, primarily in the western Gulf of Mexico, and over 200,000 line
miles of close grid 2-D seismic data. In addition to recovering prospect
development costs, BDEX will retain a reversionary working interest in each
drillable prospect. The Company acquired four lease blocks in the High Island
Area of the Gulf of Mexico in the September 1995 Federal Western Gulf of Mexico
lease sale. One prospective lease block was sold in 1996 and an unsuccessful
well was drilled and has been plugged and abandoned. Another prospective lease
block was sold in 1997 and an unsuccessful well was drilled in 1998 and has been
plugged and abandoned. A 43.75% interest in each of the two remaining
prospective lease blocks has been sold. Efforts to sell the remaining interests
in each block are ongoing. However, no assurance can be given that the Company
will be successful in its sales efforts, and if successful, that the lease
blocks will be successfully drilled, or that commercial quantities of oil and
gas will be found.
In September 1997, the Company entered into an agreement with industry
participants, whereby in exchange for certain participation rights, the
participants partially funded the costs associated with the Company's 1997/1998
offshore prospect generation program. The remaining program costs were
reimbursed to the Company as prospects were developed and leases acquired. At
the August 26, 1998 western Gulf of Mexico federal lease sale, the participants
acquired one lease block. In addition, the Company, along with certain of the
participants, submitted a successful bid on another lease block. The initial
program with these partners terminated August 31, 1998.
In order to enhance the productivity of the prospect generation program,
during 1998 the Company transitioned from the use of consulting geologists and
geophysicists to a 100% in house effort. A highly experienced team of geologists
and geophysicists, utilizing state of the art work stations, has been assembled.
The Company currently is seeking participants for available interests in its
1998/1999 program. Additionally, funding is being sought which would permit the
Company to directly participate as a working interest owner in and be designated
operator for prospects generated. At this time the Company has placed 50% of the
available interest in the 1998/1999 program.
OTHER. In the first quarter 1998, the Company drilled an unsuccessful well
on its Embar Field acreage in west Texas. The Company has terminated the farmin
and lease option agreement covering the acreage following reevaluation of the
risks of future drilling in light of the outcome of the initial well.
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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, 1998, 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, 1998, using the SEC Method (defined below).
PROVED RESERVES INFORMATION
AS OF DECEMBER 31, 1998
Future Discounted
Net Oil Net Gas Net Future Net
Reserves Reserves Revenues Revenues (3)
Buccaneer Field: (MB) (MMCF) ($000) ($000)
-------- -------- -------- ------------
Proved Reserves (1) ............. 189 31,195 $ 25,420 $ 6,184
======== ======== ======== ============
Proved Developed Reserves (2) ... 113 18,071 $ 18,503 $ 5,181
======== ======== ======== ============
MB = Thousand Barrels MMCF = Million Cubic Feet
(1) "Proved Reserves" means the estimated quantities of oil, natural gas and
condensate which geological and engineering data demonstrate with
reasonable certainty to be recoverable by primary producing mechanisms in
future years from known reservoirs under existing economic and operating
conditions.
(2) "Proved Developed Reserves" are those quantities of oil, natural gas and
condensate which are expected to be recovered through existing wells with
existing equipment and operating methods.
(3) The estimated future net revenues before deductions for income taxes from
the Company's Proved Reserves have been determined and discounted at a 10%
annual rate in accordance with requirements for reporting oil and gas
reserves pursuant to regulations promulgated by the United States
Securities and Exchange Commission (the "SEC Method"). See estimated future
net revenues after deductions for income taxes in Note 13 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.
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The reserves and future net revenues summarized above reflect capital
expenditures totalling $206,000 and $250,000 in the years ending December 31,
1999, and 2002, respectively. Management will continue to evaluate its capital
expenditure program based on, among other things, demand and prices obtainable
for the Company's production. The availability of capital resources may affect
the Company's timing for further development of the Buccaneer Field, and there
can be no assurance that the timing of the development of such reserves will be
as currently planned.
The discounted present value of estimated future net revenues attributable
to Proved Reserves has been prepared in accordance with the SEC Method after
deduction of royalties and other third-party interests, lease operating
expenses, and estimated production, development, workover and recompletion
costs, but before deduction of income taxes, general and administrative costs,
debt service and depletion and amortization. Estimated future net revenues are
based on prices of oil and gas in effect at the end of the year without
escalation except to the extent contractually committed. Lease operating
expenses, and production and development costs, were estimated based on such
costs in effect at the end of the year, assuming the continuation of existing
economic conditions and without adjustment for inflation or other factors. The
present value of estimated future net revenues is computed by discounting future
net revenues at a rate of 10% per annum. Revenues from wells not currently
producing are included at the time they are expected to be placed into
production based upon estimates of future development; workover and recompletion
costs are included at the time they are expected to be incurred. Of the
Company's total Proved Developed Reserves, 7% of its estimated gas reserves and
6% of its estimated oil reserves were being produced at December 31, 1998.
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 13 - 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, 1998.
ACREAGE AND WELLS
<TABLE>
<CAPTION>
Productive Wells (1) Developed Undeveloped
--------------------------------- --------------- ---------------
Gross Net Acres (1) Acres (1)
--------------- --------------- --------------- ---------------
OIL GAS OIL GAS GROSS NET GROSS NET
------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Buccaneer Field 0 1 0 1 8,730 8,730 5,930 5,930
Other ......... 0 0 0 0 0 0 5,760 1,728
------ ------ ------ ------ ------ ------ ------ ------
0 1 0 1 8,730 8,730 11,690 7,658
====== ====== ====== ====== ====== ====== ====== ======
</TABLE>
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(1) "Productive wells" are producing wells and wells capable of production,
and include gas wells awaiting pipeline connections or necessary
governmental certifications to commence deliveries and oil wells to be
connected to production facilities. "Developed acres" include all acreage
as to which proved reserves are attributed, whether or not currently
producing, but exclude all producing acreage as to which the Company's
interest is limited to royalty, overriding royalty, and other similar
interests. "Undeveloped acres" are considered to be those acres on which
wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas regardless of whether
such acreage contains Proved Reserves. "Gross" as it applies to wells or
acreage refers to the number of wells or acres in which a working
interest is owned, while "net" applies to the sum of the fractional
working interests in gross wells or acreage.
PRODUCTION, PRICE AND COST DATA. The following table sets forth the
approximate production volumes and revenues, average sales prices and costs
(after deduction of royalties and interests of others) with respect to crude
oil, condensate, and natural gas attributable to the interest of the Company for
each of the periods indicated:
NET PRODUCTION, PRICE AND COST DATA
Year Ended December 31,
---------------------------------------
1998 1997 1996
----------- ----------- -----------
Gas:
Production
(Mcf) .......................... 177,260 176,986 180,269
Revenue ........................ $ 391,913 $ 393,444 $ 342,119
Average Mcf per Day ............ 485.6 484.9 492.5
Average Sales
Price
per
Mcf ............................ $ 2.21 $ 2.22 $ 1.90
Oil:
Production
(Bbls) ......................... 1,628 1,156 1,887
Revenue (1) .................... $ 20,840 $ 21,636 $ 36,147
Average Bbls per day ........... 4.5 3.2 5.2
Average Sales Price
per Bbl ..................... $ 12.80 $ 18.72 $ 19.16
Production Costs:
Per Equivalent Mcf (2): ........ $ 3.30 $ 4.16 $ 3.42
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(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.
DRILLING ACTIVITY. There were two unsuccessful exploratory wells drilled in
1998, including one on a prospect generated and sold to third parties by the
Company. There was no drilling activity during 1997. One unsuccessful
exploratory well was drilled in 1996 on a prospect generated and sold to third
parties by the Company.
The Company maintains a professional staff capable of supervising and
coordinating the operation and administration of its oil and gas properties and
pipeline and other assets. From time to time, major maintenance and engineering
design and construction projects are contracted to third-party engineering and
service companies.
DEVELOPMENT OF A DEEPWATER TERMINAL AND OFFSHORE STORAGE FACILITY
The Company's investment in and development of a deepwater crude oil and
refined products terminal and offshore storage facility is through Petroport.
In March 1995, the Company acquired Petroport, L.C. The form of the
transaction was a merger of Petroport, L.C. into Petroport. Petroport holds
proprietary technology, represented by certain patents issued and or pending,
associated with the development and operation of a deepwater crude oil and
products port and offshore storage facility. The Petroport deepwater terminal
and offshore storage facility will receive and store crude oil and refined
products offshore with deliveries to shore by pipeline. Onshore the Petroport
pipeline will connect with the existing onshore distribution network, accessing
Texas Gulf coast and Mid-Continent refining centers.
Development of the Petroport deepwater terminal and offshore storage
facility continues to proceed as anticipated. The design, engineering, costing
and overall facility commercial evaluation have been completed, with favorable
results. The Company is now seeking partners to fund the next phase of facility
development - site evaluation and licensing of the facility by federal and state
authorities.
The facility, combining multiple vessel and pipeline receipt and storage
capability, will be located 45 miles off the Texas coast in approximately 120
feet of water. The state-of-the-art design incorporates leached caverns in a
subsea salt dome for the storage of crude oil and refined products. Three single
point mooring buoys will enable off-loading of two vessels simultaneously. The
design capacity of the pipeline to shore will be 1.25 million barrels per day.
Initial storage capacity will be 31 million barrels, and can be increased if
market demand warrants.
Petroport will offer an efficient and cost effective alternative for
receipt of large volumes of imported crude oil. The Company believes Petroport's
commercial success will be driven primarily by economies of scale derived from
use of larger fully loaded tankers discharging short haul cargoes from exporting
locations such as Venezuela and Mexico into Petroport, and efficiencies gained
by supertankers discharging intermediate and long haul West African, North Sea,
and Persian Gulf crudes directly into Petroport versus current use of lightering
operations.
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Petroport will also be available to serve producers in the western Gulf of
Mexico. It can serve as a major gathering hub and truckline to shore, with OCS
crude received by either pipeline, or vessel from a floating production storage
and offloading system.
Petroport's future business environment is expected to be characterized by
a continuing significant requirement by refiners for imports, with use of short
haul Caribbean Basin crudes as the dominant source of foreign crude.
Transportation savings afforded by Petroport, combined with the Texas Gulf coast
and Mid-Continent market demand for imported crude will, the Company believes,
provide a sound and strong outlook for Petroport.
Cost of the offshore terminal, main oil pipeline to shore, and its onshore
support facilities is estimated to be $527 million. The Company expects to
submit the Petroport deepwater port license application and associated permit
requests in 1999, with operations planned to commence in the year 2002. See Item
7, Management Discussion and Analysis of Financial Conditions and Results of
Operations, discussing the financing plans for Petroport.
COMPETITION, MARKETS AND REGULATION
COMPETITION
The oil and gas industry is highly competitive in all segments.
Increasingly vigorous competition occurs among oil, gas and other energy
sources, and between producers, transporters, and distributors of oil and gas.
Competition is particularly intense with respect to the acquisition of desirable
producing properties and the marketing of oil and gas production. There is also
competition for the acquisition of oil and gas leases suitable for exploration
and for the hiring of experienced personnel to manage and operate the Company's
assets. Several highly competitive alternative transportation and delivery
options exist for current and potential customers of the Company's traditional
gas and oil gathering and transportation business as well as for refiners,
shippers, marketers and producers of crude oil whom the Company's proposed
Petroport facility would serve. Competition also exists with other industries in
supplying the energy and fuel needs of consumers.
MARKETS
The availability of a ready market for natural gas and oil, and the prices
of such natural gas and oil, depend upon a number of factors which are beyond
the control of the Company. These include, among other things, the level of
domestic production, the location availability of imported oil and gas, actions
taken by foreign oil and gas producing nations, the availability of pipelines
with adequate capacity, the availability of vessels for lightering and
transshipment and other means of transportation and facilities, the availability
and marketing of other competitive fuels, fluctuating and seasonal demand for
oil, gas and refined products, and the extent of governmental regulation and
taxation (under both present and future legislation) of the production,
importation, refining, transportation, pricing, use and allocation of oil,
natural gas, refined products and alternative fuels.
Accordingly, in view of the many uncertainties affecting the supply and
demand for crude oil, natural gas and refined petroleum products, it is not
possible to predict accurately the prices or
11
<PAGE>
marketability of the natural gas and oil produced for sale or prices chargeable
for transportation, terminaling and storage services, which the Company provides
or may provide in the future.
GOVERNMENTAL REGULATION
The production, processing, marketing and transportation of oil and natural
gas and planned terminaling and storage of crude oil by the Company are subject
to federal, state and local regulations which can have a significant impact upon
the Company's overall operations.
FEDERAL REGULATION OF NATURAL GAS TRANSPORTATION. Under the NGA and to a
lesser extent the NGPA, the FERC has authority to regulate the transportation
and resale of natural gas in interstate commerce. Although the FERC is
increasingly employing "light-handed" regulation, regulation remains an
important factor in the natural gas industry. In 1998, FERC issued additional
far-reaching proposals that would increase the trend toward market-based pricing
of pipeline transportation services, fundamentally changing rate and service
regulation of interstate natural gas pipeline companies. These proposed changes
remain under consideration, awaiting comment from interested parties.
As a regulated interstate pipeline, Black Marlin Pipeline is directly
affected by Natural Gas Act requirements governing the pricing and nature of
interstate transportation of natural gas. While FERC restructuring of the gas
industry has not directly affected the activities of the Company's
nonjurisdictional pipelines, it may have an indirect effect because of its broad
scope. In particular, aspects of FERC rate regulation may be used to bolster the
relative position of regulated pipelines competing to attract production in the
vicinity of the Company's gas pipeline facilities.
The Company cannot predict accurately how such developments in the
above-described laws and regulations, or future laws and regulations, will
affect its operations.
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.
FEDERAL REGULATION OF NATURAL GAS PIPELINES. Of the natural gas pipelines
owned by the Company, only Black Marlin is subject to Natural Gas Act
regulation. As a result, its gas transportation pricing and its transportation
service are regulated by the Federal Energy Regulatory Commission. Although
Black Marlin Pipeline has just successfully completed a FERC rate case and thus
can expect some rate stability, the trend toward greater competition among gas
pipelines subject to Natural Gas Act regulation is continuing. Additionally,
requirements of the Gas Industry Standards Board ("GISB") continue to evolve,
and may impose additional obligations and costs upon interstate pipelines
subject to these GISB standards.
All of the Company's pipelines located in federal offshore waters, whether
subject to Natural Gas Act jurisdiction or exempted as nonjurisdictional
gathering, are subject to the requirements of the Outer Continental Sheld Lands
Act ("OCSLA"). FERC has stated that nonjurisdictional gathering lines, as well
as interstate pipelines, are fully subject to the open access and
nondiscriminatory requirements of OCSLA's Section 5, which generally authorizes
the FERC to insure that natural gas pipelines on the OCS will transport for
non-owner shippers in a nondiscriminatory manner and will be operated in
accordance with certain pro-competitive principles. More recently, the FERC has
undertaken several investigations into the nature and extent of its regulatory
powers on the Outer Continental Shelf. It
12
<PAGE>
issued a policy statement on OCS pipelines reaffirming the requirement that all
pipelines provide nondiscriminatory service, and currently pending complaints
against nonjurisdictional gathering facilities under the OCSLA seek more
stringent FERC regulation of service and pricing.
Further FERC initiatives concerning possibly diminished Natural Gas Act
regulation of pipelines on the OCS and/or broader regulation under the OCSLA are
under consideration. Since all of the Companies' offshore pipelines already
operates on the basis required under OCSLA, the Company does not anticipate
significant changes directly resulting from requirements concerning
nondiscriminatory open access transportation. Moreover, if, an offshore
pipeline's throughput increases to the extent that the pipeline's capacity is
completely utilized, under OCSLA, the FERC may be petitioned to direct capacity
allocation on the pipeline. Accordingly, the Company cannot predict how
application of the OCSLA to the Companies' pipelines may ultimately affect
Company operations.
Aside from OCSLA requirements and federal safety and operational
regulations, regulation of natural gas gathering activities is primarily a
matter of state oversight. Regulation of gathering activities in Texas includes
various transportation, safety, environmental and non-discriminatory
purchase/transport requirements.
FEDERAL REGULATION OF OIL PIPELINES. The Company's operation of the
Buccaneer Pipeline is subject to a variety of regulations promulgated by the
FERC and imposed on all oil pipelines pursuant to federal law. In particular,
the rates chargeable by the Company are subject to prior approval by the FERC,
as are operating conditions and related matters contained in the Company's
transportation tariffs which are on file with the FERC. In October 1993, the
FERC issued Order No. 561, which was intended to simplify oil pipeline
ratemaking, largely through use of a ceiling based on an indexing system.
Because Buccaneer Pipeline has not taken action to become subject to Order No.
561 or Order No. 572 concerning market-based rates for oil pipelines, the
Company cannot predict whether or how an indexed or market-based rate system
will affect the Buccaneer Pipeline's rates.
REGULATION OF DEEPWATER PORTS: PERMITTING AND LICENSING. The ownership,
construction and operation of a deepwater crude oil terminal and storage
facility (a "Deepwater Port"), such as the Company's proposed Petroport
facility, must conform to the requirements of a number of Federal, State and
local laws. A license from the Department of Transportation ("DOT") is required
under the Deepwater Port Act of 1974 ("DWPA"), as amended. Permits from the
Environmental Protection Agency and the Federal Communication Commission are
required, as well as permits from the U.S. Army Corps of Engineers and the State
of Texas to construct ancillary port facilities, such as pipelines and onshore
facilities.
The DWPA empowers the Secretary of Transportation to license and regulate
Deepwater Ports beyond the territorial sea of the United States. License
applications must include sufficient information to allow the Secretary of
Transportation to judge whether the Deepwater Port will comply with all
technical, environmental, and economic criteria. The application and licensing
process includes the preparation of an Environmental Impact Statement,
development of detailed operations procedures, submission of extensive financial
and ownership data and public hearings.
The Company was a principal participant in the development and passage of
The Deepwater Port Modernization Act, successfully amending the DWPA. Among
other changes to the 1974 Act, amendments to the DWPA adopted in 1996 provide:
(1) upon written request of an applicant for a license, the Secretary may exempt
the applicant from certain of the informational filing requirements if the
Secretary determines such information is not necessary to facilitate his or her
determination and such
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<PAGE>
exemption will not limit public review; (2) the facility is explicitly permitted
to receive domestic production from the United States Outer Continental Shelf;
(3) simplification and streamlining of the regulatory process to which the
facility would be subject during both the licensing process and when in
operation; and (4) elimination of various facility use restrictions. Once a
license is issued, the law states that it remains in effect unless suspended or
revoked by the Secretary of Transportation or is surrendered by the licensee.
Regulations provide for extensive consultation among all interested Federal
agencies, any potentially affected coastal State, and the general public.
Adjacent coastal States are granted an effective veto power or reservation over
proposed Deepwater Ports. Under the statute, if a Governor of an adjacent
coastal State notifies the Secretary of Transportation that a proposal is
inconsistent with the State programs relating to environmental protection, land
and water use, and coastal zone management, then the Secretary of DOT shall
grant the license on the condition that the proposal is made consistent with
such State programs. Governors may also reject proposed Deepwater Ports on other
grounds.
In addition, the DWPA requires all Deepwater Ports including related
storage facilities be operated as common carriers, unless the licensee is
subject to "effective competition".
Given the nature and complexity of obtaining the necessary license and
permits, there can be no assurance that the Company will be issued a Deepwater
Port license and other necessary permits.
LIMITS OF LIABILITY AND CERTIFICATE OF FINANCIAL RESPONSIBILITY
REQUIREMENTS FOR DEEPWATER PORTS. In February 1995, DOT published a Notice of
Proposed Rulemaking under the Oil Pollution Act of 1990 ("OPA 90"), which among
other things, would have resulted in a limit of liability for Petroport under
OPA 90 and required Petroport to provide a Certificate of Financial
Responsibility ("COFR") before a license under DWPA would be issued, of
$350,000,000. The limit of liability and associated COFR could be reduced by the
Secretary of DOT to as low as $50,000,000, through a separate rulemaking
procedure, if the results of a study evaluating a Deepwater Port's risks,
including spill history (meaning the facility must be up and running), warranted
a limit reduction.
In August 1995, the DOT issued its' final rule which provides that the
Secretary, through a separate rulemaking, can set the limit of liability/COFR
for future Deepwater Ports (i.e., Petroport) concurrent with the overall
processing of the license application, as opposed to after the facility is up
and running. The development of the liability limit would be based upon
engineering and environmental analyses provided in the licensing process. The
uncertainty as to what the reduced limit of liability 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 2,215 barrels.
This compares to a credible worst case spill of 5,194 barrels as calculated by
DOT for the Louisiana Offshore Oil Port ("LOOP"). LOOP is the only existing
Deepwater Port licensed under the DWPA. The number of barrels as determined by
DOT in the Oil Spill Risk Analysis for LOOP, was multiplied by the maximum cost
per barrel for cleanup of a barrel of oil of $11,965, also as determined by DOT,
resulting in a reduced liability limit of $62,000,000 for LOOP. Per the
Company's analysis, if DOT applied this same methodology in determining
Petroport's credible worst case spill liability, a $50,000,000 liability limit
(the minimum allowable by statute) would be established for Petroport.
14
<PAGE>
The Petroport oil spill analysis was formally presented to DOT in November
1995, along with a request that DOT provide Petroport with a letter or
memorandum of understanding stating that DOT (1) has reviewed the Petroport oil
spill risk analysis and found the methodology to be valid; (2) intends to use
that methodology for analyzing the risk Petroport would pose when the final
specific operation and other relevant information are received through the
licensing process; (3) will apply the same calculation employed in the final
rulemaking issued by DOT on August 4, 1995 on "Limit of Liability for Deepwater
Ports" for LOOP, to determine Petroport's "maximum credible spill liability"
(multiplying the maximum credible spill by the unit spill cost); and (4) will
use $11,965 (escalated by the CPI) per barrel as the unit spill cost in making
the calculation.
Such a letter or memorandum of understanding would enable Petroport to
satisfy, to a significant degree, the uncertainty of prospective customers and
investors regarding (1) the environmental risk posed by using the Petroport
facility, (2) the limit of liability/COFR, and (3) the cost of demonstrating
financial responsibility.
In February 1996, DOT informed the Company that it had concluded (1) that
the Petroport facility, as then planned, posed no greater oil spill risk to the
environment than LOOP, (2) that Petroport's offshore storage caverns show
virtually zero spill potential, (3) that Petroport's credible worst case spill
would be 2,308 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 Field".
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
15
<PAGE>
air pollutant emissions. Violations of environmental related lease conditions or
environmental permits can result in substantial civil and criminal penalties as
well as potential court injunctions curtailing operations and the cancellation
of leases. Such enforcement liabilities can result from either governmental or
citizen prosecution.
LEGISLATION AND RULEMAKING. In October 1996 the U.S. Congress enacted the
Coast Guard Authorization Act of 1996 (P.L. 104-324) which amended the Oil
Pollution Act of 1990 to establish requirements for evidence of financial
responsibility for certain offshore facilities, other than Deepwater Ports. The
amount required is $35,000,000 for certain types of offshore facilities located
seaward of the seaward boundary of a state, including properties used for oil
transportation. The Company currently maintains this statutory $35,000,000
coverage.
Federal and state legislative rules and regulations are pending that, if
enacted, could significantly affect the oil and gas industry. It is impossible
to predict which of those federal and state proposals and rules, if any, will be
adopted and what effect, if any, they would have on the operations of the
Company.
In addition, various federal, state and local laws and regulations covering
the discharge of materials into the environment, occupational health and safety
issues, or otherwise relating to the protection of public health and the
environment, may affect the Company's operations, expenses and costs. The trend
in such regulation has been to place more restrictions and limitations on
activities that may impact the general or work environment, such as emissions of
pollutants, generation and disposal of wastes, and use 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 December 31, 2006,
10,097 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, 1998.
16
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Common Stock trades in the over-the-counter market and is quoted on
NASDAQ under the symbol "BDCO". As of March 2, 1999, there were an estimated 325
stockholders of record and the Company estimates there are more than 1,000
beneficial owners of the Common Stock. NASDAQ quotations reflect inter-dealer
prices, without adjustment for retail mark-ups, mark-downs or commissions and
may not represent actual transactions. The following table sets forth, for the
periods indicated, the high and low sales price for the Common Stock as reported
on NASDAQ.
SALES
HIGH LOW
------ ------
Quarter Ended March 31, 1997 ............... 6.57 3.75
Quarter Ended June 30, 1997 ................ 4.22 3.29
Quarter Ended September 30, 1997 ........... 7.04 3.75
Quarter Ended December 31, 1997 ............ 15.00 4.25
Quarter Ended March 31, 1998 ............... 4.50 2.75
Quarter Ended June 30, 1998 ................ 3.69 3.13
Quarter Ended September 30, 1998 ........... 3.56 2.44
Quarter Ended December 31, 1998 ............ 3.50 2.63
The Board of Directors by unanimous consent, and the stockholders by
majority consent, approved a one-for-fifteen reverse stock split of the
Company's Common Stock and reduction in the total number of shares of Common
Stock and Preferred Stock the Company is authorized to issue from 100 million
and 25 million, respectively, to 10 million and 2.5 million, respectively. The
effective date of the reverse stock split was December 8, 1997. The above prices
have been restated to reflect the effect of the reverse stock split.
The Company currently intends to retain earnings for its capital needs and
expansion of its business and does not anticipate paying cash dividends on the
Common Stock in the foreseeable future. Furthermore, the Company is restricted,
pursuant to its loan agreement with a commercial bank, from paying dividends on
Common Stock. Future policy with respect to dividends will be determined by the
Board of Directors based upon the Company's earnings and financial condition,
capital requirements and other considerations. The Company is a holding company
that conducts substantially all of its operations through its subsidiaries. As a
result, the Company's ability to pay dividends on the Common Stock is dependent
on the cash flow of its subsidiaries. The Company has not declared or paid any
dividends on the Common Stock since its incorporation. On December 31, 1996, the
holders of all outstanding shares of Series A, Cumulative Convertible Preferred
Stock, $.10 par value, converted the shares, in accordance with the terms of the
Preferred Stock, into an equivalent number of shares of the Common Stock of the
Company. The holders of the Preferred Stock agreed to accept as payment in full
of the cumulative dividends, promissory notes in a principal amount equal to the
cumulative dividends. See Note 7 to Consolidated Financial Statements of Blue
Dolphin Energy Company and Subsidiaries included in Item 8 and incorporated
herein by reference.
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<PAGE>
RECENT SALES OF UNREGISTERED SECURITIES During the year ended December 31,
1998, Directors, Officers and other employees exercised options to purchase
12,780 shares of Common Stock. The sale of shares was privately made to
Directors, Officers and other employees pursuant to the Company's 1985 Stock
Option Plan, at exercise price of $2.7885 per share. The Company relied on an
exemption under Section 4(2) of the Securities Act of 1933 in effecting these
transactions.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data of the Company and its consolidated
subsidiaries is presented for the five fiscal years ended December 31, 1998.
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,
------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Operating Revenues ........................ $ 3,558,773 $ 4,982,606 $ 4,128,568 $ 5,123,053 $ 6,792,765
Income (loss) from
continuing operations .................... $ (9,059,979)(4) $ 983,095 $ 92,302 $7,355,686 (2) $ 930,659
Income (loss) from
continuing operations
per Common Share (1) (3) ................ $ (2.02) $ .22 $ (.06) $ 3.04 $ .54
Weighted average number of
Common Shares outstanding (3) ........... 4,492,344 4,462,072 3,107,026 2,323,433 2,275,467
Income (loss) from continuing
operations per diluted
Common Share (1)(3) ..................... $ (2.02) $ .22 $ (.06) $ 1.77 $ .37
Weighted average number of
Common Shares and dilutive
potential Common Shares
outstanding (3) ......................... 4,492,344 4,531,208 3,107,026 4,139,037 4,147,765
Net Income (loss) ......................... $ (9,059,979)(4) $ 983,095 $ 92,302 $ 7,355,686(2) $ 1,542,699
Working Capital (deficit) ................. $ 104,543 $ 1,625,333 $ 917,113 $ 659,692 $ (1,415,091)
Total Assets .............................. $ 15,181,810 $ 24,927,263 $ 24,226,611 $ 25,069,178 $ 20,759,338
Long-term debt ........................... $ 2,060,600 $ 2,060,600 $ 2,060,600 $ 10,000 $ 4,450,000
</TABLE>
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<PAGE>
(1) Income from continuing operations per Common Share and dilutive Common
Share in 1998, 1997, 1996, 1995 and 1994 is based on the weighted average
number of Common Shares outstanding.
(2) Includes the gain on the sale of a one-third interest in the Blue Dolphin
Pipeline System effective August 1, 1995.
(3) The weighted average number of Common Shares and potential Common Shares
outstanding for the years ended December 31, 1996, 1995, and 1994, have
been restated to reflect the one-for-fifteen reverse stock split effected
on December 8, 1997.
(4) Includes a non-cash impairment of oil and gas properties effective December
31, 1998.
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.
Effective March 1, 1999, the Company acquired BMPC for $5,404,270. The
acquisition was funded by selling a one-sixth undivided interest in the Blue
Dolphin System and the Black Marlin System for $3,713,000. Additionally, the
owner of a one-third (1/3) interest in the Blue Dolphin System also acquired a
one-third interest in the Black Marlin System, for $1,801,423. These
transactions help to diversify the Company's revenue stream, reduces its
concentration of credit risk and doubles the size of the market in which it
competes to provide gathering and transportation services. Future utilization of
the Company's pipelines and related facilities will depend upon the success of
drilling programs in the pipeline corridors, and attraction and retention of
producer / shippers to the systems.
Certain of the statements included below, including those regarding future
financial performance or results, or that are not historical facts, are or
contain "forward-looking" information as that term is defined in the Securities
Act of 1933, as amended. The words "expect," "plan," "believe," "anticipate,"
"project," "estimate," and similar expressions are intended to identify
forward-looking statements. 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
At December 31, 1998, the Company's working capital (current assets less
current liabilities) was $104,543, representing a decrease of $1,520,790 as
compared with working capital of $1,625,333 at December 31, 1997. The decrease
in working capital is attributable to planned investments in longer term, high
potential programs. Approximately $822,086 was invested in the Petroport project
and $737,868 to generate oil and gas prospects during 1998.
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<PAGE>
The Company maintains a $10,000,000 reducing revolving credit facility with
Bank One, Texas, N.A. ("Loan Agreement"). Effective August 1, 1998, the
borrowing base was adjusted to $1,040,000 reducing by $60,000 per month
beginning September 1, 1998. At December 31, 1998, the borrowing base was
$800,000. The borrowing base and reducing amount are redetermined semi-annually
and are currently being redetermined as a result of the sale of a 1/6 undivided
interest in the Blue Dolphin System and the purchase of a 50% interest in the
Black Marlin System. The maturity date is January 14, 2000, when the then
outstanding principal balance, if any, is due and payable. At December 31, 1998
the outstanding balance under the credit facility was $210,000. 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. At December 31, 1998
the Company received waivers from Bank One, Texas, N.A on the debt covenants.
On December 31, 1996, the holders of all 970,698 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 6 to Consolidated Financial
Statements of Blue Dolphin Energy Company and Subsidiaries included in Item 8
and incorporated herein by reference.
In August 1996, the Minerals Management Service conducted an annual
inspection of the Buccaneer Field production platforms and facilities. In
addition to certain repairs, the Company was required to remove piping and other
equipment that was no longer in use. The removal and abandonment work, and the
repairs to the platforms were completed in March 1997. Additionally, a
previously inactive well was plugged and abandoned in 1997 at a cost of
approximately $457,000. Removal of the associated satellite platform and site
clearance is expected to take place in 1999, at an estimated cost of
approximately $206,000.
In July 1998, the Company renegotiated the terms of its supplemental surety
bonds that provide for certain of the estimated future abandonment obligations
associated with the Buccaneer Field. The supplemental surety bonds total
$1,300,000. The previous terms required the escrowing of $10,000 per month until
the bonds were fully funded. Under the new terms, the Company is no longer
required to escrow funds. In July 1998, approximately $593,000 of escrowed funds
was released to the Company.
The reserves and future net revenues presented in Item 1 "Business - Oil
and Gas Exploration and Production Activities", reflect capital expenditures
totalling $206,000 and $250,000 in the years ending December 31, 1999 and 2002
respectively. The timing of capital expenditures has changed significantly from
those presented in prior years. At December 31, 1998, as a result of deferring
its development plans for the Buccaneer Field and lower oil and gas prices, the
Company recorded a non-cash pre-tax charge of $12,011,544 reflecting the
impairment of its oil and gas properties, and certain exploration activity
costs. Management will continue to evaluate its capital expenditure program
based on, among other things, field reservoir performance, availability and cost
of drilling and workover equipment, and demand and prices obtainable for the
Company's production. The availability of capital resources will also affect the
Company's timing for further development of the Buccaneer Field, and there can
be no assurance that such reserves will be developed as currently planned.
Additionally, if the application of horizontal
20
<PAGE>
drilling and new completion techniques are feasible, the timing of capital
expenditures and future revenues could be significantly impacted.
In September 1997, the Company entered into an agreement with industry
participants, whereby in exchange for certain participation rights, these
companies partially funded the costs associated with the Company's 1997/1998
offshore prospect generation program. The remaining program costs are reimbursed
to the Company as prospects are developed and leases acquired. The initial
program with these partners has terminated. At the August 26, 1998 western Gulf
of Mexico federal lease sale, the participants acquired one lease block. In
addition, the Company, along with certain of the participants, acquired a second
lease block. The Company acquired a 30% interest in the block.
The Company holds interests in two other lease blocks prospective for oil
and gas in the High Island Area of the Gulf of Mexico. Approximately $825,000
was invested to acquire the two leases, in addition to approximately $86,000 for
lease rentals and $65,000 associated with technical development of the
prospects. A 43.75% interest in each of these prospective lease blocks has been
sold. Efforts to sell the remaining 56.25% interest in each lease block are
ongoing. Costs associated with these two lease blocks were included in the
impairment charge recorded at December 31, 1998.
In order to enhance the productivity of the prospect generation program,
during 1998 the Company transitioned from use of consulting geologists and
geophysicists to a 100% in house effort. Annual incremental costs associated
with changing to a 100% in house effort is approximately $700,000. The Company
currently is also seeking participants for available interests in its 1998/1999
program. Additionally, funding is being sought which would permit the Company to
directly participate as a working interest owner in and be designated operator
for prospects generated. The Company currently has placed a 50% interest in its
1998/1999 program. The Company is continuing its efforts to attract program
participants. The Company had previously entered into a multi-year 3-D seismic
data acquisition and licensing agreement, whereby a minimum of $1,500,000 has
been committed over a 5 year period ending July 31, 1999 to acquire 3-D seismic
data. The remaining commitment under this agreement is $450,000.
In the first quarter 1998, the Company drilled an unsuccessful well on its
Embar Field acreage in west Texas. The Company has terminated the farmin and
lease option agreement covering the acreage following reevaluation of the risks
of future drilling in light of the outcome of the initial well. Drilling and
workover costs incurred to the Company's interest were approximately $275,000.
Development of the Petroport deepwater terminal and offshore storage
facility continues to proceed as anticipated. The design, engineering, costing
and overall facility commercial evaluation have been completed, with favorable
results.
The Company is now seeking partners to fund the next phase of facility
development - site evaluation and licensing of the facility by federal and state
authorities. This cost is estimated to be $10 million. Cost of the offshore
terminal and storage complex, the pipeline to shore, and the onshore support
facilities is estimated to be $527 million. The Company expects to submit the
license application and associated permit requests in 1999, with operations
planned to commence in the year 2002.
In general, the Company believes that it has or can obtain adequate capital
resources and liquidity to continue to finance and otherwise meet its
anticipated business requirements. The availability or cost of capital resources
may, however, adversely affect the Company's timing for major pipeline
expansions, further development of the Buccaneer Field, growth in oil and gas
prospect generation activities and the Petroport project.
21
<PAGE>
RESULTS OF OPERATIONS
For the year ended December 31, 1998 ("1998"), the Company reported a net
loss of $9,059,979, compared to net income of $983,095 reported for the year
ended December 31, 1997 ("1997"), representing a decrease of $10,043,074. The
decrease is primarily due to a non-cash impairment of oil and gas properties
recorded at December 31, 1998 of $8,952,785, net of income tax benefit.
For 1997 net income increased by $890,793 compared to net income of $92,302
reported for the year ended December 31, 1996 ("1996"). The increase in net
income was primarily due to an increase in gas transportation volumes in 1997
and a decrease in repairs and modification costs associated with the Buccaneer
Field production platforms and facilities incurred in 1996.
REVENUES
1998 VS. 1997. Pipeline system revenues decreased by $1,373,649 or 33% in
1998 to $2,788,944 from 1997. The decrease was due to a decrease in oil
transportation revenues of $1,120,457, primarily due to the loss of a
producer/shipper in October 1997.
Revenues from oil and gas sales and operating fees for 1998 decreased
$50,184 or 6% to $769,829 from 1997. The reduction in oil and gas sales is
attributable to normal production declines.
Other income for 1998 decreased $157,432 or 40% to $105,994 from 1997. The
reduction in other income is due to a refund of prior years franchise taxes of
$152,370 in 1997.
1997 VS. 1996. Pipeline system revenues increased by $886,073 or 27% in
1997 to $4,162,593 from 1996. The increase was due to a 55% increase in gas
transportation volumes, resulting in an $898,116 increase in revenues.
COSTS AND EXPENSES
1998 VS. 1997. Repair and maintenance costs for 1998 decreased by $76,411
to $264,631 from 1997 due in part to repairs and modifications to the Buccaneer
Field production platforms and facilities of approximately $68,000 incurred in
1997.
General and administrative expense increased by $108,967 or 8% in 1998 from
1997 principally due to an increase in staff costs and consulting fees of
approximately $95,472, associated with potential asset acquisitions.
At December 31, 1998, the Company recorded a non-cash impairment expense of
$12,011,544 reflecting the write down of its oil and gas properties and certin
exploration activity costs, resulting from lower oil and gas prices and changes
to the Company's development plans, whereby development of oil and gas
properties have been delayed.
1997 VS. 1996. Repair and maintenance costs for 1997 decreased by $554,316
to $341,041 due primarily to nonrecurring repairs and modifications to the
Buccaneer Field production platforms and facilities of approximately $550,000
incurred in 1996.
22
<PAGE>
Interest expense increased $202,165 in 1997 to $218,955 as a result of
promissory notes totaling $2,050,600, issued December 31, 1996. The notes are
associated with the conversion of the issued and outstanding Preferred Stock to
Common Stock.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 130 regarding reporting
comprehensive income, which establishes standards for reporting and display of
comprehensive income and its components. The components of comprehensive income
refer to revenues, expenses, gains and losses that are excluded from net income
under current accounting standards, including foreign currency translation
items, minimum pension liability adjustments and unrealized gains and losses on
certain investments in debt and equity securities. SFAS No. 130 requires that
all items recognized under accounting standards as components of comprehensive
income be reported in a financial statement displayed in equal prominence with
the other financial statements; the total of other comprehensive income for a
period is required to be transferred to a component of equity that is separately
displayed in a statement of financial condition at the end of an accounting
period. SFAS No. 130 is effective for both interim and annual periods beginning
after December 15, 1997. Reclassification of financial statements for earlier
periods provided for comparative purposes is required. Adoption by the Company
of SFAS No. 130 effective January 1, 1998, has had no impact to the Company's
financial statements presented herein.
In June 1997, FASB issued SFAS No. 131 regarding disclosures about
segments of an enterprise and related information. SFAS No. 131 establishes
standards for reporting information about operating segments in annual financial
statements and requires the reporting of selected information about operating
segments in interim financial reports issued to stockholders. It also
establishes standards for related disclosures about products and services,
geographic areas and major customers. SFAS No. 131 is effective for periods
beginning after December 15, 1997. The Company has adopted SFAS No. 131 for the
fiscal year ended December 31, 1998.
Statement of Financial Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (SFAS No. 133), was issued by the Financial
Accounting Standards Board in June 1998. SFAS No. 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts. The Company will adopt SFAS No. 133 beginning in
calendar year 2000. The Company has not determined the impact that SFAS No. 133
will have on its financial statements and believes that such determination will
not be meaningful until closer to the date of initial adoption. The Company
believes that adoption of this financial accounting standard will not have a
material effect on its financial condition or results of operations.
In April 1998, the Accounting Standards Executive Committee of the
American Institute of Certified Public Accountants issued Statement of Position
98-5, Reporting on the Costs of Start-Up Activities ("SOP 98-5"). SOP 98-5
requires that costs of start-up activities be charged to expense as incurred and
broadly defines such costs. The Company has capitalized certain costs incurred
in connection with a new business segment, and SOP 98-5 will require that such
costs be charged to results of operations upon its adoption. SOP 98-5 is
effective for fiscal years beginning after December 15, 1998. The Company will
adopt the requirements of SOP 98-5 as of January 1, 1999. The cumulative effect
of the change in accounting principle for the adoption of SOP 98-5 will result
in a charge to results of operations in the Company's financial statements for
the three months ending March 31, 1999; it is currently estimated that such
charge will not be material.
23
<PAGE>
YEAR 2000 ISSUE
The Company has conducted a review of its computer equipment and software
to identify the systems that could be affected by the "Year 2000" issue. The
Year 2000 issue results from computer programs being written using two digits
(rather than four) to define the applicable year. As a result, certain of the
Company's programs that have time-sensitive software may recognize a date using
"00" as the year 1900 rather than the year 2000. This could result in a major
system failure or miscalculations.
Accordingly, the Company has initiated a plan to address the Year 2000
issues associated with its operations and business. The plan includes several
phases - (i) assessment of all of the Company's systems and technology: (ii)
testing of existing systems and technology, both financial and operational:
(iii) modification to or replacement of non-compliant systems and technology
(iv) communication with key business partners regarding Year 2000 issues: and
(v) contingency planning.
In planning and developing the project, the Company has considered both its
information technology ("IT") and its non-IT systems. The term "computer
equipment and software" includes systems that are commonly thought of as IT
systems, including accounting, data processing, telephone systems, scanning
equipment, and other miscellaneous systems. Non-IT systems include alarm
systems, measurement devices, fax machines, and other miscellaneous equipment.
Both IT and non-IT systems may contain embedded technology, which complicates
the Company's Year 2000 identification, assessment, testing, and remediation
efforts.
The Company has tested most of its IT systems, primarily financial and
operational software, for necessary compliance. As of the date of this filing,
the Company estimates that approximately 90% of its Year 2000 plan related to
these IT systems has been implemented and anticipates that the remainder of the
plan including any necessary remedial action, will be completed by July 30,
1999. The Company continues to evaluate its vulnerability to Year 2000 issues
related to its non-IT systems, primarily field operational systems and
equipment.
The failure to correct a material Year 2000 issue could result in an
interruption in, or a failure of, certain normal business activities, resulting
in a material adverse affect on the Company's results of operations, liquidity
and financial position. The Company's remediation efforts are expected to reduce
significantly the Company's level of uncertainty about Year 2000 compliance and
the possibility of interruptions of normal operations. However, there can be no
guarantee that other companies' systems, on which the Company's systems rely,
will be timely converted, or that a failure to convert by another company, or a
conversion that is incompatible with the Company's systems, would not have a
material adverse effect on the Company.
In a recent Securities and Exchange Commission release regarding Year 2000
disclosures, the Securities and Exchange Commission stated that public companies
must disclose the most reasonably likely worst case Year 2000 scenario. Analysis
of the most reasonably likely worst case Year 2000 scenarios the Company may
face leads to contemplation of the following possibilities which, though
unlikely in some or many cases, must be included in any consideration of worst
cases: widespread failure of oil and gas producers transporting production
through the Company's pipeline systems, widespread failure of electrical, gas,
and similar supplies by utilities serving the Company; widespread disruption of
the services of communications common carriers; similar disruption to means and
modes of transportation for the Company and its employees, contractors,
suppliers and customers; significant disruption to the Company's ability to gain
access to, and remain working in, office buildings and other facilities; the
failure of substantial numbers of the Company's mission-critical information
(computer) hardware and software systems, including both internal business
systems and systems (such as those with
24
<PAGE>
embedded chips) controlling operational facilities such as oil and gas rigs, oil
and gas pipelines and gas plants. The effects of which would have a cumulative
material adverse impact on the Company. Among other things, the Company could
face substantial claims by customers or loss of revenues due to service
interruptions, inability to fulfill contractual obligations, inability to
account for certain revenues or obligations or to bill customers accurately and
on a timely basis, and increased expenses associated with litigation,
stabilization of operations following mission-critical failures, and the
execution of contingency plans. The Company could also experience the inability
by customers to pay, on a timely basis or at all, obligations owed to the
Company. Under these circumstances, the adverse effect on the Company, and the
diminution of the Company's revenues, would be material, although not
quantifiable at this time. Further in this scenario, the cumulative effect of
these failures could have a substantial adverse effect on the economy,
domestically and internationally. The adverse effect on the Company, and the
diminution of the Company's revenues, from a domestic or global recession or
depression is also likely to be material, although not quantifiable at this
time.
As of December 31, 1998, the Company has incurred minimal costs in
connection with Year 2000 compliance. The Company intends to complete its Year
2000 compliance projects by July 1999 and does not anticipate any additional
costs.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET PRICE
The Company is exposed to market risk, including adverse changes in
commodity prices and interest rates as discussed below.
COMMODITY PRICE RISK- The Company produces, and sells natural gas, crude
oil, and natural gas liquids. As a result, the Company's financial results can
be significantly affected if these commodity prices fluctuate widely in response
to changing market forces. The Company has not used derivative products in the
past to manage commodity price risk.
INTEREST RATE RISK- The Company's exposure to changes in interest rates
primarily results from its short-term and long-term debt with floating interest
rates. See Note 6 to Consolidated Financial Statements of Blue Dolphin Energy
Company and Subsidiaries included in Item 8 and incorporated herein by reference
for information relating to existing credit facility. Based upon the current
credit facility a 10% change in the interest rate on the credit facility would
result in a minimal increase in interest expense.
25
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements: PAGE
Independent Auditors' Report.........................................27
Consolidated Balance Sheets, at December 31, 1998 and 1997...........28
Consolidated Statements of Operations, for the years
ended December 31, 1998, 1997, and 1996.........................30
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1998, 1997, and 1996...................31
Consolidated Statements of Cash Flows, for the years
ended December 31, 1998, 1997, and 1996.........................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, 1998 and 1997, 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, 1998.
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, 1998 and 1997, and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 1998, in conformity with generally accepted accounting
principles.
KPMG LLP
Houston, Texas
March 30, 1999
27
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 1998 and 1997
ASSETS 1998 1997
----------- -----------
Current assets:
Cash and cash equivalents ....................... $ 593,509 1,756,294
Trade accounts receivable ....................... 771,268 861,740
Crude oil inventory, at market .................. 5,248 7,570
Prepaid expenses and other assets ............... 152,340 87,268
----------- -----------
Total current assets ................. 1,522,365 2,712,872
----------- -----------
Property and equipment, at cost:
Oil and gas properties, including $0 and $992,293
of leases held for sale at December 31,
1998 and 1997, respectively (full-cost method) 21,210,806 20,467,503
Onshore separation and handling facilities ...... 2,106,189 2,041,596
Land ............................................ 1,133,333 1,133,333
Pipelines ....................................... 1,320,063 1,175,547
Other property and equipment .................... 343,220 127,033
----------- -----------
26,113,611 24,945,012
Less accumulated depletion, depreciation,
amortization and impairment .................. 17,172,057 4,841,211
----------- -----------
8,941,554 20,103,801
Deferred federal income tax ......................... 2,010,060 --
Acquisition and development costs - Petroport ....... 1,576,391 766,485
Escrow fund ......................................... 1,107,573 1,327,766
Other assets ........................................ 23,867 16,339
----------- -----------
$15,181,810 24,927,263
=========== ===========
See accompanying notes to consolidated financial statements.
(Continued)
28
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, CONTINUED
December 31, 1998 and 1997
<TABLE>
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY 1998 1997
------------ ------------
<S> <C> <C>
Current liabilities:
Trade accounts payable and accrued expenses ............................................. $ 892,190 700,315
Accrued interest payable ................................................................ 105,662 105,957
Current portion of accrued abandonment costs ............................................ 206,000 231,000
Current portion of long term debt ....................................................... 200,000 --
Income taxes payable .................................................................... 13,970 50,267
------------ ------------
Total current liabilities ..................................................... 1,417,822 1,087,539
------------ ------------
Long-term debt .............................................................................. 2,060,600 2,060,600
Deferred federal income tax ................................................................. -- 1,103,921
Accrued abandonment costs, less current portion ............................................. 108,594 51,876
------------ ------------
Total long-term liabilities ................................................... 2,169,194 3,216,397
------------ ------------
Stockholders' equity:
Common stock, $.01 par value. 10,000,000 shares authorized at December 31,
1998 and 1997, 4,504,627 shares issued and outstanding at December 31,
1998; 4,491,847 shares issued and outstanding
at December 31, 1997 ................................................................. 45,046 44,918
Additional paid-in capital .............................................................. 17,700,833 17,669,515
Retained earnings (deficit) since January 1, 1990 ....................................... (6,151,085) 2,908,894
------------ ------------
Total stockholders' equity .................................................... 11,594,794 20,623,327
$ 15,181,810 24,927,263
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
29
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Revenue from operations:
Pipeline operations ......................................................... $ 2,788,944 4,162,593 3,276,520
Oil and gas sales and operating fees ........................................ 769,829 820,013 852,048
------------ ------------ ------------
Revenue from operations ............................................ 3,558,773 4,982,606 4,128,568
------------ ------------ ------------
Cost of operations:
Pipeline operating expenses ................................................. 796,144 804,880 871,305
Lease operating expenses .................................................... 669,377 620,807 609,805
Repairs and maintenance costs ............................................... 264,630 341,041 895,357
Impairment of oil and gas properties ........................................ 12,011,544 -- --
Depletion, depreciation and amortization .................................... 400,982 372,252 388,406
General and administrative expenses ......................................... 1,466,738 1,357,771 1,315,256
------------ ------------ ------------
Cost of operations ................................................. 15,609,415 3,496,751 4,080,129
------------ ------------ ------------
Income (loss) from operations ...................................... (12,050,642) 1,485,855 48,439
Other income (expense):
Interest expense ............................................................ (215,141) (218,955) (16,790)
Interest and other income ................................................... 105,994 262,426 123,442
------------ ------------ ------------
Income (loss) before income taxes .................................. (12,159,789) 1,529,326 155,091
Income tax benefit (expense) .................................................... 3,099,810 (546,231) (62,789)
------------ ------------ ------------
Net income (loss) .................................................. (9,059,979) 983,095 92,302
Dividend requirements on preferred stock ........................................ -- -- (291,204)
------------ ------------ ------------
Net income (loss) attributable to
common stockholders ............................................. $ (9,059,979) 983,095 (198,902)
============ ============ ============
Earnings (loss) per share:
Basic ..................................................................... $ (2.02) 0.22 (0.06)
============ ============ ============
Diluted ................................................................... $ (2.02) 0.22 (0.06)
============ ============ ============
Weighted average number of common shares outstanding and dilutive potential
common shares:
Basic ..................................................................... 4,492,344 4,462,072 3,107,026
============ ============ ============
Diluted ................................................................... 4,492,344 4,531,208 3,107,026
============ ============ ============
</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, 1998, 1997, and 1996
<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, 1995 ............. $ 23,550 1,456,048 14,493,358 2,124,701 18,097,657
-------- ----------- ----------- ---------- -------------
Exercise of 1,105,039 warrants ....... 11,050 -- 1,645,507 -- 1,656,557
Exercise of 20,555 stock options and
related tax benefit ................ 206 -- 42,035 -- 42,241
Dividend requirements on preferred
stock .............................. -- -- -- (291,204) (291,204)
Conversion of 14,560,475 shares of
preferred stock .................... 9,707 (1,456,048) 1,443,532 -- (2,809)
Other ................................ -- -- 5,833 -- 5,833
Net income ........................... -- -- -- 92,302 92,302
-------- ----------- ----------- ---------- -------------
Balance at December 31, 1996 ............. 44,513 -- 17,630,265 1,925,799 19,600,577
-------- ----------- ----------- ---------- -------------
Exercise of 51,340 stock options ..... 513 -- 159,574 -- 160,087
Cancellation of 10,768 shares of stock (108) -- (110,324) -- (110,432)
Other ................................ -- -- (10,000) -- (10,000)
Net income ........................... -- -- -- 983,095 983,095
-------- ----------- ----------- ---------- -------------
Balance at December 31, 1997 ............. 44,918 -- 17,669,515 2,908,894 20,623,327
-------- ----------- ----------- ---------- -------------
Exercise of 12,780 stock options ..... 128 -- 35,509 -- 35,637
Other ................................ -- -- (4,191) -- (4,191)
Net loss ............................. -- -- -- (9,059,979) (9,059,979)
-------- ----------- ----------- ---------- -------------
Balance at December 31, 1998 ............. $ 45,046 -- 17,700,833 (6,151,085) 11,594,794
======== =========== =========== ========== =============
</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, 1998, 1997, and 1996
<TABLE>
<CAPTION>
1998 1997 1996
------------ ---------- ----------
<S> <C> <C> <C>
Operating activities:
Net income (loss) .......................................... $ (9,059,979) 983,095 92,302
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization ............... 400,982 372,252 388,406
Deferred income taxes .................................. (3,113,980) 469,965 50,542
Gain on sale of property and equipment ................. -- -- (4,397)
Impairment of oil and gas properties ................... 12,011,544
Changes in operating assets and liabilities:
(Increase) decrease in trade accounts receivable ..... 90,472 (117,457) 116,408
(Increase) decrease in crude oil inventory,
prepaid expenses and other assets .................. (62,750) 3,962 (6,796)
(Decrease) increase in trade accounts payable,
accrued interest and other liabilities ............. 130,282 (276,754) (157,929)
------------ ---------- ----------
Net cash provided by operating activities ....... 396,571 1,435,063 478,536
------------ ---------- ----------
Investing activities:
Oil and gas prospect generation costs ...................... (737,868) (500,460) (1,960,217)
Proceeds from sales of oil and gas prospect leases ......... -- 1,018,289 397,178
Exploration and development costs .......................... (100,051) -- --
Purchases of property and equipment ........................ (354,821) (299,551) (531,623)
Development costs - Petroport .............................. (822,086) (185,641) (216,113)
Reduction of escrowed abandonment fund ..................... 593,830 -- --
Abandonment of oil and gas properties ...................... -- (570,115) (1,047,908)
Funds escrowed for abandonment costs ....................... (369,806) (388,269) (374,569)
------------ ---------- ----------
Net cash used in
investing activities .......................... (1,790,802) (925,747) (3,733,252)
------------ ---------- ----------
Financing activities:
Proceeds from revolving credit facility .................... 200,000 -- --
Net proceeds from the exercise of stock options and warrants 31,446 39,655 1,713,572
------------ ---------- ----------
Net cash provided by
financing activities .......................... 231,446 39,655 1,713,572
------------ ---------- ----------
Increase (decrease) in cash ..................... (1,162,785) 548,971 (1,541,144)
Cash and cash equivalents at beginning of year .................. 1,756,294 1,207,323 2,748,467
------------ ---------- ----------
Cash and cash equivalents at end of year ........................ $ 593,509 1,756,294 1,207,323
============ ========== ==========
Supplementary cash flow information:
Interest paid .............................................. $ 214,926 113,000 17,000
============ ========== ==========
Income taxes (received) paid ............................... $ (93,264) 70,881 226,519
============ ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
32
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1998, 1997 and 1996
(1) ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Blue Dolphin Energy Company (the Company) was incorporated in Delaware in
January 1986 to engage in oil and gas exploration, production and
acquisition activities and oil and gas transportation and marketing. It
was formed pursuant to a reorganization effective June 9, 1986.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of the Company include the accounts
of its wholly-owned subsidiaries. All significant intercompany balances
and transactions have been eliminated in consolidation.
ACCOUNTING ESTIMATES
Management has made a number of estimates and assumptions relating to the
reporting of assets and liabilities and to the disclosure of contingent
assets and liabilities including reserve information which affects the
depletion calculation as well as the computation of the full cost ceiling
limitation to prepare these financial statements in conformity with
generally accepted accounting principles. Actual results could differ from
those estimates.
CASH EQUIVALENTS
Cash equivalents include liquid investments with an original maturity of
three months or less.
CRUDE OIL INVENTORY
Inventory represents crude oil in storage tanks at the Company's shore
facility near Freeport, Texas. Such inventories are recorded at their fair
market value as of the balance sheet date.
OIL AND GAS PROPERTIES
Oil and gas properties are accounted for using the full-cost method of
accounting, whereby all costs associated with acquisition, exploration,
and development of oil and gas properties, including directly related
internal costs, are capitalized on a country-by-country cost center basis.
Amortization of such costs and estimated future development costs is
determined using the unit-of-production method. Costs directly associated
with the acquisition and evaluation of unproved properties are excluded
from the amortization computation until it is determined whether or not
proved reserves can be assigned to the properties or impairment has
occurred. Estimated proved oil and gas reserves are based upon reports of
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
33
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ceiling, defined as the sum of the present value (10% discount rate
applied) of estimated future net revenues from proved reserves, after
giving effect to income taxes, and the lower of cost or estimated fair
value of unproved properties. Disposition of oil and gas properties are
recorded as adjustments to capitalized costs, with no gain or loss
recognized unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves.
At December 31, 1998, the Company recorded an impairment charge on oil and
gas properties and certain exploration activity costs of $12,011,544,
thereby adjusting the net carrying value of oil and gas properties to the
cost center ceiling as described above. The impairment results from lower
oil and gas prices and changes to the Company's development plans, whereby
development of oil and gas properties have been deferred. Included in oil
and gas properties is $992,293 of leases acquired with the intention of
selling to third-party participants as drillable oil and gas prospects as
of December 31, 1997, which costs the Company included in the impairment
charge recorded at December 31, 1998. Included in oil and gas properties
at December 31, 1998 is $198,486 in expenditures directly associated with
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 Statement of Financial Accounting Standards
(SFAS) No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR
LONG-LIVED ASSETS TO BE DISPOSED OF, with no impact to the Company's
consolidated financial statements. Assets are grouped and evaluated based
on the ability to identify separate cash flows generated therefrom.
OTHER PROPERTY AND EQUIPMENT
Depreciation of furniture, fixtures and other equipment, including assets
held under capital leases, is computed using the straight-line method over
estimated useful lives of 2-5 years.
ABANDONMENT
34
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A provision for the abandonment, dismantlement and site remediation of
offshore production platforms and existing wells is made using the
unit-of-production method applied to estimates based on current costs. A
provision for pipeline and pipeline facilities abandonment costs is also
provided using the straight-line method over the estimated useful lives of
the pipeline and pipeline facilities. These provisions are included in
accumulated depletion, depreciation and amortization, and accrued
abandonment costs, respectively, and are undiscounted. Aggregate
abandonment liability is estimated to be approximately $3,960,000 and
$3,985,000 at December 31, 1998 and 1997, respectively.
STOCK-BASED COMPENSATION
The Company applies SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION,
which allows a company to adopt a fair value based method of accounting
for a stock-based employee compensation plan or to continue to use the
intrinsic value based method of accounting prescribed by Accounting
Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES.
The Company has chosen to continue to account for stock-based compensation
under the intrinsic value method and provides the pro forma effects of the
fair value method as required.
RECOGNITION OF CRUDE OIL AND NATURAL GAS REVENUE
Revenue from crude oil and natural gas produced and sold from the
Buccaneer Field is recognized when such crude oil and natural gas 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.
OPERATION OF OIL AND GAS PROPERTIES
The Company operates, for a monthly fee, oil and gas properties in which
it does not own an interest. Revenues and costs from these activities are
included in oil and gas sales and operating fees and lease operating
expenses, respectively.
INCOME TAXES
35
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
EARNINGS PER SHARE
The Company follows SFAS No. 128 (Statement 128), EARNINGS PER Share, for
computing and presenting earnings per share and requires, among other
things, dual presentation of basic and diluted earnings per share on the
face of the statement of operations.
36
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a reconciliation between basic and diluted
earnings (loss) per share:
<TABLE>
<CAPTION>
WEIGHTED
AVERAGE
COMMON SHARES
OUTSTANDING
NET AND DILUTIVE PER
INCOME POTENTIAL SHARE
(LOSS) COMMON SHARES AMOUNT
----------- ------------- -----
<S> <C> <C> <C>
Year ended December 31, 1998:
Basic (loss) per share ......... $(9,059,979) 4,492,344 $(2.02)
----------- ------------- -----
Diluted (loss) per share ....... $(9,059,979) 4,492,344 $(2.02)
=========== ============= =====
Year ended December 31, 1997:
Basic earnings per share ..... $ 983,095 4,462,072 $0.22
Effect of dilutive stock
options .................. -- 69,136
----------- ------------- -----
Diluted earnings per share ... $ 983,095 4,531,208 $0.22
=========== ============= =====
Year ended December 31, 1996:
Basic (loss) per share ....... $ (198,902) 3,107,026 $(0.06)
----------- ------------- -----
Diluted (loss) per share ..... $ (198,902) 3,107,026 $(0.06)
=========== ============= =====
</TABLE>
The employee stock options at December 31, 1998, and the employee stock
options and the Convertible Preferred Stock at December 31, 1996 were not
included in the computation of diluted earnings per share because the
effect of their assumed exercise and conversion would have an antidulitive
effect on the computation of diluted loss per share.
37
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
ENVIRONMENTAL
The Company is subject to extensive Federal, state and local environmental
laws and regulations. These laws, which are constantly changing, regulate
the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed or capitalized depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are
expensed. Liabilities for expenditures of a noncapital nature are recorded
when environmental assessment and/or remediation is probable, and the
costs can be reasonably estimated. Such liabilities are generally recorded
at their undiscounted amounts unless the amount and timing of payments is
fixed or reliably determinable.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 130 regarding
reporting comprehensive income, which establishes standards for reporting
and display of comprehensive income and its components. The components of
comprehensive income refer to revenues, expenses, gains and losses that
are excluded from net income under current accounting standards, including
foreign currency translation items, minimum pension liability adjustments
and unrealized gains and losses on certain investments in debt and equity
securities. SFAS No. 130 requires that all items recognized under
accounting standards as components of comprehensive income be reported in
a financial statement displayed in equal prominence with the other
financial statements; the total of other comprehensive income for a period
is required to be transferred to a component of equity that is separately
displayed in a statement of financial condition at the end of an
accounting period. SFAS No. 130 is effective for both interim and annual
periods beginning after December 15, 1997. Reclassification of financial
statements for earlier periods provided for comparative purposes is
required. Adoption by the Company of SFAS No. 130 effective January 1,
1998, has had no impact to the Company's financial statements presented
herein.
38
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In June 1997, FASB issued SFAS No. 131 regarding disclosures about
segments of an enterprise and related information. SFAS No. 131
establishes standards for reporting information about operating segments
in annual financial statements and requires the reporting of selected
information about operating segments in interim financial reports issued
to stockholders. It also establishes standards for related disclosures
about products and services, geographic areas and major customers. SFAS
No. 131 is effective for periods beginning after December 15, 1997. The
Company has adopted SFAS No. 131 for the fiscal year ended December 31,
1998.
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities (SFAS No. 133), was issued
by the Financial Accounting Standards Board in June 1998. SFAS No. 133
standardizes the accounting for derivative instruments, including certain
derivative instruments embedded in other contracts. The Company will adopt
SFAS No. 133 beginning in calendar year 2000. The Company has not
determined the impact that SFAS No. 133 will have on its financial
statements and believes that such determination will not be meaningful
until closer to the date of initial adoption. The Company believes that
adoption of this financial accounting standard will not have a material
effect on its financial condition or results of operations.
In April 1998, the Accounting Standards Executive Committee of the
American Institute of Certified Public Accountants issued Statement of
Position 98-5, Reporting on the Costs of Start-Up Activities ("sop 98-5").
SOP 98-5 requires that costs of start-up activities be charged to expense
as incurred and broadly defines such costs. We have deferred certain costs
incurred in connection with potential business initiatives and a new
business segment, and SOP 98-5 will require that such deferred costs be
charged to results of operations upon its adoption. SOP 98-5 is effective
for fiscal years beginning after December 15, 1998. We will adopt the
requirements of SOP 98-5 as of January 1, 1999. The cumulative effect of
the change in accounting principle for the adoption of SOP 98-5 will
result in a charge to results of operations in our financial statements
for the three months ending March 31, 1999; it is currently estimated that
such charge will not be material 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
39
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for quasi-reorganizations. The principal adjustments to fair value
included an $810,000 increase in the carrying value of land and the
elimination of the remaining deferred debt offering costs associated with
convertible subordinated notes of $994,192, resulting in a net charge to
the accumulated deficit of $184,192.
The Company's remaining assets and liabilities at December 31, 1989
approximated fair value; accordingly, the accumulated depletion,
depreciation and amortization at December 31, 1989 was eliminated against
the original cost of the assets. The accumulated deficit of $14,031,556 at
December 31, 1989 was then transferred to additional paid-in capital. Any
benefits realized upon the utilization of tax operating losses generated
prior to January 1, 1990 were credited to additional paid-in capital.
(3) SUBSEQUENT EVENTS
On March 1, 1999 the Company acquired Black Marlin Pipeline Company from
Enron Pipeline Company (Enron), for $5,404,270 cash. In addition, Enron
has a purchase option to repurchase between 25% and 33 1/3% of the Black
Marlin Pipeline System if it becomes exempt from rate or tariff regulation
under the Natural Gas Act of 1938 by the Federal Energy Regulatory
Commission. This option expires on the earlier of the third anniversary of
the notice that the Black Marlin pipeline is exempt from rate or tariff
regulation or March 1, 2004. Black Marlin Pipeline Company owns the 75
mile Black Marlin Pipeline System located in the High Island area off the
Texas Gulf Coast extending across Galveston Bay to shore facilities in
Texas City, Texas. This acquisition was funded by selling a one-sixth
(1/6) undivided interest in the Company's Blue Dolphin Pipeline System,
the Black Marlin Pipeline System and the inactive Omega Pipeline to WBI
Southern, Inc. ("WBI") for $3,713,000 and selling a one-third (1/3)
undivided interest in the Black Marlin Pipeline System to MCNIC Pipeline
Processing Company ("MCNIC") for $1,801,423. MCNIC owns a one-third (1/3)
undivided interest in the Blue Dolphin Pipeline System. The sale to WBI
provides for conditional consideration to be paid by WBI to the Company of
up to $500,000 during a four year term ending February 28, 2003, if
certain cash flow targets are achieved.
(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
40
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1998 and 1997.
(5) INCOME TAXES
Income tax expense for 1998, 1997 and 1996 consists of:
1998 1997 1996
----------- ------- ------
Current:
Federal ..... $ -- 25,466 --
State ....... 14,170 50,800 12,247
Deferred - federal (3,113,980) 469,965 50,542
----------- ------- ------
$(3,099,810) 546,231 62,789
=========== ======= ======
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, 1998 and 1997 are presented below.
<TABLE>
<CAPTION>
1998 1997
----------- ----------
<S> <C> <C>
Deferred tax assets:
Accrued abandonment costs .......... $ 84,541 73,796
Net operating loss carryforwards ... 2,685,789 2,106,646
Alternative minimum tax credit ..... 244,444 254,363
Basis differences in property and
equipment ........................ 29,295 --
----------- ----------
Total gross deferred tax assets .. 3,044,069 2,434,805
Deferred tax liabilities:
Basis differences in property and
equipment ..................... -- (3,504,717)
State tax .......................... (34,009) (34,009)
----------- ----------
Total gross deferred tax liability (34,009) (3,538,726)
----------- ----------
Net deferred tax asset (liability) 3,010,060 (1,103,921)
Less valuation allowance ........ (1,000,000) --
----------- ----------
Deferred tax asset (liability)......... $ 2,010,060 (1,103,921)
=========== ==========
</TABLE>
41
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 believes that
the valuation allowance at December 31, 1998 reduces the deferred tax
assets to amounts for which the benefit of such deferred tax assets are
expected to be fully utilized.
The Company's effective tax rate applicable to continuing operations in
1998, 1997 and 1996 differs from the expected tax rate of 34% due to the
following:
1998 1997 1996
---- ---- ----
Expected tax rate .............................. 34% 34% 34%
State taxes, net of federal benefit ............ -- 1% 5%
Expenses not deductible for tax purposes ....... -- 1% 1%
Increase in valuation allowance recognized
in earnings ................................ (8%) -- --
---- ---- ----
26% 36% 40%
==== ==== ====
At December 31, 1998, the Company had the following estimated net
operating loss carryforwards (NOL):
YEAR OF NET OPERATING LOSS
EXPIRATION CARRYFORWARDS
---------- ------------------
2002 .................... $ 511,551
2003 .................... 1,954,812
2004 .................... 2,066,517
2006 .................... 1,011,469
2007 .................... 402,349
2011 .................... 311,844
2018 .................... 1,640,839
------------------
$ 7,899,381
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
42
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 1998. 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 $244,444
that does not expire and may be applied to reduce regular tax to an amount
not less than the alternative minimum tax payable in any one year.
(6) LONG-TERM DEBT
The Company maintains a reducing revolving credit facility (Loan
Agreement) with Bank One, Texas, N.A. (Bank One), in an amount of
$10,000,000. At December 31, 1998, the borrowing base under the Loan
Agreement was $800,000 reducing $60,000 per month. The borrowing base is
redetermined semi-annually. On the first day of each month interest is due
and payable on the outstanding loan balance at the rate of 1.25% above
Bank One's prime rate of interest. Borrowings under the Loan Agreement are
secured by first liens on the Buccaneer Field, the Blue Dolphin Pipeline,
the Buccaneer Pipeline, the Freeport, Texas acreage and the Shore
Facilities. The maturity date under the Loan Agreement is January 14,
2000.
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. At December 31, 1998 the
company has received waivers from Bank One on the debt covenants.
In December 1996, the Company issued $2,050,600 in promissory notes to the
holders of the Preferred Stock as full payment of the cumulative preferred
stock dividends. The promissory notes are unsecured and bear interest at
the rate of 10.25% per annum. Interest only is payable semi-annually with
the principal due on December 31, 2000. The Company may prepay all or a
portion of the principal at any time prior to maturity with no penalty.
43
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-term debt at December 31, 1998 and 1997 is as follows:
DECEMBER 31,
-----------------------
1998 1997
---------- ---------
$10,000,000 bank credit facility,
$800,000 borrowing base interest
payable monthly at prime rate
(8. 5% at December 31, 1998)
plus 1.25%. Borrowing availability
and reducing base amount are
redetermined semiannually .... $ 210,000 10,000
$2,050,600 notes payable, interest at
10.25% per annum payable
semi-annually, principal due
December 31, 2000 ........... 2,050,600 2,050,600
---------- ---------
2,260,600 2,060,600
Less current maturities ........ 200,000 --
---------- ---------
$2,060,600 2,060,600
========== =========
(7) STOCKHOLDERS' EQUITY
Effective December 31, 1996, the holders of all 970,698 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
44
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
with the Common Stock, except that the holders of the Preferred Stock were
entitled to elect a majority of the Board of Directors as a result of the
dividend arrearage being more than three years.
In December 1997, the Company effected a one-for-fifteen reverse stock
split of its common stock. As a result of the reverse stock split, the
number of shares of common stock was decreased to 10,000,000 shares
authorized and 4,479,133 shares outstanding from 100,000,000 shares
authorized and 67,186,971 shares outstanding, respectively, immediately
prior to the reverse stock split. The stockholders' equity accounts on the
accompanying financial statements have been restated to give retroactive
recognition to the reverse stock split for all periods presented. In
addition, all references to number of shares of common stock and per share
amounts have been restated throughout these financial statements.
(8) STOCK OPTIONS
The Company adopted a new stock option plan in 1996 (the Plan). The stock
subject to the options and other provisions of the Plan are shares of the
Company's Common Stock, $.01 par value (the Stock). The total amount of
the Stock with respect to which options may be granted shall not exceed in
the aggregate 10% of the number of issued and outstanding shares of Common
Stock of the Company. The stock options become exercisable from time to
time in part or as a whole, as the Compensation Committee (the Committee),
appointed by the Board of Directors, or the Board of Directors in their
discretion may provide. However, the Committee shall not grant options
which may become exercisable in any one calendar year to purchase more
than one-third of the maximum amount granted. All options expire five
years after the date of grant. The price of options granted may not be
less than eighty-five percent of the fair market value of the Stock on the
date the option is granted. Optionees must continue their association with
the Company for six months after exercising the options, or the underlying
stock reverts to the Company. All shares issued for options exercised in
the current year are restricted at December 31, 1998. The Company's
previous stock option plan, with terms and conditions essentially the same
as those of the Plan, expired in 1995.
45
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 1998 the Company has reserved a total of 553,475 shares of
Common Stock for issuance under the above mentioned stock option plans, of
which 47,418 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, 1996 ........... 197,000 0.938 4.383
======== ====== ======
Granted ........................... 53,690 3.825 3.825
Exercised ......................... (51,340) 0.938 4.383
-------- ------ ------
Balance, December 31, 1997 ........... 199,350 2.391 4.383
======== ====== ======
Expired ........................... (32,005) 4.383 2.789
Exercised ......................... (12,780) 2.789 2.789
-------- ------ ------
Balance, December 31, 1998 ........... 154,565 2.789 4.383
======== ====== ======
The weighted average exercise price per share was $2.789 and $1.301 in
1998 and 1997, respectively.
As of December 31, 1998, options for 36,779 shares of stock were
immediately exercisable. No options where granted in 1998. Pursuant to the
requirements of FASB No. 123, the weighted average fair market value of
options granted during 1997 and 1996 are $2.66 and $2.50, respectively.
The closing bid prices for the Company's stock at the date the options
were granted during 1997 and 1996 are $4.50 and $4.69, respectively. The
fair market value pursuant to FASB No. 123 of each option granted is
estimated on the date of grant using the Black-Scholes options-pricing
model. The model assumed expected volatility of 80% and 67% and risk-free
interest rates of 3.75% and 5.89% for grants in 1997 and 1996,
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
46
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
be at or near the value estimated by the Black-Scholes model.
As discussed in note 1, no compensation expense has been recorded in 1998,
1997, and 1996 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, 1995 under
those plans, the Company's net income (loss) and earnings (loss) per share
would have been reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
----------- --------- --------
<S> <C> <C> <C>
Net income (loss) As reported $(9,059,979) $ 983,095 $ 92,302
Pro forma (9,172,801) 821,555 (33,483)
Basic earnings (loss) As reported (2.02) 0.22 (0.06)
per share Pro forma (2.04) 0.18 (0.10)
Diluted earnings As reported (2.02) 0.22 (0.06)
(loss) per share Pro forma (2.04) 0.18 (0.10)
</TABLE>
Outstanding options at December 31, 1998 expire between August 9, 1999 and
December 25, 2002.
Under the provisions of SFAS No. 123, the pro forma disclosures above
include only the effects of stock options granted by the Company
subsequent to December 31, 1994. During this initial phase-in period, the
pro forma disclosures as required by SFAS No. 123 are not representative
of the effects on reported net income for future years as options vest
over several years and additional awards are generally made each year and
there is a risk of forfeiture.
(9) RELATED PARTY TRANSACTIONS
Related party transactions which are not disclosed elsewhere in these
consolidated financial statements are discussed in the following
paragraph.
In 1992, the Company entered into a contract with a company, in which a
director of the Company is a principal, for business development
consulting services. The Company paid $71,250, $90,000 and $91,600 under
the contract in 1998, 1997 and 1996, respectively. The contract was
terminated October 15, 1998.
47
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(10) LEASES
The Company has various noncancelable operating leases which continue
through 2006.
The following is a schedule of future minimum lease payments required
under noncancelable operating leases at December 31, 1998:
YEARS ENDING
DECEMBER 31,
------------
1999..................... $ 136,310
2000..................... 136,310
2001..................... 136,310
2002..................... 136,310
Thereafter............... 595,723
----------
$1,140,963
==========
Rental expense under operating leases for the years indicated are as
follows:
YEARS ENDING
DECEMBER 31,
------------
1998..................... $ 119,490
1997..................... 222,838
1996..................... 213,603
(11) COMMITMENTS AND CONTINGENCIES
In 1993, the United States Department of the Interior, Minerals Management
Service (MMS) required the Company's wholly-owned subsidiary, Blue Dolphin
Exploration Company (BDEX), to provide additional security to ensure it
could meet the future abandonment and site clearance obligations
associated with the Buccaneer Field. In February 1994, BDEX and the MMS
agreed on the form of such security and the amount of the future
obligations.
As additional security for the future Buccaneer Field abandonment and site
clearance obligations, in February 1994, BDEX provided the MMS with a
$700,000
48
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
supplemental surety bond. In October 1996, BDEX provided the MMS with an
additional $600,000 supplemental surety bond.
Additionally, a sinking fund was established in 1994 wherein $250,000
annually will be set aside until a total of approximately $2,400,000 has
been accumulated to meet end of lease abandonment and site clearance
obligations. The Company estimates the remaining useful life of its major
Buccaneer Field facilities to be in excess of ten years.
In July 1994, BDEX entered into a Regional 3-D Seismic Data Acquisition
and Purchase Agreement with a third-party provider of seismic data. The
term of the agreement is 5 years and provides BDEX access to the
third-party's 3-D and 2-D seismic data base. At December 31, 1998, BDEX's
minimum commitment during the remainder of the agreement is $450,000.
The Company is involved in various claims and legal actions arising in the
ordinary course of business. In the opinion of management, the ultimate
disposition of these matters will not have a material effect on the
Company's financial position.
(12) BUSINESS SEGMENT INFORMATION
The Company's income producing operations are conducted in two principal
business segments: oil and gas exploration and production, and pipeline
operations. Intersegment revenues consist of transportation, general
processing and storage fees charged by certain subsidiaries to another for
natural gas and crude oil transported through the Blue Dolphin Pipeline
System. The intercompany revenues and expenses are eliminated in
consolidation. Information concerning these segments for the years ended
December 31, 1998, 1997, and 1996 is as follows:
49
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<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, 1998:
Oil and gas exploration
and production ... $ 777,829 8,000 (12,448,875) 5,253,370 179,384
Pipeline operations .. 2,818,921 29,976 739,610 2,453,396 193,086
Other ................ (37,977) (341,377) 7,475,044 28,512
----------- ----------- ------------ ----------------
Consolidated ......... 3,558,773 -- (12,050,642) 15,181,810 400,982
Other income (expense) (109,147)
-----------
Loss before income taxes (12,159,789)
Year ended December 31, 1997:
Oil and gas exploration
and production ... $ 828,013 8,000 (384,459) 16,485,333 174,988
Pipeline operations .. 4,192,343 29,750 2,308,995 2,432,416 169,873
Other ................ (37,750) (438,681) 6,009,514 27,391
----------- ----------- ------------ ----------------
Consolidated .............. 4,982,606 -- 1,485,855 24,927,263 372,252
Other income (expense) 43,471
-----------
Income before income taxes 1,529,326
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
Other ................ (40,340) (451,565) 4,790,273 52,760
----------- ----------- ------------ ----------------
Consolidated ......... 4,128,568 -- 48,439 24,226,611 388,406
Other income (expense) -- 106,652
-----------
Income before income taxes 155,091
</TABLE>
(1) Consolidated income from operations includes $273,600, $373,040 and
$358,465 in unallocated general and administrative expenses, and
unallocated depletion, depreciation and amortization of $28,512,
$27,392 and $52,760 for the years ended December 31, 1998, 1997 and
1996, respectively.
(2) Pipeline depletion, depreciation and amortization includes a
provision for pipeline abandonment of $26,340, for each of the years
ended December 31, 1998, 1997 and 1996. Oil and gas depletion,
depreciation and amortization includes a provision for abandonment
costs of platforms and wells of $56,718, $28,466 and $29,190 for the
years ended December 31, 1998, 1997 and 1996, respectively.
50
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
See the supplemental disclosures for oil and gas producing activities for
discussion of capitalized costs incurred for oil and gas production
operations. Capital expenditures of $144,516 were incurred for pipeline
operations for the year ended December 31, 1998.
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:
51
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
OIL AND GAS
SALES AND PIPELINE
OPERATING FEES OPERATIONS TOTAL
-------------- ------------- ---------
<S> <C> <C> <C>
Apache Corporation ..... $ 333,787 1,504,375 1,838,162
The Dow Chemical Company 391,913 46,119 438,032
Burlington Resources ... -- 429,186 429,186
Apache Corporation ..... $ 359,376 1,466,621 1,825,997
The Coastal Corporation 39,905 1,111,885 1,151,790
Burlington Resources ... -- 642,492 642,492
The Dow Chemical Company 393,443 114,381 507,824
The Coastal Corporation $ 49,085 1,281,147 1,330,232
Apache Corporation ..... 401,265 696,319 1,097,584
The Dow Chemical Company 342,119 120,636 462,755
</TABLE>
(13) SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
The following supplemental information regarding the oil and gas
activities of the Company is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange Commission (SEC)
and SFAS No. 69 DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
(Statement 69).
At December 31, 1998, 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.
52
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Set forth below is a summary of the changes in the estimated quantities of
the Company's crude oil and condensate, and natural gas reserves for the
periods indicated, as estimated by the Company's independent petroleum
engineer, Gerald W. DuPont Enterprises, Inc. All of the Company's reserves
are located within the United States. Proved reserves cannot be measured
exactly because the estimation of reserves involves numerous judgmental
determinations. Accordingly, reserve estimates must be continually revised
as a result of new information obtained from drilling and production
history, new geological and geophysical data and changes in economic
conditions.
Proved reserves are estimated quantities of natural gas, crude oil, and
condensate which geological and engineering data demonstrate, with
reasonable certainty, to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved
developed reserves are proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
OIL GAS
QUANTITY OF OIL AND GAS RESERVES (BBLS) (MCF)
------------------------------------------ -------- -----------
Total proved reserves at December 31, 1995 202,166 33,097,136
-------- -----------
Revisions to previous estimates .......... (6,477) (201,823)
Production ............................... (1,887) (180,269)
-------- -----------
Total proved reserves at December 31, 1996 193,802 32,715,044
-------- -----------
Revisions to previous estimates .......... (8,500) (1,125,504)
Production ............................... (1,156) (176,986)
-------- -----------
Total proved reserves at December 31, 1997 184,146 31,412,554
======== ===========
Revisions to previous estimates .......... 6,743 (40,387)
Production ............................... (1,628) (177,260)
-------- -----------
Total proved reserves at December 31, 1998 189,261 31,194,907
======== ===========
Proved developed reserves:
December 31, 1998 ...................... 113,183 18,070,961
December 31, 1997 ...................... 108,068 18,288,608
December 31, 1996 ...................... 117,724 19,591,098
53
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CAPITALIZED COSTS OF OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the aggregate amounts of capitalized costs
relating to the Company's oil and gas producing activities and the
aggregate amount of related accumulated depletion, depreciation and
amortization as of the dates indicated:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1998 1997
------------ -----------
<S> <C> <C>
Unproved properties and prospect generation
costs not being amortized .............. $ 2,823,357 2,180,306
Proved properties being amortized ........ 18,387,449 18,287,197
Less accumulated depletion, depreciation,
amortization and impairment ............ (15,957,436) (3,982,170)
------------ -----------
Net capitalized costs ............. $ 5,253,370 16,485,333
============ ===========
Accrued offshore platform and
well abandonment costs ................. $ (292,081) (297,458)
</TABLE>
At December 31, 1998 the Company recorded an impairment charge on its oil
and gas properties and certain exploration activity costs of $12,011,544,
resulting from lower oil and gas prices and changes to its development
plans, whereby development of oil and gas properties have been deferred.
54
(Continued)
<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,
----------------------------
1998 1997 1996
-------- ------- -------
Property acquisition costs - unproved
properties and prospect generation $ -- 471,861 584,728
Exploration costs ................... 277,501 -- --
Development costs ................... -- 23,685 105,069
-------- ------- -------
$277,501 495,546 689,797
======== ======= =======
Depletion expense per Mcf
equivalent produced ........ $ 1.03 0.95 0.97
======== ======= =======
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,
---------------------------
1998 1997
------------ -----------
Future cash inflows ................ $ 60,296,555 71,531,303
Future development costs ........... (9,782,601) (9,807,601)
Future production costs ............ (25,093,865) (13,666,735)
------------ -----------
Future net cash inflows
before income taxes ............. 25,420,089 48,056,967
Future income taxes ................ (213,271) (14,457,358)
------------ -----------
Future net cash flows .............. 25,206,818 33,599,609
10% discount factor ................ (19,022,516) (16,686,802)
------------ -----------
Standardized measure of discounted
future net cash inflow ....... $ 6,184,302 16,912,807
============ ==========
Future net cash flows at each year end, as reported in the above schedule,
were
55
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1998, such prices were $10.03
per barrel of oil and $1.87 per Mcf of gas) and (2) deducting estimated
expenditures to be incurred during each year to develop and produce the
proved reserves (based on current costs). Income taxes were computed by
applying year-end statutory rates to pretax net cash flows, reduced by the
tax basis of the properties and available net operating loss
carryforwards. The annual future net cash flows were discounted, using a
prescribed 10% rate, and summed to determine the standardized measure of
discounted future net cash flows.
The Company cautions readers that the standardized measure information
which places a value on proved reserves is not indicative of either fair
market value or present value of future cash flows. Other logical
assumptions could have been used for this computation which would likely
have resulted in significantly different amounts. Such information is
disclosed solely in accordance with Statement 69 and the requirements
promulgated by the SEC to provide readers with a common base for use in
preparing their own estimates of future cash flows and for comparing
reserves among companies. Management of the Company does not rely on these
computations when making investment and operating decisions.
56
(Continued)
<PAGE>
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Principal changes in the STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS attributable to the Company's proved oil and gas reserves for
the periods indicated are as follows
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------------
1998 1997 1996
------------ ---------- ----------
<S> <C> <C> <C>
Sales and transfers, net of production costs * .. $ 433,346 489,564 996,305
Net change in estimated future development
costs ...................................... 18,918 165,389 (105,110)
Net change in income taxes ...................... 5,322,055 267,388 (1,748,864)
Revisions in previous quantity estimates ........ 34 (996,557) (209,443)
Net changes in sales and transfer prices,
net of production costs .................... (10,944,737) (548,223) 5,566,602
Accretion of discount ........................... 2,277,393 2,432,226 1,885,846
Change in production rates (timing)
and other .................................. (7,835,514) (3,090,710) (2,670,405)
------------ ---------- ----------
Net change .......................... $(10,728,505) (1,280,923) 3,714,931
============ ========== ==========
</TABLE>
* 6% of the Company's estimated proved oil reserves and 7% of its
estimated proved gas reserves were being produced at December 31, 1998
57
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 is incorporated by reference to the
Company's definitive proxy statement relating to its 1999 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 1999 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 1999 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 1999 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.
58
<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, 1998
and 1997......................................................28
Consolidated Statements of Operations, for the
years ended December 31, 1998, 1997, and 1996.................30
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1998, 1997, and 1996.................31
Consolidated Statements of Cash Flows, for the
years ended December 31, 1998, 1997, and 1996.................32
Notes to Consolidated Financial Statements......................33
59
<PAGE>
(a) 3.Exhibits:
NO. DESCRIPTION
3.1 (1) Certificate of Incorporation of the Company
3.2 (2) Certificate of Correction to the Certificate of Incorporation of
the Company dated June 30, 1987
3.3 (2) Certificate of Amendment to the Certificate of Incorporation of
the Company dated June 30, 1987
3.4 (2) Certificate of Amendment to the Certificate of Incorporation of
the Company dated December 11, 1989
3.5 (2) Certificate of Amendment to the Certificate of Incorporation of
the Company dated December 14, 1989
3.6 (2) Bylaws of the Company
3.7 (8) Certificate of Amendment to the Certificate of Incorporation of
the Company dated December 8, 1997.
4.1 (2) Specimen Certificate of Blue Dolphin Energy Company Common Stock
10.1 (1) Blue Dolphin Energy Company 1985 Employee Stock Option Plan
10.2 (7) Blue Dolphin Energy Company 1996 Employee Stock Option Plan
10.3 (3) Gas Purchase Agreement between Dow Chemical Company and Ivory
Production Co. dated May 1, 1991
10.4 (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
10.5 (5) Plan and Agreement of Merger between Petroport, L.C. and Blue
Dolphin Acquisition Company dated March 8, 1995
10.6 (6) First Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission
Energy, Inc., Ivory Production Co., Blue Dolphin Services Co., and
Bank One, Texas, N.A., dated February 7, 1995
10.7 (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
60
<PAGE>
10.8 (7) Third Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission
Energy, Inc., Blue Dolphin Exploration Company, previously known
as Ivory Production Co., Blue Dolphin Services Co., and Bank One,
Texas, N. A., dated November 5, 1996.
10.9 (9) Asset Purchase Agreement between WBI Southern, Inc., Blue Dolphin
Pipeline Company, Buccaneer Pipe Line Co. and Mission Energy, Inc.
10.10 (9) Purchase and Sale Agreement between Enron Pipeline Company, Black
Marlin Energy Company and Blue Dolphin Energy Company
10.11 (9) Asset Purchase Agreement between WBI Southern, Inc., Black Marlin
Pipeline Company and Black Marlin Energy Company
10.12 (9) Asset Purchase Agreement between MCNIC Offshore Pipeline &
Processing Company, Black Marlin Pipeline Company and Black Marlin
Energy Company
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
(Commission File No. 000-15905).
(3) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1991
under the Securities and Exchange Act of 1934, dated March 27, 1992
(Commission File No. 000-15905).
(4) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1993
under the Securities and Exchange Act of 1934, dated March 30, 1994
(Commission File No. 000-15905).
(5) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1994
under the Securities and Exchange Act of 1934, dated March 28, 1995
(Commission File No. 000-15905).
(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
(Commission File No. 000-15905).
(7) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1996
under the Securities and Exchange Act of 1934, dated March 31, 1997
(Commission File No. 000-15905).
61
<PAGE>
(8) Incorporated herein by reference to Exhibits filed in connection with the
definitive Information Statement on Schedule 14C of Blue Dolphin Energy
Company under the Securities and Exchange Act of 1934, dated November 18,
1997 (Commission File No. 000-15905).
(9) Incorporated herein by reference to Exhibits filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated March 1, 1999 (Commission File No. 000-15905).
* Management Compensation Plan.
(b) Reports on Form 8-K
None
62
<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 30, 1999
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 30, 1999
Michael J. Jacobson executive officer)
/s/ G. BRIAN LLOYD Vice President, Treasurer March 30, 1999
G. Brian Lloyd (principal accounting officer)
/s/ IVAR SIEM Chairman March 30, 1999
Ivar Siem
/s/ HARRIS A. KAFFIE Director March 30, 1999
Harris A. Kaffie
/s/ DANIEL B. PORTER Director March 30, 1999
Daniel B. Porter
/s/ MICHAEL S. CHADWICK Director March 30, 1999
Michael S. Chadwick
63
EXHIBIT 23.1
GERALD DUPONT ENTERPRISES, INC.
PETROLEUM ENGINEER
P.O. BOX 1590
SUGAR LAND, TEXAS 77487-1590
------
(281) 240-2822 FAX (281) 242-2822
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
Gerald W. DuPont Enterprises, Inc. consents to the incorporation by
reference of our evaluation of the estimated reserves and future net
revenues of certain interests owned by Blue Dolphin Energy Company
in the Galveston Block 288 Field, dated December 31, 1998, included
in the Annual Report on Form 10-K of Blue Dolphin Energy Company for
the year ended December 31, 1998.
/s/ GERALD W. DUPONT
Petroleum Engineer
MARCH 25, 1999
Date
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BLUE DOLPHIN
ENERGY COMPANY AND SUBSIDIARIES CONSOLIDATED FINANCIAL STATEMENTS AND
INCORPORATED HEREIN BY REFERENCE.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 593,509
<SECURITIES> 0
<RECEIVABLES> 771,268
<ALLOWANCES> 0
<INVENTORY> 5,248
<CURRENT-ASSETS> 1,522,365
<PP&E> 26,113,611
<DEPRECIATION> 17,172,057
<TOTAL-ASSETS> 15,181,810
<CURRENT-LIABILITIES> 1,417,822
<BONDS> 2,060,600
0
0
<COMMON> 45,046
<OTHER-SE> 11,549,748
<TOTAL-LIABILITY-AND-EQUITY> 15,181,810
<SALES> 412,753
<TOTAL-REVENUES> 3,558,773
<CGS> 862,523
<TOTAL-COSTS> 15,609,415
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 215,141
<INCOME-PRETAX> (12,159,326)
<INCOME-TAX> (3,099,810)
<INCOME-CONTINUING> (9,059,979)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (9,059,979)
<EPS-PRIMARY> (2.02)
<EPS-DILUTED> (2.02)
</TABLE>
