UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Act of 1934
For the fiscal year ended December 31, 2002
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
(Name of small business issuer 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)
Issuer's telephone number (713) 227-7660
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act:
common stock, $.01 par value
(Title of Class)
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 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 [ ]
Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. [X]
The issuer's revenues for the year ended December 31, 2002 were $2,910,277.
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of March 13, 2003, was approximately $1,923,264.
As of March 13, 2003, there were outstanding 6,606,585 shares of common
stock, par value $.01 per share, of the issuer.
Documents Incorporated By Reference
The registrant's definitive proxy statement for the 2003 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
Forward Looking Statements. Certain of the statements included in this
annual report on Form 10-KSB, including those regarding future financial
performance or results or that are not historical facts, are "forward-looking"
statements as that term is defined in Section 21E of the Securities Exchange Act
of 1934, as amended, and Section 27A of 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. Blue
Dolphin Energy Company (referred to herein, with its predecessors and
subsidiaries, as "Blue Dolphin" or the "Company") cautions readers that any such
statements are not guarantees of future performance or events and such
statements involve risks and uncertainties that may cause actual results and
outcomes to differ materially from those indicated in forward-looking
statements. Some of the important factors, risks and uncertainties that could
cause actual results to vary from forward-looking statements include:
o the risks associated with exploration;
o gas and oil price volatility;
o uncertainties in the estimation of proved reserves and in the
projection of future rates of production and timing of development
expenditures;
o availability and cost of capital;
o actions or inactions of third party operators for properties where the
Company has an interest;
o regulatory developments; and
o general economic conditions.
Additional factors that could cause actual results to differ materially from
those indicated in the forward-looking statements are discussed under the
caption "Risk Factors". 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 duty to update these forward-looking statements. Readers
are urged to carefully review and consider the various disclosures made by the
Company which attempt to advise interested parties of the additional factors
which may affect the Company's business, including the disclosures made under
the caption "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in this report.
THE COMPANY
The Company conducts its business activities in two primary business segments:
(i) oil and gas exploration and production, and (ii) pipeline operations, which
includes developmental projects. The Company is a holding company that conducts
substantially all of its operations through its subsidiaries. Substantially all
of the Company's assets consist of equity in its subsidiaries. The Company's
subsidiaries and affiliates are as follows:
o American Resources Offshore, Inc., a Delaware corporation;
o Blue Dolphin Petroleum Company, a Delaware corporation;
o Blue Dolphin Exploration Company, a Delaware corporation;
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o Blue Dolphin Pipe Line Company, a Delaware corporation;
o Blue Dolphin Services Co., a Texas corporation;
o Petroport, Inc., a Delaware corporation;
o New Avoca Gas Storage, LLC, a Texas limited liability company in which
the Company owns a 25% interest; and
o Drillmar, Inc., a Delaware corporation in which the Company owns a
12.8% interest.
Effective January 1, 2002, two wholly owned subsidiaries, Mission Energy,
Inc. and Buccaneer Pipe Line Co. were merged into Blue Dolphin Pipe Line
Company.
The principal executive office of the Company is located at 801 Travis,
Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660. Shore based
facilities are maintained in Freeport, Texas serving Gulf of Mexico operations.
The Company has 11 full-time employees. The Company's common stock is traded on
the National Association of Securities Dealers, Inc. Automated Quotation System
("NASDAQ") Small Cap Market under the trading symbol "BDCO". The Company's home
page address on the world wide web is http://www.blue-dolphin.com.
Recent Developments
Sale of Oil and Gas Properties. During 2002, American Resources sold all of
its interests in its oil and gas properties in two separate transactions
described below. These properties represented over 99% of the Company's proved
oil and gas reserves. The Company's remaining oil and gas properties consist of
working interests in several exploratory lease blocks located offshore Louisiana
in the Gulf of Mexico and reversionary working interests in certain exploratory
and producing lease blocks located offshore Texas in the Gulf of Mexico.
In July 2002, American Resources sold its working interest in the South
Timbalier Block 148 property for $2.3 million to Newfield Exploration Company.
Production from this field accounted for 15% and 19% of the Company's oil and
gas sales revenues and 9% and 16% of the Company's total revenues for the years
ended December 31, 2002 and 2001, respectively. In November 2002, American
Resources sold its working interest in all of its remaining proved oil and gas
properties for $2.7 million to Fidelity Exploration & Production Company.
Production from these fields accounted for 85% and 81% of the Company's oil and
gas sales revenues and 52% and 67% of the Company's total revenues for the years
ended December 31, 2002 and 2001, respectively. As a result of these
transactions, the Company will be primarily dependent on revenues generated from
its pipeline operations and reversionary interest in oil and gas properties.
Abandonment of Buccaneer Field. The Company owned a 100% working interest
in the Buccaneer Field. The Company conducted traditional oil and gas production
operations for itself, and operated and maintained oil and gas production
facilities at the Buccaneer Field for third party producers who utilized the
Blue Dolphin Pipeline System for gathering and transportation of their
production. In November 2000 the Company decided to abandon and not reestablish
production from the Buccaneer Field. As a result of this decision, the leases in
this field terminated in January 2001 pursuant to their terms, and the Company's
third party operation and maintenance services contract was terminated in
December 2000.
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As a result of the termination of the Company's leases in or around the
Buccaneer Field, the Company must plug and abandon all remaining wells and
remove platform facilities. Blue Dolphin Exploration provided the U.S. Minerals
Management Service ("MMS") surety bonds in the amount of $4.2 million for its
abandonment obligations. The rules and regulations of the MMS require that the
Company complete the plugging and abandonment within one year after termination
of the leases.
During removal of the platform complexes in October 2001, the Company
initiated discussions with the Texas Parks and Wildlife Department ("TPW") in an
effort to leave certain underwater portions of the platform complexes in place
as artificial reefs. In December 2001, operations to remove the platform
complexes were suspended while the Company continued its discussions with the
TPW. By leaving the platform complexes in place as artificial reefs, certain
site clearance costs will be eliminated. On January 3, 2003, the Company and TPW
executed deeds of donation for both of the Company's platform complexes in the
Buccaneer Field, whereby the Company will leave certain of the underwater
portions of the platforms in place as artificial reefs and donate them to the
TPW. The Company requested and has received an extension from the MMS until
April 1, 2003 to complete the abandonment operations needed to convert the
platform complexes into artificial reefs. Remaining abandonment operations
include mechanically severing the upper section of the platform jackets and well
casings at a minimum of minus 50 feet from the water's surface, cutting the
severed pieces into sections that meet the clearance requirement, and placing
those sections on the seafloor near the base of the platform jackets. The work
to complete the abandonment/reefing is expected to begin and be completed during
the second quarter 2003. The Company will seek a further extension from the MMS.
Until abandonment operations were suspended in December 2001, significant
progress was made. Both platform complexes consisted of production platform with
a bridge connected quarters platform. At the complex located in GA Block 288,
the decks on both the production and quarters platforms and the bridge have been
removed. At the complex located in GA Block 296, the deck on the quarters
platform, a portion of the deck on the production platform and the bridge have
been removed.
Pipeline Operations and Activities
The Company's pipeline assets are held and operations conducted by Blue
Dolphin Pipe Line Company. Effective January 1, 2002, Mission Energy and
Buccaneer Pipe Line, which held pipeline assets, were merged into Blue Dolphin
Pipe Line Company, where all of the Company's pipeline assets are now held.
The economic return to the Company on its pipeline system investments is
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 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.
Blue Dolphin Pipeline System. The Company owns an 83% undivided interest in
the Blue Dolphin Pipeline System (the "Blue Dolphin System"). The Blue Dolphin
System includes the Blue Dolphin Pipeline, Buccaneer Pipeline, onshore
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facilities for condensate and gas separation and dehydration, 85,000 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 where the pipeline system shore
facilities, pipeline easements and rights-of-way are located.
The Blue Dolphin System gathers and transports gas and condensate from
various offshore fields in the Galveston Area in the Gulf of Mexico 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.
The Blue Dolphin Pipeline consists of two segments. The offshore segment
transports both gas and condensate and is comprised of approximately 34 miles of
20-inch pipeline from a platform in GA Block 288 to shore. An additional 4 miles
of 20 inch pipeline connect the offshore segment to the shore facility at
Freeport, Texas. In 2001, Blue Dolphin Pipe Line Company installed a platform in
GA Block 288 to operate and maintain the Blue Dolphin Pipeline System as a
result of the Company's decision to abandon and remove the Buccaneer Field
platforms in GA Blocks 288 and 296, which were previously used to operate and
maintain the Blue Dolphin System. The installation of the platform and its
connection to the Blue Dolphin System cost approximately $1.7 million net to the
Company's interest. Additionally, the offshore segment includes 5 field
gathering lines totaling approximately 27 miles, connected to the main 20-inch
line. This system's onshore segment consists of approximately 2 miles of 16-inch
pipeline for transportation of 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 gas throughput
averaged approximately 9% and 16% of capacity during 2002 and 2001,
respectively. Current system capacity is approximately 160 MMcf per day of gas
and 7,000 Bbls per day of condensate. During 2002, 100% of gas and condensate
volumes transported were attributable to production from third party
producer/shippers. See Note 11 to Consolidated Financial Statements included in
Item 7.
In February 2002, the Company's interest in the Blue Dolphin System was
increased from 50% to 83% by acquiring a 1/3 interest in the Blue Dolphin System
and the inactive Omega Pipeline from MCNIC Pipeline and Processing Company
("MCNIC").
Black Marlin Pipeline System. In January 2001, the Company and its
partners, MCNIC and WBI Holdings, Inc. ("WBI") sold the Black Marlin Pipeline
System and the High Island Block A-5 pipeline to Williams Field Services for
$9.3 million. The Company through wholly-owned subsidiaries owned a 50% interest
in these assets and received $4.6 million for its interest. The Black Marlin
Pipeline System included 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 five 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. See Note 13 to Consolidated Financial Statements included in
Item 7.
In July 2000, the Company reached an agreement to provide transportation
services for Vastar Resources, Inc. in High Island Area Block A-5, offshore
Texas in the Gulf of Mexico. To accommodate this production, the Company
constructed a 3.4 mile 12" diameter pipeline from the production platform in
5
High Island Area Block A-5 to the Black Marlin Pipeline. The cost to construct
the pipeline was approximately $1.9 million, $.9 million net to the Company's
50% interest in the pipeline. The pipeline was completed in September 2000. See
Note 13 to Consolidated Financial Statements included in Item 7.
Galveston Area Block 350 Pipeline. In July 2000, the Company acquired an
83% ownership interest in an 8-inch, 12.78 mile pipeline extending from
Galveston Area Block 350 to an interconnect to a transmission pipeline in GA
Block 391 (the "GA350 Pipeline"), approximately 14 miles south of the Company's
Blue Dolphin Pipeline for $224,000. The pipeline currently transports
approximately 8,000 Mcf of gas per day.
Other. The Company also holds an 83% undivided interest in the currently
inactive Omega Pipeline. The Omega Pipeline originates in West Cameron Block 342
and extends to High Island Area, East Addition Block A-173, where it was
previously connected to the High Island Offshore System ("HIOS"). The line 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.
Reactivation of the Omega Pipeline will be dependent upon future drilling
activity in the vicinity and successfully attracting reserves to the system.
Oil and Gas Exploration and Production Activities
The Company's oil and gas assets are held by Blue Dolphin Petroleum and
Blue Dolphin Exploration. 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 focuses its
oil and gas acquisitions and exploration activities in the western and central
Gulf of Mexico, and onshore Texas and Louisiana. The leasehold interests in
properties held by the Company are subject to royalty, overriding royalty and
interests of others. In the future, the Company's properties may become subject
to burdens and encumbrances typical to oil and gas operators, such as liens
incident to operating agreements and current taxes, development obligations
under oil and gas leases and other encumbrances.
Certain terms that are commonly used in the oil and gas industry, including
terms that define the Company's rights and obligations with respect to each of
its properties, are defined in the "Glossary of Certain Oil and Gas Terms" on
pages 22, 23 and 24 of this Form 10-KSB.
The following is a description of the Company's oil and gas exploration and
production assets and activities:
Offshore Oil and Gas Prospect Generation Activities. Effective, December
31, 2000 the Company suspended its prospect generation program as a result of
the withdrawal of its partner. The program developed oil and gas exploration
prospects in the Gulf of Mexico for sale to third parties. In addition to
recovering prospect development costs, the Company sought to retain a
reversionary working interest in each drillable prospect it sold through this
program. As a result of the withdrawal of the Company's partner from its
prospect generation program, effective December 31, 2000 this program was
suspended. Although the program is suspended the Company has seismic and other
data to evaluate and develop prospects, including a non-exclusive license to 200
blocks of 3-D seismic data covering 1,152,000 acres in the western Gulf of
Mexico and a substantial inventory of close grid 2-D seismic data.
In January 2001, the Company entered into a consulting agreement with
Cheyenne Petroleum Co., whereby the Company's remaining prospect generation
staff provided technical consulting services to Cheyenne in the evaluation of
prospects for the March 2001 central Gulf of Mexico federal lease sale. In
6
exchange, Cheyenne reimbursed the Company for personnel costs and allowed the
Company to participate in prospects generated with a 5% working interest in four
undeveloped offshore blocks. This agreement terminated April 30, 2001.
Unproved Leasehold Interests. The Company's leased prospect inventory,
which it continues to market, consists of prospects on the following offshore
leases:
o East Cameron Area Block 90
o East Cameron Area Block 94
o West Cameron Area Block 212
o Mustang Island Area Block 817
o Mustang Island Area Block 839
The Company has reversionary working interests in several offshore leases
after payout. These leases are:
o Galveston Area Block 297
o Galveston Area Block 271
o Galveston Area Block 284
o Galveston Area Block 285
o Matagorda Island Area Block 710
o Matagorda Island Area Block 713
Other. In connection with Blue Dolphin Exploration's acquisition of a
controlling interest in American Resources in December 1999, Fidelity Oil
acquired an 80% interest in American Resources oil and gas assets located in the
Gulf of Mexico for approximately $24.2 million and agreed to assign Blue Dolphin
Exploration 10% of its working interest in the proved properties of American
Resources after it recovered its investment in these properties. In addition,
Fidelity Oil agreed to assign Blue Dolphin Exploration 15% of its working
interest in each exploratory property after Fidelity recovered its investment in
these exploratory properties on a property by property basis.
In the fourth quarter 2001, Fidelity Oil recovered its investment in the
proved properties. However, instead of assigning 10% of its interest in the
proved properties, Fidelity paid Blue Dolphin $1.4 million in December 2001, for
the property interest owed to Blue Dolphin.
At December 31, 2002, there was one such exploratory property remaining
located in High Island Area Block 34. A successful well was drilled on this
property in late 2002, with further drilling expected in 2003. If payout occurs,
the Company would receive an approximate 1.8% working interest.
High Island Block A-7. The Company previously announced a gas discovery in High
Island Area Block A-7, in the Gulf of Mexico. The Company owns an 8.9%
reversionary working interest in this field and it will begin to receive
revenues from its reversionary interest after "payout" occurs. Payout occurs
after all of the other working interest owners have recovered their costs and
expenses associated with developing the field from sales of gas and oil
production from the field. In late 2002, two wells from this field were
successfully recompleted. As a result of the two recompleted wells and based on
current levels of production and commodity prices, the Company now believes that
it could begin to receive revenues from its reversionary working interest in
this field in mid 2003.
7
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, 2002, by the
Company.
The quantities of proved gas and oil reserves presented below 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 at prices and costs, and under regulatory practices and
technology existing at the time of the estimate. Accordingly, changes in oil and
gas prices, operation and development costs, regulations, technology, future
production and other factors, many of which are beyond the Company's control,
could significantly affect the estimates of proved reserves and the discounted
present value of future net revenues attributable thereto.
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 12 - Supplemental Oil and Gas Information to Consolidated Financial
Statements included in Item 7.
The following table presents the estimates of Proved Reserves, Proved
Developed Reserves, and Proved Undeveloped 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, 2002. The discounted present value of
future net revenues and future net revenues are calculated using the SEC Method
(defined above) and are not intended to represent the current market value of
the oil and gas reserves the Company owns.
PROVED RESERVES
As of December 31, 2002 (1) (3)
Discounted
Net Oil Net Gas Future Present Value of Future
Reserves Reserves Net Revenues Net Revenues (2)
(Mbbls) (Mmcf) (in thousands) (in thousands)
---------------------------------------------------------------
Total Proved Reserves 1.4 280 757 $ 748
========== ========== ========== ==========
Total Proved Developed
Reserves 1.4 280 757 $ 748
========== ========== ========== ==========
(1) As of December 31, 2002, all of the Company's proved reserves are from its
8.9% reversionary interest in the High Island Block A-7 field.
(2) The estimated discounted present value of future net revenues before
deductions for income taxes from the Company's Proved Reserves have been
determined by using prices of $32.36 per barrel of oil and $4.83 per Mcf of
gas, representing the December 31, 2002 prices for oil and gas 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").
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(3) As of December 31, 2002, the Company reported no proved undeveloped
reserves.
Capital Expenditures for Proved Reserves. The following table presents
information regarding the costs the Company expects to incur in development
activities associated with its proved reserves. These expenditures include
recompletion costs, workover costs and the cost of drilling additional wells
required to recover proved reserves. The information regarding proved reserves
summarized in the preceding table assumes the following estimated capital
expenditures in the years indicated.
Estimated Capital Expenditures To Develop Proved Reserves
For the years ending December 31,
(in thousands)
-----------------------------------------------------------
2003 2004 2005 2006 2007
---- ---- ---- ---- ----
High Island Block A-7 0 $150 0 $192 0
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 and the willingness of other
working interest owners to participate in development operations may affect the
Company's timing for further development, and there can be no assurance that the
timing of the development of such reserves will be as currently planned.
Production, Price and Cost Data. The following table presents information
regarding production volumes and revenues, average sales prices and costs (after
deduction of royalties and interests of others) with respect to crude oil,
condensate, and gas attributable to the interest of the Company for each of the
periods indicated.
NET PRODUCTION, PRICE AND COST DATA
Year Ended December 31,
-----------------------
2002 (1) 2001 2000
---------------------------------------
Gas:
Production (Mcf) 418,895 815,184 911,671
Revenue $ 1,221,168 $ 3,607,910 $ 3,674,192
Average Production (Mcf) per day 1,147.7 2,233.4 2,490.9
Average Sales Price
Per Mcf $ 2.92 $ 4.43 $ 4.03
Oil:
Production (Bbls) 28,230 40,769 64,707
Revenue $ 560,790 $ 1,086,292 $ 1,844,948
Average Production (Bbls) per day 77.3 111.7 176.8
Average Sales Price
Per Bbl $ 19.87 $ 26.65 $ 28.51
Production Costs (2):
Per Mcfe: $ 0.88 $ 1.06 $ 1.05
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(1) See "Recent Developments."
(2) Production costs, exclusive of workover costs, are costs incurred to
operate and maintain wells and equipment and to pay production taxes.
Drilling Activity. During fiscal 2002 there was no drilling activity. The
following table shows the Company's drilling activity for 2001. "Gross" as it
applies to wells refers to the number of wells in which a working interest is
owned, while "net" applies to the sum of the fractional working interests in
gross wells.
Exploratory Wells Drilled Developmental Wells Drilled
-------------------------------------------- --------------------------------------------
Productive Dry Productive Dry
-------------------------------------------- --------------------------------------------
Gross Net Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- --------- --------- ---------
2001
----
American Resources -- -- 1 0.06 1 0.1 -- --
Other -- -- -- -- -- -- -- --
The Company maintains professional staff and consultants 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
engineering and construction projects are contracted to third-party engineering
and service companies.
Development Projects
Avoca Gas Storage Project
In November 1999, the Company and WBI formed New Avoca Gas Storage, LLC
("New Avoca"), and acquired the assets of Avoca Gas Storage, Inc. from
Northeastern Gas Caverns ("Northeastern"). The Company has a 25% equity interest
and is the manager of New Avoca. The Company records its investment in New Avoca
by using the equity method of accounting. The existing New Avoca assets include:
o Approximately 900 acres of land located south of Rochester near the
town of Avoca, New York
o Pumps and pipeline for fresh water
o Pump house containing 12 pumps (6,400 HP) for the solution mining
operation
o 7 cavern wells - 4,000 feet deep
o 6 brine disposal wells - 9,000 feet to 11,000 feet deep
o Storage building with valves, fittings, and miscellaneous parts
o Electrical switch gear
o Solution mining equipment
o Compressor foundations
The Avoca salt cavern gas storage project was conceived as a 5 Bcf working
gas storage facility located south of Rochester near the town of Avoca, New
York. Its design provides for 250 Mmcf per day injection and 500 Mmcf per day
withdrawal capacities, with deliveries into the Tennessee Gas Pipeline HC400 24"
line and other area transmission lines.
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To create the gas storage facility salt caverns must be created. To create
the salt caverns, fresh water is injected from the surface to dissolve the salt
formations below. The brine solution produced by this process must be
continuously brought to the surface and then injected into underground disposal
wells or disposed of in some other manner. The disposal wells must have
sufficient porosity and permeability to accept the injected brine at a rate at
least consistent with the rate at which brine is being produced during the
creation of the salt caverns. The original owners of the Avoca gas storage
assets conducted tests to determine the rate that the disposal wells would
accept brine. New Avoca believes that the testing procedures used by the
original owners of the project to analyze the rate at which the disposal wells
could accept brine may have been flawed as a result of the accelerated pace at
which the tests were conducted, and therefore yielded test results that were
uncertain and did not conclusively support an acceptable rate of brine disposal.
The original owners of the Avoca gas storage assets encountered technical and
other difficulties as a result of the uncertainty of their test results. New
Avoca is reviewing additional brine disposal options that could be used to
accelerate the creation of the salt caverns.
During 2000, New Avoca completed an analysis of the project. Based on this
analysis and recent technological advances, New Avoca believes the disposal
wells will be capable of handling the more moderate rates of brine injection
expected to be produced under its proposed construction schedule. From October
2000 through February 2001, New Avoca tested the disposal wells to determine the
rate that these wells will accept brine. In February 2001, as a result of mild
seismic activity in the area surrounding Avoca, the New York State Department of
Environmental Conservation requested that New Avoca stop testing the disposal
wells. New Avoca stopped testing the wells, and does not plan on further testing
at this time. As a viable solution for the brine disposal, New Avoca has studied
the construction of a brine pipeline to deliver brine to a salt plant. New Avoca
believes that a combination of the use of disposal wells and brine deliveries by
pipeline appears to be the most feasible means of brine disposal, and believes
that it can negotiate an agreement with area salt plants to take the brine. In
2002 the Company and WBI began marketing their ownership interest in New Avoca.
If the Company and WBI do not sell their interest in New Avoca, the Company
would need to secure financing in order to proceed with the project. New Avoca
estimates that it will take between 9 months to 15 months for approval of its
permit, and between 21 months to 2 years after approval of its permit to
contract and begin operations at partial capacity, with another 2 years needed
to complete construction and reach the full 5 BCF capacity. There can be no
assurance that the Company and WBI will be able to sell their interest in New
Avoca on acceptable terms or that the Company will be able to secure financing
necessary to proceed with the project.
Offshore Crude Oil Terminalling
Previously, the Company began the development of offshore crude oil terminals.
The Company's efforts focused on two prospective market areas for locating such
a facility: the Greater Houston area, including the Freeport, Texas and Houston
Ship Channel market (the "Petroport" project); and the Beaumont - Port Arthur,
Texas and Westlake - Lake Charles, Louisiana market (the "Sabine Seaport"
project).
The Company elected to discontinue its efforts to develop an offshore crude
oil terminal effective December 31, 2001, due to the lack of market support for
the projects, the Company recorded a full impairment of $1.9 million of its
investment in both the Petroport and Sabine Seaport projects. The Company will
continue market surveillance activities and seek prospective partners to jointly
develop an offshore terminal project, if market conditions warrant such
development in the future.
Drillmar Project
In 2000, the Company, together with other partners, formed Drillmar, Inc.,
to develop mooring solutions which will allow a semi-submersible tender unit to
11
be placed next to a deepwater floating production platform to assist in the
drilling and completion of oil and gas wells. Drillmar has developed a
proprietary mooring system and has patents and patents pending to protect this
technology.
In 2000, Drillmar acquired a 1% general partner interest in Zephyr
Drilling, Ltd., a Texas limited partnership ("Zephyr"). Zephyr owned a
semi-submersible drilling rig. At December 31, 2000, the Company's investment in
Drillmar and the partnership consisted of $25,000 cash and the contribution of
management and administrative services of $50,000.
In May 2001, the Company increased its ownership in Drillmar from 37.5% to
64%. Consideration paid by the Company included cash of approximately $131,000,
and contribution of services in the amount of $434,000.
Effective January 2001, the Company entered into an agreement with Drillmar
whereby it agreed to provide office space and certain management and
administrative services to Drillmar for approximately $40,000 per month. The
Company used the payments it was entitled to receive under this agreement to
fund its investment in Drillmar. The funding of the Company's investment in
Drillmar was completed in October 2001.
In September 2001, Zephyr merged into Drillmar. As a result of the merger,
the Company's interest in Drillmar decreased from 64% to 12.8%.
Ivar Siem, Chairman of the Company, Harris A. Kaffie and James M. Trimble,
Directors of the Company, were limited partners of Zephyr. After the merger
between Drillmar and Zephyr, Messers. Siem, Kaffie and Trimble were owners of
30.3%, 30.6% and 6.6%, respectively, of Drillmar's common stock. Messrs. Siem
and Kaffie are both Directors, and Mr. Siem is Chairman and President of
Drillmar. Messrs. Siem and Kaffie provided funding to Drillmar in 2002 of
$116,000 and $100,000, respectively, and in 2001 of $300,000 and $425,000,
respectively, and were issued unsecured promissory notes from Drillmar. The
promissory notes were due June 30, 2002 and bore interest at the rate of 10% per
annum. Along with the promissory notes, Drillmar issued detachable warrants to
Messrs. Siem and Kaffie to purchase 41,500 and 42,500 shares of Drillmar common
stock, respectively. The promissory notes issued by Drillmar are nonrecourse to
the Company.
In January 2003, Drillmar stockholders approved a restructuring plan
whereby Drillmar will issue up to $3.0 million of convertible notes that will
convert into common stock representing over 99% of Drillmar's outstanding
shares. As a result, the Company's ownership in Drillmar will be reduced to less
than 1%. Messrs. Siem and Kaffie are expected to exchange their promissory notes
and accrued interest into Drillmar new convertible notes, which were outstanding
at December 31, 2002.
In May 2002, the Company terminated its agreement with Drillmar effective
as of May 1, 2002, whereby it provided office space and certain management and
administrative services to Drillmar for approximately $40,000 per month and
entered into a new agreement effective as of May 1, 2002, whereby the Company
provided office space and minimal accounting and administrative services to
Drillmar for $2,000 per month. This agreement was terminated and a new agreement
was entered into effective as of February 1, 2003, whereby the Company will
provide office space to Drillmar for $1,500 per month. The Company will also
provide professional, accounting and administrative services to Drillmar billed
on agreed hourly rates. The agreement can be terminated upon 30 days notice or
by the mutual agreement of the parties.
Effective March 31, 2002, the Company recorded a full impairment of its
investment in Drillmar of approximately $340,000 and a full reserve for the
accounts receivable amount owed from Drillmar of approximately $200,000 due to
Drillmar's working capital deficiency and delays in securing capital funding.
12
Customers
The Company generated revenues from both of its primary business segments.
Revenues from major customers exceeding 10% of revenues were as follows for 2002
and 2001.
Oil and gas Pipeline
sales operations Total
----------- ----------- -----------
Year ended December 31, 2002:
Houston Exploration and Production Company $ -- 290,223 290,223
Apache Corporation $ -- 282,215 282,215
Year ended December 31, 2001:
Houston Exploration and Production Company $ -- 639,975 639,975
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. Gas storage customers who
would use the proposed Avoca Gas Storage system have alternatives, including
depleted reservoir and other salt cavern storage systems. Competition also
exists with other industries in supplying the energy and fuel needs of
consumers.
Markets
The availability of a ready market for gas and oil, and the prices of such
gas and oil, depends upon a number of factors, which are beyond the control of
the Company. These include, among other things, the level of domestic
production, actions taken by foreign oil and gas producing nations, the
availability of pipelines with adequate capacity, the availability of vessels
for direct shipment, lightering and transshipment and other means of
transportation, 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, gas, refined products and alternative fuels.
In view of the many uncertainties affecting the supply and demand for crude
oil, gas and refined petroleum products, it is not possible to predict
accurately the prices or marketability of the gas and oil produced for sale or
prices chargeable for transportation and storage services, which the Company
provides.
13
Governmental Regulation
The production, processing, marketing, and transportation of oil and gas,
and the development of terminalling and storage of crude oil and gas by the
Company are subject to federal, state and local regulations which can have a
significant impact upon the Company's overall operations.
Federal Regulation of Natural Gas Transportation. The transportation and
resale of gas in interstate commerce have been regulated by the Natural Gas Act,
the Natural Gas Policy Act and the rules and regulations promulgated by FERC. In
the past, the federal government has regulated the prices at which gas could be
sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which
removed all remaining Natural Gas Act and Natural Gas Policy Act price and
non-price controls affecting producer sales of gas, effective January 1, 1993.
Congress could, however, reenact price controls in the future.
The price and terms for access to pipeline transportation is subject to
extensive federal regulation. In April 1992, the FERC issued Order No. 636,
beginning a series of related orders, which required interstate pipelines to
provide open-access transportation on a basis that is equal for all gas
suppliers. The FERC has stated that it intends Order No. 636 to foster increased
competition within all phases of the gas industry. Order No. 636 affects how
buyers and sellers gain access to the necessary transportation facilities and
how gas is sold in the marketplace. In 2000, the FERC issued Order No. 637
which, among other things, will permit pipelines to file for peak/off-peak and
term differentiated rate structures and changed existing regulations relating to
scheduling procedures, capacity segmentation, pipeline imbalance processes and
penalties, and pipeline reporting requirements.
The Company cannot predict whether the FERC's actions will achieve the goal
of increasing competition in the gas markets or how these, or future regulations
will affect its operations or competitive position. However, the Company does
not believe that any action taken will affect it in any way that materially
differs from the way that such action affects the Company's competitors.
Of the gas pipelines owned by the Company in 2001, only the Black Marlin
Pipeline (sold in January 2001) was subject to rules and regulations of the
Natural Gas Act. As a result, its gas transportation service and pricing service
were subject to the regulatory jurisdiction of the FERC.
All of the Company's pipelines located offshore in federal waters are
subject to the requirements of the Outer Continental Shelf Lands Act ("OCSLA").
FERC has stated that nonjurisdictional gathering lines, as well as interstate
pipelines, are fully subject to the open access and nondiscrimination
requirements of OCSLA's Section 5, which generally authorizes the FERC to insure
that gas pipelines on the Outer Continental Shelf 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 issued a policy statement on Outer Continental
Shelf pipelines reaffirming the requirement that all pipelines provide
nondiscriminatory service. In 2000, FERC issued Order 639, formally imposing new
OCSLA regulations on offshore pipelines not otherwise subject to its Natural Gas
Act jurisdiction. Order 639's requirements, which largely entail reporting and
disclosure obligations to FERC, contain certain exemptions for, among other
things, an offshore pipeline system that "feeds into a facility where gas is
first collected or a facility where gas is first separated, dehydrated, or
otherwise processed." Among the FERC's stated purposes in issuing such rules was
the desire to provide shippers on the OCS with greater assurance of open-access
services on pipelines located on the OCS and non-discriminatory rates and
conditions of service on such pipelines. A federal district court recently
determined that FERC has exceeded its statutory authority in promulgating Order
nos. 639 and 639-A, and the court permanently enjoined FERC from enforcing the
orders. FERC has appealed the district court's decision.
14
Further FERC initiatives concerning possibly diminished Natural Gas Act
regulation of pipelines on the OCS and/or broader regulation under the OCSLA
remain possible and could cause increased regulatory compliance costs. Since all
of the Companies' offshore pipelines fall within the exemption for feeder
facilities and already operate 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 its pipelines may ultimately affect
Company operations.
Aside from the OCSLA requirements and federal safety and operational
regulations, regulation of 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 1993, the FERC issued
Order No. 561, which was intended to simplify oil pipeline ratemaking, largely
through use of a ceiling based on an indexing system. At the end of 2000, the
Commission issued an order based on a five-year review of the indexing system,
affirming this approach to oil pipeline ratemaking. 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.
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. In addition, the OCSLA authorizes
regulations relating to safety and environmental protection applicable to leases
and permittees operating on the OCS. Specific design and operational standards
may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and
structures. Violations of lease conditions or regulations issued pursuant to the
OCSLA 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
private prosecution. Currently, the Company believes that it is in material
compliance with the various safety and operational regulations that it is
subject to. However, as safety and operational regulations are frequently
changed, the Company is unable to predict the future effect changes in these
regulations will have on its operations, if any.
Federal Oil and Gas Leases. All of the Company's exploration and production
operations are located on federal oil and gas leases in the OCS, which are
administered by the Minerals Management Service ("MMS"). Such leases are issued
through competitive bidding, contain relatively standardize terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA that
are subject to interpretation and change by the MMS. For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency, lessees must obtain a permit
from the MMS prior to the commencement of drilling. The MMS has promulgated
15
regulations requiring offshore production facilities located on the OCS to meet
stringent engineering and construction specifications. The MMS also has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil
without prior authorization. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the installation and removal of all production facilities. To cover the various
obligations of lessees on the OCS, the MMS generally requires that lessees have
substantial net worth or post bonds or other acceptable assurance that such
obligations will be met. The cost of these bonds or other surety can be
substantial, and there is no assurance that bonds or other surety can be
obtained in all cases. The Company is currently in compliance with the bonding
requirements of the MMS. Under some circumstances, the MMS may require any of
the Company's operations on federal leases to be suspended or terminated. Any
such suspension or termination could materially adversely affect the Company's
financial condition and results of operations.
The Company's leases in the OCS provide for royalty payments on gas
production calculated at some fraction of the value of the gas produced. OCS
lessees have challenged the Department of Interior's rules and regulations which
prohibit the natural gas producer from subtracting downstream marketing costs
from royalties owed to the Federal government. The U.S. Court of Appeals for the
District of Columbia on February 8, 2002 reversed the U.S. District Court for
the District of Columbia and upheld the Department of Interior's rule that
producers may not deduct costs such as downstream marketing costs, including
aggregator/marketing fees or intra-hub transfer fees charged by pipelines to
track paper transactions at a pipeline junction (not for physical transfers).
With respect to any Company operations conducted on offshore federal
leases, 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 within one
year after production ceases or the lease expires.
Environmental Regulation. The Company's activities with respect to (1)
exploration, development and production of oil and natural gas and (2) the
operation and construction of pipelines, plants, and other facilities for the
transportation and processing, and storage of crude oil, natural gas and natural
gas liquids are subject to stringent environmental regulation by local, state
and federal authorities, including the U.S. Environmental Protection Agency
("EPA"). Such regulation has increased the cost of planning, designing,
drilling, operating and in some instances, abandoning wells and related
equipment. Similarly, such regulation has also increased the cost of design,
construction, and operation of crude oil and natural gas pipelines and
processing facilities. Although the Company believes that compliance with
existing environmental regulations will not have a material adverse affect on
operations or earnings, there can be no assurance that significant costs and
liabilities, including civil and criminal penalties, will not be incurred.
Moreover, future developments, such as stricter environmental laws and
regulations or claims for personal injury or property damage resulting from the
Company's operations, could result in substantial costs and liabilities. 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.
16
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA") imposes liability, without regard to fault or the legality of the
original conduct, on responsible parties with respect to the release or
threatened release of a "hazardous substance" into the environment. Responsible
parties, which include the owner or operator of a site where the release
occurred and persons that disposed or arranged for the disposal of a hazardous
substance at the site, are liable for response and remediation costs and for
damages to natural resources. Petroleum and natural gas are excluded from the
definition of "hazardous substances"; however, this exclusion does not apply to
all materials used in the Company's operations. At this time, neither the
Company nor any of its predecessors has been designated as a potentially
responsible party under CERCLA.
The federal Resource Conservation and Recovery Act ("RCRA") and its state
counterparts regulate solid and hazardous wastes and impose civil and criminal
penalties for improper handling and disposal of such wastes. EPA and various
state agencies have promulgated regulations that limit the disposal options for
such wastes. Certain wastes generated by the Company's oil and gas operations
are currently exempt from regulation as a hazardous wastes," but in the future
could be designated as "hazardous wastes" under RCRA or other applicable
statutes and therefore may become subject to more rigorous and costly
requirements.
The Company currently owns or leases, or has in the past owned or leased,
numerous properties used for the exploration and production of oil and gas or
used to store and maintain equipment regularly used in these operations.
Although the Company's past operating and disposal practices at these properties
were standard for the industry at the time, hydrocarbons or other substances may
have been disposed of or released on or under these properties or on or under
other locations. In addition, many of these properties have been operated by
third parties whose waste handling activities were not under the Company's
control. These properties and any waste disposed thereon may be subject to
CERCLA, RCRA, and state laws which could require the Company to remove or
remediate wastes and other contamination or to perform remedial plugging
operations to prevent future contamination.
The Oil Pollution Act of 1990 ("OPA") and regulations promulgated
thereunder include a variety of requirements related to the prevention of oil
spills and impose liability for damages resulting from such spills. OPA imposes
liability on owners and operators of onshore and offshore facilities and
pipelines for removal costs and certain public and private damages arising from
a spill. OPA establishes a liability limit for onshore facilities of $350
million and for offshore facilities of all removal costs plus $75 million, and
lesser liability limits for vessels depending upon their size. In August 1995,
the DOT issued a Rulemaking under OPA providing that the Secretary of
Transportation can set the liability limit and associated Certificate of
Financial Responsibility requirement for Deepwater Ports from between $350
million and $50 million concurrent with the overall processing of the DWPA
license application. Development of the liability limit would be based upon
engineering and environmental analysis provided during the licensing process. A
party cannot take advantage of the liability limits if the spill is caused by
gross negligence or willful misconduct or resulted from a violation of federal
safety, construction, or operating regulations. If a party fails to report a
spill or cooperate in the cleanup, liability limits likewise do not apply. OPA
imposes ongoing requirements on responsible parties, including proof of
financial responsibility for potential spills. The amount of financial
responsibility required depends upon a variety of factors including the type of
facility or vessel, its size, storage capacity, oil throughput, proximity to
sensitive areas, type of oil handled, history of discharges, worst-case spill
potential and other factors. The Company believes it has established adequate
financial responsibility. While the financial responsibility requirements under
OPA may be amended to impose additional costs on the Company, the impact of such
a change is not expected to be any more burdensome on the Company than on others
similarly situated.
17
The Clean Air Act and state air quality laws and regulations contain
provisions that impose pollution control requirements on emissions to the air
and require permits for construction and operation of certain emissions sources,
including sources located offshore. The Company may be required to incur capital
expenditures for air pollution control equipment in connection with maintaining
or obtaining operating permits and approvals addressing emission-related issues,
although the Company does not expect to be materially adversely affected by such
expenditures.
The Clean Water Act ("CWA") regulates the discharge of pollutants to waters
of the United States and imposes permit requirements on such discharges,
including discharges to wetlands. Federal regulations under the CWA and OPA
require certain owners or operators of facilities that store or otherwise handle
oil, to prepare and implement spill prevention, control and countermeasure plans
and facility response plans relating to the possible discharge of oil into
surface waters. With respect to certain of the Company's operations, it is
required to prepare and comply with such plans and to obtain and comply with
permits. The CWA also prohibits spills of oil and hazardous substances to waters
of the United States in excess of levels set by regulations and imposes
liability in the event of a spill. State laws further provide varying civil and
criminal penalties and liabilities for the spills to both surface and
groundwaters. The Company believes it is in substantial compliance with the
requirements of the CWA, OPA, and state laws, and that any non-compliance would
not have a material adverse effect on the Company.
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 OPA to
establish requirements for evidence of financial responsibility for certain
offshore facilities, other than Deepwater Ports. The amount required is $35
million 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 million 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.
RISK FACTORS
The Company will be primarily dependent on revenues from its pipeline
systems.
As a result of the Company's sale of substantially all of its proved oil
and gas reserves, the Company's future revenues will be primarily dependent on
the level of use of its pipeline systems. Various factors will influence the
level of use of the Company's pipeline system including the amount of oil and
18
gas production near the Company's pipelines and the Company's ability to attract
new users. There are various competing pipelines in and around the Company's
pipeline systems that the Company vigorously competes with to attract new users
to its pipeline systems. There can be no assurance that the Company's marketing
activities will result in attracting new oil and gas reserves to its pipeline
systems.
Oil and gas prices are volatile and a substantial and extended decline in
the price of oil and gas would have a material adverse effect on the Company.
The Company's revenues, profitability, operating cash flow and its
potential for growth are largely dependent on prevailing oil and gas prices.
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply and demand for oil and gas, uncertainties
within the market and a variety of other factors beyond the Company's control.
These factors include: o weather conditions in the United States;
o the condition of the United States economy;
o the actions of the Organization of Petroleum Exporting Countries;
o governmental regulation;
o political stability in the Middle East, South America and elsewhere;
o the foreign supply of oil and gas;
o the price of foreign imports; and
o the availability of alternate fuel sources.
In addition, low or declining oil and gas prices could have collateral
effects that could adversely affect the Company, including the following:
o reducing the exploration and development of oil and gas reserves held
by third party companies around the Company's pipeline systems;
o increasing the Company's dependence on external sources of capital to
meet its cash needs; and
o impairing the Company's ability to obtain needed equity.
Volatile oil and gas prices also make it difficult to estimate the value of
producing properties the Company may acquire and also make it difficult for the
Company to budget for and project the return on acquisitions and development and
exploitation projects.
The Company faces strong competition from larger companies that may
negatively affect its ability to carry on operations.
The Company operates in a highly competitive industry. The Company's
competitors include major integrated oil companies, substantial independent
energy companies, affiliates of major interstate and intrastate pipelines and
national and local gas gatherers, many of which possess greater financial and
19
other resources than the Company. The Company's ability to successfully compete
in the marketplace is affected by many factors.
o Most of the Company's competitors have greater financial resources
than it does, which gives them better access to sources of capital to
acquire and develop oil and gas properties.
o Most of the Company's competitors have longer operating histories and
have more data generally available to them, including information
relating to oil and gas properties.
o The Company often establishes a higher standard for the minimum
projected rate of return on an investment than some of its competitors
since it cannot afford to absorb certain risks. The Company believes
this puts it at a competitive disadvantage in acquiring oil and gas
properties.
The Company's future success depends, in part, upon its ability to find,
develop and acquire new oil and gas reserves.
The Company sold substantially all of its proved reserves in 2002, and is
currently attempting to find and acquire properties containing proved reserves.
Until the Company acquires additional proved reserves, substantially all of the
Company's revenues will be from its pipeline systems and reversionary interest
in oil and gas properties. There can be no assurance that the Company will be
able to acquire proved reserves.
The Company cannot control the activities on properties it does not
operate.
Currently, other companies operate all of the oil and gas properties in
which the Company has an interest. As a result, the Company will depend on the
operator of the wells to properly conduct lease acquisition, drilling,
completion and production operations. The failure of an operator, or the
drilling contractors and other service providers selected by the operator to
properly perform services, could adversely affect the Company, including the
amount and timing of revenues, if any, it receives from its interest.
The Company has and generally anticipates that it will typically own
substantially less than a 50% working interest in its prospects and will
therefore engage in joint operations with other working interest owners. In
instances in which the Company owns or controls less than a majority of the
working interest in a prospect, decisions affecting the prospect could be made
by the owners of more than a majority of the working interest. For instance, if
the Company is unwilling or unable to participate in the costs of operations
approved by a majority of the working interests in a well, the Company's working
interest in the well (and possibly other wells on the prospect) will likely be
subject to contractual "non-consent penalties". These penalties may include, for
example, full or partial forfeiture of the Company's interest in the well or a
relinquishment of the Company's interest in production from the well in favor of
the participating working interest owners until the participating working
interest owners have recovered a multiple of the costs which would have been
borne by the Company if it had elected to participate, which often ranges from
400% to 600% of such costs.
The Company has pursued, and intends to continue to pursue, acquisitions.
The Company's business may be adversely affected if it cannot effectively
integrate acquired operations.
One of the Company's business strategies has been to acquire operations and
assets that are complementary to its existing businesses. Acquiring operations
and assets involves financial, operational and legal risks. These risks include:
20
o inadvertently becoming subject to liabilities of the acquired company
that were unknown to the Company at the time of the acquisition, such
as later asserted litigation matters or tax liabilities,
o the difficulty of assimilating operations, systems and personnel of
the acquired businesses, and
o maintaining uniform standards, controls, procedures and policies.
Any future acquisitions would likely result in an increase in expenses. In
addition, competition from other potential buyers could cause the Company to pay
a higher price than it otherwise might have to pay and reduce its acquisition
opportunities. The Company is often out-bid by larger, better capitalized
companies for acquisition opportunities it pursues. Moreover, the Company's past
success in making acquisitions and in integrating acquired businesses does not
necessarily mean it will be successful in making acquisitions and integrating
businesses in the future.
Operating hazards, including those peculiar to the marine environment, may
adversely affect the Company's ability to conduct business.
The Company's operations are subject to risks inherent in the oil and gas
industry, such as:
o sudden violent expulsions of oil, gas and mud while drilling a well,
commonly referred to as a blowout;
o a cave in and collapse of the earth's structure surrounding a well,
commonly referred to as cratering;
o explosions;
o fires;
o pollution; and
o other environmental risks.
These risks could result in substantial losses to the Company from injury and
loss of life, damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. The Company's offshore
operations are also subject to a variety of operating risks peculiar to the
marine environment, such as hurricanes or other adverse weather conditions and
more extensive governmental regulation. These regulations may, in certain
circumstances, impose strict liability for pollution damage or result in the
interruption or termination of operations.
Losses and liabilities from uninsured or underinsured drilling and
operating activities could have a material adverse effect on the Company's
financial condition and operations.
The Company maintains several types of insurance to cover its operations,
including maritime employer's liability and comprehensive general liability.
Amounts over base coverages are provided by primary and excess umbrella
liability policies with maximum limits of $50 million. The Company also
maintains operator's extra expense coverage, which covers the control of drilled
or producing wells as well as redrilling expenses and pollution coverage for
wells out of control.
21
The Company may not be able to maintain adequate insurance in the future at
rates it considers reasonable or losses may exceed the maximum limits under the
Company's insurance policies. If a significant event that is not fully insured
or indemnified occurs, it could materially and adversely affect the Company's
financial condition and results of operations.
Compliance with environmental and other government regulations could be
costly and could negatively impact production and pipeline operations.
The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. These laws and regulations may:
o require the acquisition of a permit before drilling commences;
o restrict the types, quantities and concentration of various substances
that can be released into the environment from drilling and production
activities;
o limit or prohibit drilling and pipeline activities on certain lands
lying within wilderness, wetlands and other protected areas;
o require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells and abandoning pipelines;
and
o impose substantial liabilities for pollution resulting from the
Company's operations.
The recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. The enactment of stricter legislation or the
adoption of stricter regulations could have a significant impact on the
Company's operating costs, as well as on the oil and gas industry in general.
The Company's operations could result in liability for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages. The Company could also be liable
for environmental damages caused by previous property owners. As a result,
substantial liabilities to third parties or governmental entities may be
incurred which could have a material adverse effect on the Company's financial
condition and results of operations. The Company maintains insurance coverage
for its operations, including limited coverage for sudden and accidental
environmental damages, but the Company does not believe that insurance coverage
for environmental damages that occur over time or complete coverage for sudden
and accidental environmental damages is available at a reasonable cost.
Accordingly, the Company may be subject to liability or may lose the privilege
to continue exploration or production activities upon substantial portions of
its properties if certain environmental damages occur.
The OPA imposes a variety of regulations on "responsible parties" related
to the prevention of oil spills. The implementation of new, or the modification
of existing, environmental laws or regulations, including regulations
promulgated pursuant to the OPA, could have a material adverse impact on the
Company.
22
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used
in the oil and gas industry.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of gas.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Condensate. Liquid hydrocarbons associated with the production of a
primarily gas reserve.
Development well. A well drilled within the proved area of a gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find and produce gas or oil in an
unproved area, to find a new reservoir in a field previously found to be
productive of gas or oil in another reservoir or to extend a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Leasehold interest. The interest of a lessee under an oil and gas lease.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of gas to one barrel of oil, condensate or gas liquids.
Mmbtu. One million British Thermal Units.
Mmcf. One million cubic feet of gas.
Mmcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of gas to one Bbl of oil, condensate or gas liquids.
Net revenue interest. The percentage of production to which the owner of a
working interest is entitled.
Nonoperating working interest. A working interest, or a fraction of a
working interest, in a tract where the owner is not the operator of the tract.
Overriding royalty. An interest in oil and gas produced at the surface,
free of the expense of production that is in addition to the usual royalty
interest reserved to the lessor in an oil and gas lease.
23
Prospect. A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the
discovery of oil, gas or both.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Proved
developed reserves are further categorized into two sub-categories, proved
developed producing reserves and proved developed non-producing reserves.
Proved developed producing. Reserves sub-categorized as producing are
expected to be recovered from completion intervals which are open and producing
at the time of the estimate.
Proved developed non-producing. Reserves sub-categorized as non-producing
include shut-in and behind pipe reserves. Shut-in reserves are expected to be
recovered from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were shut-in
awaiting pipeline connections or as a result of a market interruption, or (3)
wells not capable of producing for mechanical reasons.
Proved reserves. The estimated quantities of oil, gas and condensate that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions.
Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells or from existing wells where a relatively major expenditure is
required for recompletion.
Reversionary interest. A form of ownership interest in property that
reverts back to the transferor after expiration of an intervening income
interest or the occurrence of another triggering event.
Royalty interest. An interest in a gas and oil property entitling the owner
to a share of gas and oil production free of costs of production.
Undivided Interest. A form of ownership interest in which more than one
person concurrently owns an interest in the same oil and gas lease or pipeline.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production.
Item 2. Properties
Information appearing in Item 1 describing the Company's oil and gas
properties under the caption "Business" is incorporated herein by reference.
The Company leases its executive offices in Houston, Texas, under an
operating lease expiring December 31, 2006. The Company's aggregate annual lease
payment obligation under this lease is approximately $195,000.
In March 2003, the Company entered into a sublease agreement expiring
December 31, 2006 for certain of its office space to Tri-Union Development
Corporation. The Company's annual receipts from this sublease will be $81,630.
Mr. James M. Trimble, director of the Company is the Chairman and Chief
Executive Officer of Tri-Union.
24
Item 3. Legal Proceedings
In May 2002, the Company, American Resources and members of prior
management of American Resources, including its former chief financial officer,
entered into a settlement agreement with H&N Gas, Limited Partnership ("H&N"),
whereby American Resources paid approximately $0.3 million in settlement of this
litigation and additionally released funds of approximately $0.7 million it was
holding that were due to H&N. The settlement agreement and the payments made
thereunder were made in compromise of disputed claims and are not an admission
of wrongdoing or of liability of any kind.
Neither the Company nor any of its property is subject to any material
pending legal proceedings.
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters
The Company's common stock trades in the over-the-counter market and is
quoted on the NASDAQ Small Cap Market under the symbol "BDCO". As of March 13,
2003, there were an estimated 600 stockholders of record and the Company
estimates there are more than 1,000 beneficial owners of its common stock.
NASDAQ quotations reflect inter-dealer prices, without adjustment for retail
mark-ups, markdowns or commissions and may not represent actual transactions.
The following table sets forth, for the periods indicated, the high and low bid
price for the common stock as reported by the NASDAQ.
High Low
Quarter Ended March 31, 2001 ............. $ 5.19 $ 3.25
Quarter Ended June 30, 2001 ............. $ 4.95 $ 3.80
Quarter Ended September 30, 2001............. $ 4.31 $ 2.81
Quarter Ended December 31, 2001 ............. $ 3.40 $ 1.60
Quarter Ended March 31, 2002 ............. $ 1.86 $ 1.52
Quarter Ended June 30, 2002 ............. $ 1.70 $ 0.60
Quarter Ended September 30, 2002............. $ 0.79 $ 0.28
Quarter Ended December 31, 2002 ............. $ 0.81 $ 0.22
The Company has not declared or paid any dividends on the Common Stock
since its incorporation. 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. Previously, the
Company was restricted, pursuant to a loan agreement from paying dividends on
the Common Stock if there was an outstanding balance under the loan agreement.
Any loan agreements which the Company may enter into in the future will likely
contain restrictions on the payment of dividends on its' 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.
On July 15, 2002, the Company received a notice from the NASDAQ, that
because the Company's Common Stock traded below the minimum bid requirement of
$1.00 for 30 consecutive trading days the Common Stock would be delisted if its
bid price does not close above $1.00 for 10 consecutive trading days by January
25
13, 2003. On January 14, 2003, the Company received notice from NASDAQ that the
initial deadline was extended until July 14, 2003. As of March 13, 2003, the bid
price for the Company's Common Stock had not closed above $1.00. If the
Company's Common Stock is delisted from NASDAQ it would then trade on the OTC
Bulletin Board or "pink sheets". This could materially decrease the liquidity of
the Company's Common Stock and further limit the Company's ability to raise
capital.
Item 6. Management's Discussion and Analysis of Financial Condition and Results
of Operations
During 2002, the Company sold substantially all of its interests in its oil
and gas properties for approximately $5.0 million. The properties sold
represented over 99% of the Company's proved oil and gas reserves. As a result
of the sale of the Company's proved oil and gas properties, the amount of future
oil and gas sales revenues, lease operating expenses, depletion and capital
expenditures associated with oil and gas production activities will be dependent
upon the success of the Company's exploratory properties, reversionary working
interests and future acquisitions of oil and gas properties. 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 included in Item 7. and Item 1. Business.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------
Historically, the Company has relied on the proceeds from the sale of assets and
capital raised from the issuance of debt and equity securities to individual
investors and related parties to sustain its operations. At December 31, 2002,
the Company's working capital was approximately $2.2 million. During the third
and fourth quarters of 2002, the Company received approximately $5.0 million
from the sale of substantially all of its proved oil and gas properties. In
addition to using the sales proceeds to satisfy its working capital needs the
Company may also use the sale proceeds to finance future asset acquisitions,
which may include other oil and gas properties. However, there can be no
assurance that the Company will be able to acquire and develop additional oil
and gas reserves that are economically recoverable.
The following table summarizes certain of the Company's contractual
obligations and other commercial commitments at December 31, 2002 (amounts in
thousands).
26
Payments Due by Period
----------------------
Contractual Less than After
Obligations Total 1 year 2-3 years 4-5 years 5 years
----------- ----------- ----------- ----------- ----------- -----------
Long-Term Debt $ 750 -- -- 750 --
Operating Leases 487 136 237 114 --
Abandonment - Costs 2,700 1,440 1,260 -- --
----------- ----------- ----------- ----------- -----------
Total Contractual
Obligations $ 3,937 1,576 1,497 864 --
=========== =========== =========== =========== ===========
Amount of Commitment Expiration Per Period
------------------------------------------
Other Commercial Less than After
Commitments Total 1 year 2-3 years 4-5 years 5 years
---------------- ----------- ----------- ----------- ----------- -----------
Abandonment - Costs $ 1,100 1,100 -- -- --
----------- ----------- ----------- ----------- -----------
Total Commercial
Obligations $ 1,100 1,100 -- -- --
=========== =========== =========== =========== ===========
The following table summarizes the Company's financial position for the periods
indicated:
December 31,
(amounts in thousands)
2002 2001
------------------- -------------------
Amount % Amount %
-------- -------- -------- --------
Working Capital $ 2,243 29 $ -- --
Property and equipment, net 4,687 60 5,980 85
Other noncurrent assets 845 11 1,043 15
-------- -------- -------- --------
Total $ 7,775 100 $ 7,023 100
======== ======== ======== ========
Working Capital $ -- -- $ 1,197 17
Long-term Liabilities 2,010 26 -- --
Minority Interest -- -- 1,065 15
Stockholders' equity 5,765 74 4,761 68
-------- -------- -------- --------
Total $ 7,775 100 $ 7,023 100
======== ======== ======== ========
27
The change in the Company's financial position from December 31, 2001 to
December 31, 2002, was primarily due to the sale of its South Timbalier Block
148 oil and gas property in July 2002 and the sale of substantially all of its
remaining oil and gas properties in November 2002. See Item 1. Business - Recent
Developments.
The Company's future cash flows are subject to a number of variables,
including receipt of revenues from leases in which the Company holds
reversionary interests utilization of its pipeline systems, utilization of its
services by third parties and commodity prices among others. The Company
believes that it has sufficient liquidity at December 31, 2002 to meet its
obligations and operating needs for the year ending December 31, 2003. However,
there can be no assurance that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of expenditures.
The net cash provided by or used in operating, investing and financing
activities is summarized below:
Years Ended December 31
(amounts in thousands)
2002 2001
--------- ---------
Net cash provided by (used in):
Operating activities $ (2,836) $ 1,447
Investing activities 3,898 2,412
Financing activities -- (2,587)
--------- ---------
Net increase in cash $ 1,062 $ 1,272
========= =========
The Company's cash flow from operating activities decreased by $4.3 million
in 2002 from 2001, due primarily to a decrease in cash generated from 2002
operations of approximately $2.1 million and a reduction in current liabilities
of approximately $2.3 million.
Cash flow provided by investing activities during 2002 included the
proceeds from the sale of the American Resources oil and gas properties of
approximately $5.0 million. Cash flow used in investing activities included
exploration and development costs associated with oil and gas properties owned
by American Resources of approximately $0.5 million, the purchase of American
Resources minority stockholders interests of approximately $0.3 million, and
other capital expenditures of approximately $0.2 million.
The Company previously announced a gas discovery in High Island Area Block
A-7, in the Gulf of Mexico. The Company owns an 8.9% reversionary working
interest in this field and it will begin to receive revenues from its
reversionary interest after "payout" occurs. Payout occurs after all of the
other working interest owners have recovered their costs and expenses associated
with developing the field from sales of gas and oil production from the field.
In late 2002, two wells from this field were successfully recompleted. As a
result of the recompleted wells and based on current levels of production and
commodity prices, the Company now believes that it could begin to receive
revenues from its reversionary working interest in this field in the second or
third quarter 2003.
In November 2000, the Company elected to abandon the Buccaneer Field due to
adverse developments in the field. The Company reached an agreement with Tetra
Applied Technologies, Inc. ("Tetra"), to plug and abandon the wells located in
the Buccaneer Field. The work was completed in the first quarter of 2001 for
approximately $1.4 million. In addition, Maritech Resources, Inc. ("Maritech"),
an affiliate of Tetra, purchased an adjacent lease from Apache Corporation for
which the Company provided production operating services. In connection with
this lease purchase, Maritech also assumed the operating agreement. In December
28
2000, as a result of the Company's plans to abandon the Buccaneer Field platform
facilities, the Company and Maritech terminated the operating agreement. The
Company installed a new platform in 2001 at a cost of $1.7 million net to its
interest, to operate and maintain the Blue Dolphin Pipeline System as well as
handle the production from Maritech's lease. The Blue Dolphin System was
previously tied into and operated from the Buccaneer Field platforms.
In August 2001, the Company reached an agreement with Tetra to remove the
Buccaneer Field platforms for a cost of approximately $2.6 million. Pursuant to
the agreement, Tetra and the Company agreed to extended payment terms, whereby
the Company will pay 20% upon completion and 5% per month for twelve months,
with the remaining balance due in the thirteenth month. To provide security for
the extended payment terms, the Company provided Tetra with a first lien on the
50% interest it then owned in the Blue Dolphin Pipeline System. Operations to
remove the platforms commenced in August 2001 and were suspended in December
2001, while the Company continued discussions with and was awaiting a decision
from the Texas Parks and Wildlife Department ("TPW") to leave the underwater
portion of the platforms in place as artificial reefs. The scope of work with
Tetra has changed due to the reefing rather than complete removal originally
contemplated. The contract price and the payment terms remain unchanged. The
Company requested and has received an extension from the Minerals Management
Service until April 1, 2003 to complete abandonment operations needed to convert
the platform complexes into artificial reefs. Tetra is expected to resume its
operations during the second quarter 2003. The Company is also obligated to pay
$390,000 to TPW, of which $350,000 represents half of the site clearance work
that will be eliminated and $40,000 represents the cost of buoys to mark the
reef sites. As a result of the reefing agreement with TPW, the Company has
reduced its provision for abandonment costs by $310,000 due to the elimination
of site clearance costs, and by approximately $373,000 due to lowering its
contingency associated with the abandonment work. The Company will request and
expects the MMS to grant additional time to complete the reefing activities. The
Company believes that its provision for abandonment costs of $3.8 million at
December 31, 2002 is adequate.
In January 2001, the Company and its partners sold the Black Marlin
Pipeline System for $7.3 million and the High Island Block A-5 pipeline for $2.0
million to Williams Field Services. The Company's portion of the proceeds were
$3.6 million and $1.0 million, respectively.
During 2002, the Company incurred capital expenditures of approximately
$512,000 for development of its proved reserves. As a result of the sales of its
proved reserves during 2002, future capital expenditures associated with the
Company's oil and gas properties will be dependent upon the success of the
Company's exploratory properties, reversionary working interests and future
acquisitions of proved oil and gas reserves. The reserves and future net
revenues presented in Item 1 "Business" reflect capital expenditures totaling
$150,000 and $192,000 in the years ending December 31, 2004 and 2006,
respectively.
On December 2, 1999, the Company, through Blue Dolphin Exploration,
acquired a 75% ownership interest in American Resources by purchasing
approximately 39.5 million shares of American Resources common stock for
approximately $4.5 million. On February 19, 2002, the Company completed its
acquisition of American Resources, pursuant to the Amended and Restated
Agreement and Plan of Merger dated as of December 19, 2001 (the "Merger
Agreement"). Pursuant to the Merger Agreement, American Resources became a
wholly owned subsidiary of the Company. As a result of elections made by
American Resources' stockholders, the Company issued 277,330 shares of Common
Stock and paid approximately $255,000 in cash.
29
In connection with the Company's initial investment in American Resources
Den norske Bank sold American Resources senior secured debt to the Company for
the right to receive a possible future payment. The payment due to Den norske
was determined to be approximately $0.8 million net to American Resources;
however, in June 2002, Den norske agreed to accept $0.6 million as full payment,
which American Resources paid in June 2002.
In May 2002, the Company, American Resources and members of prior
management of American Resources, including its former chief financial officer,
entered into a litigation settlement agreement with H&N Gas. American Resources
paid approximately $0.3 million in settlement of the litigation and additionally
released funds of approximately $0.7 million it was holding that were due to
H&N. The settlement agreement and the payments made thereunder were made in
compromise of disputed claims and are not an admission of wrongdoing or of
liability of any kind.
In February 2002, the Company acquired an additional 1/3 interest in the
Blue Dolphin Pipeline System and the inactive Omega Pipeline from MCNIC.
Pursuant to the terms of the purchase and sales agreement, Blue Dolphin Pipeline
issued MCNIC a $750,000 promissory note due December 31, 2006, with required
monthly payments to be made out of 90% of the net revenues of the interest
acquired. The note bears interest at the rate of 6% per annum and is secured by
the interest acquired. Additionally, contingent payments of up to $750,000 will
be made, if the promissory note is retired before its maturity date, payable
annually after the promissory note is retired until December 31, 2006, out of
50% of the net revenues from the interest acquired. The maturity date, December
31, 2006, will be extended by one additional year, up to a maximum of two years,
for years in which non-recurring, extraordinary expenditures, attributable to
the interest acquired, exceeds $200,000, in the aggregate, during any year. As
of December 31, 2002, the amount owed MCNIC is $750,000 plus accrued interest of
$42,245. During the year ended December 31, 2002 the Company paid MCNIC interest
of $2,755.
RESULTS OF OPERATIONS
For the year ended December 31, 2002 ("2002"), the Company reported net
income of $482,054, compared to a net loss of $2,649,142 for the year ended
December 31, 2001 ("2001"). The improvement in results in 2002 was due to a gain
on sale of assets of approximately $2.2 million in 2002 offset by the 2001 gain
on sale of assets of approximately $1.4 million, and 2001 recordings of an
impairment for the Company's Petroport and Sabine Seaport projects of $1.9
million and a $1.0 million increase in the Company's impairment of the Buccaneer
Field.
2002 compared to 2001
Revenue from oil and gas sales. Revenues from oil and gas sales decreased
by $2,912,294 in 2002, from those of 2001. The decrease was primarily due to a
45% reduction in oil and gas production volumes due to the sale of the Company's
proved reserves during 2002 resulting in a decrease in revenues of $2.0 million
(see Item 1. Business) and normal production declines, and a reduction in gas
prices of 34% and oil prices of 25% in 2002, resulting in a $0.9 million
reduction in revenues.
Revenue from pipeline operations. Revenues from pipeline operations
increased by $136,496 or 14% in 2002 to $1,128,319. The increase was due
primarily to the Company's acquisition of an additional 1/3 interest in the Blue
Dolphin Pipeline System effective January 1, 2002, increasing the Company's
interest from 50% to 83%, resulting in additional revenues of approximately $.47
million, offset in part by a decrease in transportation volumes of 26 %
resulting in decreased revenues of approximately $.33 million.
30
Lease operating expenses. Lease operating expenses for 2002 decreased by
$636,629, or 55% from 2001. The decrease resulted primarily from the sale of the
Company's proved oil and gas reserves during 2002.
Pipeline operating expenses. Pipeline operating expenses in 2002 increased
by $321,553 from $517,054 in 2001. The increase was primarily due to the
acquisition of the 1/3 interest in the Blue Dolphin Pipeline System effective
January 1, 2002 increasing the company's interest from 50% to 83%.
Depletion, depreciation and amortization expense. Depletion, depreciation
and amortization expenses decreased by $999,128 from 2001. Depletion expense
decreased in the 2002 due to a 45% decrease in production volumes resulting in
decreased depletion of $0.5 million and a lower depletion rate used in 2002
compared to 2001 resulting in decreased depletion of approximately $0.4 million.
Impairment of assets. Impairment of assets decreased in 2002 by $2,600,480.
In 2002 the Company recorded an impairment of its investment in Drillmar of $0.3
million (see Item 1. Business - Drillmar). In 2001, the Company recorded an
impairment of its investment in the Petroport and Sabine Seaport projects of
approximately $1.9 million, and increased the impairment of the Buccaneer Field
by $1.0 million due to revised plugging and abandonment estimates.
General and administrative expenses. General and administrative expenses
for 2002 decreased $337,744 from 2001. The decrease is primarily due to the
Company's cost reduction plan implemented in 2002 that resulted in a reduction
in staff and other costs of approximately $0.6 million, the acquisition of the
American Resources minority shareholders interest and the closing of American
Resource's New Orleans office of approximately $0.2 million and lower legal
expenses of approximately $0.1 million as a result of the settlement of the H&N
lawsuit in 2002. These cost reductions were offset in part by the elimination of
approximately $0.6 million of management fees generated by the Company that were
recorded as a reduction to general and administrative expenses during 2001, of
which $0.3 million were recorded from Drillmar, and $0.3 million were recorded
from the 1/3 interest in the Blue Dolphin Pipeline System acquired by the
Company effective January 1, 2002.
Interest and other expense. Interest and other expense decreased by $23,990
in 2002. In 2002, the Company recorded an expense associated with the settlement
of litigation with H&N of approximately $0.3 million and costs associated with
unsuccessful acquisitions and other expenses of approximately $0.1 million,
offset in part by a reduction of the payment to Den norske Bank of approximately
$0.2 million. In 2001 other expenses included a $0.2 million increase in the
provision for the contingent payment to Den norske Bank.
Gain on sale of assets. Current period gain on sale of assets increased by
$802,923 from 2001. In 2002, the Company recorded gains on the sale of its
proved oil and gas reserves of $2.2 million. In 2001, the Company recorded a
gain on the sale of the Black Marlin Pipeline System of $1.4 million.
Bad debt expense. The Company recorded bad debt expense of $197,500 in 2002
from accounts receivable owed by Drillmar and other accounts receivable of
$24,250.
Equity losses of affiliates. In 2001, the Company recorded losses from its
equity interests in Drillmar and New Avoca of $245,201.
Interest and other income. Interest and other income increased $644,285 in
2002. The increase is primarily due to the Company's $0.7 million reduction in
its provision for the Buccaneer Field abandonment costs.
31
Critical Accounting Policies
The selection and application of accounting policies is an important process
that has developed as Blue Dolphin's business activities have evolved and as the
accounting rules have developed. Accounting rules generally do not involve a
selection among alternatives, but involve an implementation and interpretation
of existing rules, and the use of judgment, to the specific set of circumstances
existing in the Company's business. The Company makes every effort to properly
comply with all applicable rules on or before their adoption, and believes the
proper implementation and consistent application of the accounting rules is
critical. However, not all situations are specifically addressed in the
accounting literature. In these cases, the Company must use its best judgment to
adopt a policy for accounting for these situations. Blue Dolphin accomplishes
this by analogizing to similar situations and the accounting guidance governing
them, and often consults with its independent accountants about the appropriate
interpretation and application of these policies.
Given that the Company has sold substantially all of its oil and gas exploration
and production assets as of December 31, 2002, its most critical accounting
policy currently relates to the accounting for the impairment of long lived
assets, which include primarily the pipeline assets, as of December 31, 2002.
In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets", Blue Dolphin initiates its review whenever events or changes
in circumstances indicate that the carrying amount of a long-lived asset may not
be recoverable. Recoverability of an asset is measured by comparison of its
carrying amount to the expected future undiscounted cash flows expected to
result from the use and eventual disposition of that asset, excluding future
interest costs that would be recognized as an expense when incurred. Any
impairment to be recognized is measured by the amount by which the carrying
amount of the asset exceeds its fair market value. Significant management
judgment is required in the forecasting of future operating results which are
used in the preparation of projected cash flows and, should different conditions
prevail or judgments be made, material impairment charges could be necessary.
Currently, the Company's pipeline assets are significantly under utilized and
therefore is an indicator of possible impairment at December 31, 2002.
Accordingly, management developed future cash flows as of December 31, 2002
expected to be generated from its pipeline assets based on certain assumptions.
The most significant assumption made in connection with the preparation of
expected future cash flows is the assumption that pipeline throughput volumes
will increase over the next few years due to the current leasing and drilling
activity surrounding the Company's pipeline. Based on the results of the
impairment test, which indicates expected future undiscounted cash flows are in
excess of the pipeline assets net carrying value, no impairment has been
recorded as of December 31, 2002.
Recently Issued Accounting Pronouncements
In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement No. 143 ("SFAS 143"), "Accounting for Asset Retirement Obligations,"
which addresses financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the associated asset
retirement costs. The standard applies to legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction,
development and/or normal use of the asset. SFAS 143 requires that the fair
value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made. The fair value of the liability is added to the carrying amount of the
associated asset and this additional carrying amount is depreciated over the
life of the asset. If the obligation is settled for other than the carrying
amount of the liability, the Company will recognize a gain or loss on
settlement.
32
The Company is required and will adopt the provisions of SFAS 143 for the
quarter ending March 31, 2003. The Company currently estimates that the adoption
of SFAS 143 will result in the recording of an asset retirement obligation of
$1.6 million.
In May 2002, the FASB issued Statement of Financial Accounting Standards No. 145
("SFAS 145"), "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13, and Technical Corrections". This Statement rescinds FASB
Statements No. 4, Reporting Gains and Losses from Extinguishment of Debt, and an
amendment of Statement No. 4 and FASB Statement No. 64, Extinguishments of Debt
Made to Satisfy Sinking-Fund Requirements. This Statement also rescinds FASB
Statement No. 44, Accounting for Intangible Assets of Motor Carriers. This
Statement amends FASB Statement No. 13, Accounting for Leases, to eliminate an
inconsistency between the required accounting for sale-leaseback transactions
and the required accounting for certain lease modifications that have economic
effects that are similar to sale-leaseback transactions. SFAS 145 is effective
for fiscal years beginning after May 15, 2002. The Company's management does not
expect the adoption of SFAS 145 to have a material effect on the Company's
financial condition and results of operations.
In June 2002, the FASB issued Statement of Financial Accounting Standards No.
146 ("SFAS 146"), "Accounting for Costs Associated with Exit or Disposal
Activities". This Statement addresses financial accounting and reporting for
costs associated with exit or disposal activities and nullifies Emerging Issues
Task Force Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)". SFAS 146 is effective for exit or disposal
activities initiated after December 31, 2002. The Company's management does not
expect the adoption of SFAS 146 to have a material effect on the Company's
financial condition and results of operations.
In December 2002, the FASB issued Statement of Financial Accounting Standards
("SFAS") No. 148, "Accounting for Stock-Based Compensation, Transition and
Disclosure." SFAS No. 148 provides alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. SFAS No. 148 also requires that disclosures of the pro
forma effect of using the fair value method of accounting for stock-based
employee compensation be displayed more prominently and in a tabular format.
Additionally, SFAS No. 148 requires disclosure of the pro forma effect in
interim financial statements. The transition and annual disclosure requirements
of SFAS No. 148 are effective for fiscal years ending after December 15, 2002.
The interim disclosure requirements are effective for interim periods beginning
after December 15, 2002. The Company does not expect that the adoption of SFAS
148 will have a material effect on its financial position or results of
operations.
Item 7. Financial Statements and Supplementary Data
Index to Financial Statements: Page
----
Independent Auditors' Report....................................... 34
Consolidated Balance Sheet, at December 31, 2002................... 35
Consolidated Statements of Operations, for the years
ended December 31, 2002 and 2001............................ 37
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 2002 and 2001...................... 38
Consolidated Statements of Cash Flows, for the years
ended December 31, 2002 and 2001............................ 39
Notes to Consolidated Financial Statements.................... 41
33
Independent Auditors' Report
The Board of Directors
Blue Dolphin Energy Company
We have audited the accompanying consolidated balance sheet of Blue Dolphin
Energy Company and subsidiaries as of December 31, 2002, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the years in the two-year period ended December 31, 2002. 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 auditing standards generally accepted
in the United States. Those standards require that we plan and perform the
audits 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 consolidated financial position of Blue
Dolphin Energy Company and subsidiaries as of December 31, 2002, and the
consolidated results of their operations and their cash flows for each of the
years in the two-year period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States.
/s/ Mann Frankfort Stein & Lipp CPAs, LLP
-----------------------------------------
Houston, Texas
February 28, 2003
34
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet
December 31, 2002
Assets
------
Current assets:
Cash and cash equivalents $ 4,405,676
Trade accounts receivable 515,292
Prepaid expenses and other assets 294,192
-----------
Total current assets 5,215,160
Property and equipment, at cost:
Oil and gas properties, including $140,233
of unproved leasehold cost (full-cost method) 21,920,491
Pipelines 3,670,510
Onshore separation and handling facilities 1,664,128
Land 860,275
Other property and equipment 272,508
-----------
28,387,912
Less accumulated depletion, depreciation,
amortization and impairment 23,700,652
-----------
4,687,260
Deferred federal income tax
244,444
Investment in New Avoca
585,629
Other assets 15,415
-----------
$10,747,908
===========
See accompanying notes to consolidated financial statements.
35
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet, continued
December 31, 2002
Liabilities and Stockholders' Equity
------------------------------------
Current liabilities:
Trade accounts payable $ 366,304
Asset retirement obligations - current portion 2,540,000
Accrued expenses and other liabilities 66,245
------------
Total current liabilities 2,972,549
------------
Long-term liabilities:
Note payable 750,000
Asset retirement obligations, net of current portion 1,260,000
------------
Total long-term liabilities 2,010,000
------------
Stockholders' equity:
Common stock, $.01 par value, 10,000,000 shares
authorized and 6,606,585 shares issued
and outstanding 66,066
Additional paid-in 26,239,098
capital
Accumulated deficit (20,539,805)
------------
Total stockholders' equity 5,765,359
------------
$ 10,747,908
============
See accompanying notes to consolidated financial statements.
36
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
Years ended December 31, 2002 and 2001
2002 2001
----------- -----------
Revenue from operations:
Oil and gas sales $ 1,781,958 4,694,202
Pipeline operations 1,128,319 991,823
----------- -----------
Revenue from operations 2,910,277 5,686,025
Cost of operations:
Lease operating expenses 518,920 1,155,549
Pipeline operating expenses 838,607 517,054
Depletion, depreciation and amortization 818,642 1,817,770
Impairment of assets 339,984 2,940,464
General and administrative expenses 2,507,716 2,845,459
----------- -----------
Cost of operations 5,023,869 9,276,296
----------- -----------
Loss from operations (2,113,592) (3,590,271)
Other income (expense):
Interest and other expense (219,601) (243,591)
Gain on sale of assets 2,220,549 1,417,626
Interest and other income 760,702 116,417
Bad debt expense (221,750) --
Equity in losses of affiliates -- (245,201)
----------- -----------
Income (loss) before minority interest and income taxes 426,308 (2,545,020)
Minority interest 55,746 (104,122)
Income tax expense -- --
----------- -----------
Net income (loss) $ 482,054 (2,649,142)
=========== ===========
Income (loss) per common share-basic $ 0.08 (0.44)
=========== ===========
Income (loss) per common share- diluted $ 0.08 (0.44)
=========== ===========
Weighted average number of common shares
outstanding - basic 6,343,834 6,004,019
=========== ===========
Weighted average number of common shares
outstanding - diluted 6,359,072 6,004,019
=========== ===========
See accompanying notes to consolidated financial statements.
37
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended December 31, 2002 and 2001
Additional Total
Common paid-in Accumulated stockholders'
stock capital deficit equity
------------- ------------- ------------- -------------
Balance at December 31, 2000 60,167 25,775,417 (18,372,717) 7,462,867
Exercise of 3,333 stock options 33 12,715 -- 12,748
Issuance of shares to 401K plan 500 79,500 -- 80,000
Stock registration costs and other 215 (145,572) -- (145,357)
Net loss (2,649,142) (2,649,142)
------------- ------------- ------------- -------------
Balance at December 31, 2001 $ 60,915 25,722,060 (21,021,859) 4,761,116
Acquire minority interest of subsidiary 2,773 360,173 -- 362,946
Common stock issued for services -- 159,243
2,378 156,865
Net income 482,054 482,054
------------- ------------- ------------- -------------
Balance at December 31, 2002 $ 66,066 26,239,098 (20,539,805) 5,765,359
============= ============= ============= =============
See accompanying notes to consolidated financial statements.
38
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended December 31, 2002 and 2001
2002 2001
----------- -----------
Operating activities:
Net income (loss) $ 482,054 (2,649,142)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization 818,642 1,817,770
Minority interest (55,746) 104,122
Gain on sale of assets (2,220,549) (1,417,626)
Impairment of assets - investments 339,984 2,940,464
Change in Abandonment costs (410,816) --
Increase in other liabilities -- 250,000
Equity in income (losses) of affiliate (60,158) 245,201
Bad debt expense 221,750 --
Common stock issued for services 159,243 80,000
Changes in operating assets and liabilities:
Trade accounts receivable 521,197 1,148,512
Prepaid expenses and other assets (130,367) (35,912)
Abandonment costs incurred (194,592) (442,984)
Other assets -- 28,389
Trade accounts payable,
accrued expenses and other liabilities (2,307,021) (622,292)
----------- -----------
Net cash provided by (used in)
operating activities (2,836,379) 1,446,502
Investing activities:
Exploration and development costs (512,393) (1,022,843)
Purchases of property and equipment (180,600) (1,764,245)
Net proceeds from sale of assets 5,030,000 5,985,000
Development costs - Petroport -- (59,305)
Development costs - New Avoca (82,000) (234,140)
Acquisition and development costs - Drillmar -- (492,460)
Purchase of minority interest in subsidiary (356,512) --
----------- -----------
Net cash provided by
investing activities 3,898,495 2,412,007
See accompanying notes to consolidated financial statements.
39
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows, Continued
Years ended December 31, 2002 and 2001
2002 2001
----------- -----------
Financing activities:
Payments on borrowings, preferred stockholders -- (218,412)
Payments on borrowings, related parties -- (2,000,000)
Payments of offering costs and other -- (145,357)
Dividends paid by subsidiary -- (235,610)
Net proceeds from the exercise of stock options -- 12,748
----------- -----------
Net cash provided by (used in)
financing activities -- (2,586,631)
----------- -----------
Increase in cash and cash equivalents 1,062,116 1,271,878
Cash and cash equivalents at beginning of year 3,343,560 2,071,682
----------- -----------
Cash and cash equivalents at end of year $ 4,405,676 3,343,560
=========== ===========
Supplementary cash flow information:
Interest paid $ 2,755 98,500
=========== ===========
Taxes paid $ -- 6,530
=========== ===========
Non cash investing and financing activities
Purchase of property and equipment financed with debt 750,000 --
=========== ===========
See accompanying notes to consolidated financial statements.
40
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2002 and 2001
(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
accounting principles generally accepted in the United States. Actual
results could differ from those estimated.
Cash Equivalents
Cash equivalents include liquid investments with an original maturity of
three months or less. Cash balances are maintained in depository and
overnight investment accounts with a financial institution which at times,
exceed insured limits. The Company monitors the financial condition of the
financial institution and has experienced no losses associated with these
accounts.
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. The
Company utilizes one cost center for all of its properties. Amortization of
such costs and estimated future development costs are determined using the
unit-of-production method. Provision for the estimated costs of offshore
platform and well abandonment, net of salvage value, is computed on the
units of production method and is included in depletion, depreciation and
amortization. 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 independent petroleum engineers or
prepared internally by the Company. The net carrying value of oil and gas
41
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
properties, less related deferred income taxes, is limited to the lower of
unamortized cost or the cost center ceiling, defined as the sum of the
present value (10% discount rate applied) of estimated future net revenues
from proved reserves, after giving effect to income taxes, and the lower of
cost or estimated fair value of unproved properties. Disposition of oil and
gas properties are recorded as adjustments to capitalized costs, with no
gain or loss recognized unless such adjustments would significantly alter
the relationship between capitalized costs and proved reserves.
The following table reflects the depletion expense incurred from oil and
gas properties during the periods indicated:
Year Ended
December 31,
2002 2001
--------- ---------
Depletion expense per Mcf
equivalent
produced $ 1.05 $ 1.53
========= =========
At December 31, 2002, oil and gas properties included $140,233 of unproved
leasehold costs that are not being amortized. These costs will begin to be
amortized when they are evaluated and proved reserves are discovered,
impairment is indicated or when the lease term expires. Unproved leasehold
costs consist of interests in state and federal leases located in the Gulf
of Mexico with expiration dates ranging from October 2003 to November 2005.
In order to retain the leases after the primary term, they must be
producing or development operations must be in progress. The leases have
primary terms of 5 years. Development of these leases is dependent upon the
other owners of the leases to initiate a plan of development.
The following table reflects the periods when costs were incurred for
unproved leasehold costs:
December 31,
----------------------
Total 2002 2001 Prior Years
--------- --------- --------- ---------
Property acquisition costs $ 101,097 (76,421) (102,920) 280,438
Exploration costs 39,136 (5,178) (106,030) 150,344
--------- --------- --------- ---------
$ 140,233 (81,599) (208,950) 430,782
========= ========= ========= =========
The Company capitalizes interest on expenditures made in connection with
significant exploration and production projects that are not subject to
current amortization. Interest is capitalized only for the period that
activities are in progress to bring these projects to their intended use.
No interest has been capitalized for the periods reflected herein.
Pipelines and Facilities
Pipelines and facilities are recorded at cost. Depreciation is computed
using the straight-line method over estimated useful lives of 10-22 years.
Provision for the estimated cost of pipeline and facilities abandonment,
net of salvage value, is computed on a straight line basis over the
estimated useful life of such assets and is included in Depletion,
Depreciation and Amortization.
42
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
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 3-10 years.
In accordance with Statement of Financial Accounting Standards ("SFAS") No.
144, Accounting for the Impairment or Disposal of Long-lived Assets, assets
are grouped and evaluated for impairment based on the ability to identify
separate cash flows generated therefrom. For the year ended December 31,
2001, the Company recorded a full impairment of $1.9 million of its
investment in both the Petroport and Sabine Seaport projects and for the
year ended December 31, 2002, the Company recorded a full impairment of
approximately $.4 million of its investment in Drillmar, Inc.
Abandonment
A provision for the abandonment, dismantlement and site clearance 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. Aggregate abandonment liability, all
of which is for the Buccaneer Field is estimated to be approximately $3.8
million at December 31, 2002. Based on timing of the reefing and related
payment plan $2.5 million is reflected as "Asset retirement obligations -
current portion" and $1.3 million is reflected as a long-term liability,
due to the extended payment terms arranged by the Company.
New Avoca and Drillmar
The Company records its investment in New Avoca (25% owned and managed by
the Company) and Drillmar using the equity method of accounting. Under the
equity method, investments are recorded at cost plus the Company's equity
in undistributed earnings and losses after acquisition.
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 accounts for stock-based compensation under the intrinsic value
method and provides the pro forma effects of the fair value method as
required.
43
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Recognition of Oil and Gas Revenue
Sales from producing wells are recognized on the entitlement method of
accounting which defers recognition of sales when, and to the extent that,
deliveries to customers exceed the Company's net revenue interest in
production. Similarly, when deliveries are below the Company's net revenue
interest in production, sales are recorded to reflect the full net revenue
interest. The Company's imbalance liability at December 31, 2002 and 2001
was not material.
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.
Income Taxes
The Company provides for income taxes using the asset and liability method
pursuant to SFAS No. 109, Accounting for Income Taxes ("Statement 109").
Under the asset and liability method of Statement 109, deferred tax assets
and liabilities are recognized for the future tax consequences attributable
to differences between the financial statement carrying amounts of existing
assets and liabilities and their respective tax bases and operating loss
and tax credit carryforwards. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable income in the
years in which those temporary differences are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of a change in
tax rates is recognized in income in the period that includes the enactment
date.
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.
The employee stock options at December 31, 2001, were not included in the
computation of diluted earnings per share because the effect of their
assumed exercise and conversion would have an antidilutive effect on the
computation of diluted loss per share. In 2002 there was one employee stock
option that was used in the computation of diluted earnings per share.
The following table provides a reconciliation between basic and diluted
earnings per share:
44
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Weighted-
Average Number
of Common Shares
Outstanding
and Potential Per
Net Income Dilutive Share
(Loss) Common Shares Amount
------------- ------------- -------------
Year ended December 31, 2002
Basic earnings per share $ 482,054 6,343,834 $ 0.08
Effect of dilutive stock options 15,238
------------- ------------- -------------
Diluted earnings per share $ 482,054 6,359,072 $ 0.08
============= ============= =============
Year ended December 31, 2001
Basic and diluted earnings per share $ (2,649,142) 6,004,019 $ 0.44
============= ============= =============
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 August 2001, the FASB issued Statement No. 143 ("SFAS 143"), "Accounting
for Asset Retirement Obligations," which addresses financial accounting and
reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. The standard
applies to legal obligations associated with the retirement of long-lived
assets that result from the acquisition, construction, development and/or
normal use of the asset.
SFAS 143 requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is incurred
if a reasonable estimate of fair value can be made. The fair value of the
liability is added to the carrying amount of the associated asset and this
additional carrying amount is depreciated over the life of the asset. If
the obligation is settled for other than the carrying amount of the
liability, the Company will recognize a gain or loss on settlement.
45
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
The Company is required and plans to adopt the provisions of SFAS 143 for
the quarter ending March 31, 2003. To accomplish this, the Company must
identify all legal obligations for asset retirement obligations and
determine the fair value of these obligations on the date of adoption. The
determination of fair value is complex and requires the Company to gather
market information and develop cash flow models. Additionally, the Company
is required to develop processes to track and monitor these obligations.
The Company currently estimates that the adoption of SFAS 143 will result
in the recording of an asset retirement obligation of $1.6 million.
In May 2002, the FASB issued Statement of Financial Accounting Standards
No. 145 ("SFAS 145"), "Rescission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections". This
Statement rescinds FASB Statements No. 4, Reporting Gains and Losses from
Extinguishment of Debt, and an amendment of Statement No. 4 and FASB
Statement No. 64, Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements. This Statement also rescinds FASB Statement No. 44,
Accounting for Intangible Assets of Motor Carriers. This Statement amends
FASB Statement No. 13, Accounting for Leases, to eliminate an inconsistency
between the required accounting for sale-leaseback transactions and the
required accounting for certain lease modifications that have economic
effects that are similar to sale-leaseback transactions. SFAS 145 is
effective for fiscal years beginning after May 15, 2002. The Company does
not expect the adoption of SFAS 145 to have a material effect on the
Company's financial condition and results of operations.
In June 2002, the FASB issued Statement of Financial Accounting Standards
No. 146 ("SFAS 146"), "Accounting for Costs Associated with Exit or
Disposal Activities". This Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and
nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)". SFAS 146
is effective for exit or disposal activities initiated after December 31,
2002. The Company does not expect the adoption of SFAS 146 to have a
material effect on the Company's financial condition and results of
operations.
In December 2002, the FASB issued Statement of Financial Accounting
Standards ("SFAS") No. 148, "Accounting for Stock-Based Compensation,
Transition and Disclosure." SFAS No. 148 provides alternative methods of
transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. SFAS No. 148 also
requires that disclosures of the pro forma effect of using the fair value
method of accounting for stock-based employee compensation be displayed
more prominently and in a tabular format. Additionally, SFAS No. 148
requires disclosure of the pro forma effect in interim financial
statements. The transition and annual disclosure requirements of SFAS No.
148 are effective for fiscal years ending after December 15, 2002. The
interim disclosure requirements are effective for interim periods beginning
after December 15, 2002. The Company does not expect that the adoption of
SFAS 148 will have a material effect on its financial position or results
of operations.
46
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
(2) Liquidity
At December 31, 2002, the Company's working capital was approximately $2.2
million. During the third and fourth quarters of 2002, the Company received
approximately $5.0 million from the sale of proved oil and gas properties
from two separate transactions. As a result, the Company believes that it
has sufficient cash to meet its working capital and capital expenditure
requirements through 2003. Historically, the Company has relied on the
proceeds from the sale of assets and capital raised from the issuance of
debt and equity securities to individual investors and related parties to
sustain its operations.
(3) 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 Note Payable approximates the fair
value due to its interest rate approximating current borrowing rates.
(4) Income Taxes
Income tax expense for both 2002 and 2001 was $0.
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, 2002 are presented below:
Deferred tax assets:
Net operating loss and capital loss carryforwards $ 11,753,227
Alternative minimum tax credit 388,336
Basis differences in property and equipment 731,629
------------
Total gross deferred tax asset 12,873,192
------------
Net deferred tax asset 12,873,192
Less valuation allowance (12,628,748)
------------
Deferred tax asset $ 244,444
============
In 1999, the Company acquired a 75% interest in American Resources, which
had deferred tax assets of approximately $8.5 million made up of basis
differences in oil and gas properties and net operating losses. A full
valuation allowance was recorded to reduce the corresponding deferred
assets, since it is more likely than not that they will not be realized,
due to the limitation of the use of the net operating loss carryforwards
resulting from the ownership change in December 1999.
In assessing the realizability of deferred tax assets, the Company applies
SFAS No. 109 to determine whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. As a
result, the Company's valuation allowance at December 31, 2002 reduces the
deferred tax assets to $244,444.
47
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
The Company's effective tax rate applicable to continuing operations in
2002 and 2001 is as follows:
2002 2001
-------- --------
Expected tax rate (34%) (34%)
State taxes, net of federal benefit -- --
Expenses not deductible for tax purposes -- --
Increase in valuation allowance recognized
in earnings 34% 34%
Other -- --
-------- --------
0% 0%
For federal tax purposes, the Company had a net operating loss carryforward
("NOL") of approximately $32.0 million and $31.1 million for the years
ended December 31, 2002 and 2001, respectively. These NOLs must be utilized
prior to their expiration, which is between 2003 and 2022. Of the $32.0
million of NOLs as of December 31, 2002, $17.2 million relate to American
Resources.
The Company has alternative minimum tax credit carry forwards of $388,336
that do 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.
(5) Long-term Debt
In February 2002, the Company acquired a 1/3 interest in the Blue Dolphin
Pipeline System and the inactive Omega Pipeline from MCNIC Pipeline and
Processing Company ("MCNIC") effective January 1, 2002. Pursuant to the
terms of the purchase and sales agreement, Blue Dolphin issued MCNIC a
$750,000 promissory note due December 31, 2006, with required monthly
payments to be made out of 90% of the net revenues of the interest
acquired. As of December 31, 2002, net revenues attributable to the
acquired interest were insufficient to provide any principal payments,
however the note continues to accrue interest at 6% per annum.
Additionally, an aggregate contingent payment of up to $750,000 will be
made, if the promissory note is retired before its maturity date. The
contingent payments will be payable annually after the promissory note is
retired until December 31, 2006 out of 50% of the net revenues from the
interest acquired. The termination date, December 31, 2006, will be
extended by one additional year, up to a maximum of two years, for years in
which non-recurring, extraordinary expenditures attributable to the
interest acquired, exceeds $200,000, in the aggregate, during any year.
Currently, the Company does not believe that net revenues from the 1/3
interest in the Blue Dolphin Pipeline System will be sufficient enough to
provide any principal payments to MCNIC in the year ending December 31,
2003.
Long-term debt at December 31, 2002 is as follows:
Note payable, interest at
6% per annum payable out of 90%
of the net revenues from the 1/3 interest
acquired in the Blue Dolphin Pipeline
System, secured by the 1/3 interest
acquired, all remaining principal due
December 31, 2006. $ 750,000
Less current maturities --
------------
$ 750,000
============
48
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
(6) Stockholders' Equity
On December 2, 1999, the Company, through Blue Dolphin Exploration,
acquired a 75% ownership interest in American Resources by purchasing
approximately 39.5 million shares of American Resources common stock. On
February 19, 2002, the Company completed its acquisition of American
Resources, pursuant to the Amended and Restated Agreement and Plan of
Merger dated as of December 19, 2001 (the "Merger Agreement"). Pursuant to
the Merger Agreement, American Resources became a wholly owned subsidiary
of the Company and each outstanding share of (i) American Resources common
stock, par value $.00001 per share, was converted into the right to
receive, at the option of the holder, either $.06 per share in cash or
.0362 of a share of the Company's Common Stock, par value $.01 per share
(the "Common Stock"), and (ii) American Resources Series 1993 Preferred
Stock, par value $12.00 per share, was converted into the right to receive,
at the option of the holder, either $.07 in cash or .0301 of a share of
Common Stock.
As a result of elections made by American Resources' stockholders, the
Company issued 277,330 shares of Common Stock and paid $255,000 in cash.
The Company incurred costs totaling $101,128 and $185,943 in 2002 and 2001,
respectively, associated with the registration of shares of its Common
Stock that were issued to American Resources stockholders. In addition, the
Company issued 62,603 and 17,867 shares of its Common Stock in 2002 and
2001, respectively, as a severance payment to former employees and recorded
compensation expense of $70,740 and $28,586 in 2002 and 2001, respectively.
The Company also issued 25,060 and 2,824 shares in 2002 and 2001,
respectively, to the board of directors and recorded an expense of $21,000
and $12,000 in 2002 and 2001, respectively.
(7) Stock Options
Effective April 14, 2000, the Company adopted, after approval by
stockholders, a stock incentive plan (the "2000 Plan"). The stock subject
to the options and other provisions of the 2000 Plan are shares of the
Company's Common Stock $.01 par value (the "Stock"). No more than 500,000
shares of Stock will be available for incentive stock options ("ISOs"). The
2000 Plan is administered by the Compensation Committee of the Board of
Directors. Options granted must be exercised within 10 years from their
grant date. The exercise price of ISOs cannot be less than 100% of the fair
market value of a share of Stock. The 2000 Plan also provides for the
granting of other incentive awards, however only ISOs and non-statutory
stock options have been issued under the 2000 Plan.
The Company adopted a stock option plan in 1996 (the "1996 Plan"). The
stock subject to the options and other provisions of the 1996 Plan are
shares of the Company's Common Stock. The total amount of the Common 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, appointed by the
49
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
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 Common 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.
At December 31, 2002 the Company has reserved a total of 416,321 shares of
Common Stock for issuance under the above mentioned stock option plans. 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, 2000 151,236 2.78 6.000
======== ======== ========
Granted 42,104 1.90 1.900
Expired (36,834) 3.12 6.000
Exercised (3,333) 3.82 3.825
-------- -------- --------
Balance, December 31, 2001 153,173 1.90 6.000
======== ======== ========
Granted 340,277 0.33 1.550
Expired (77,129) 1.55 6.000
-------- -------- --------
Balance, December 31, 2002 416,321 0.33 6.000
======== ======== ========
The weighted average exercise price per share was $3.825 in 2001.
As of December 31, 2002, options for 400,988 shares of Common Stock were
immediately exercisable. There were 340,277 and 42,104 options granted in
2002 and 2001, respectively. Pursuant to the requirements of FASB No. 123,
the weighted average fair market value of options granted during 2002 and
2001 was $0.94 per share and $0.24 per share, respectively. The weighted
average closing bid prices for the Company's stock at the date the options
were granted during 2002 and 2001 were $1.01 per share and $1.90 per share,
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 88% and
29%, risk-free interest rate of 1.45% and 2.22% for grants in 2002 and
2001, respectively, and an expected life of 1 year. As the Company has not
declared dividends on its Common Stock since it became a public entity, no
dividend yield was used. Actual value realized, if any, is dependent on the
future performance of the Company's Common Stock and overall stock market
conditions. There is no assurance the value realized by an optionee will be
at or near the value estimated by the Black-Scholes model. No compensation
expense was recorded in 2002 and 2001 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, the
Company's net income (loss) and income (loss) per share would have been
adjusted to the pro forma amounts indicated below:
50
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Year ended December 31,
--------------------------
2002 2001
----------- -----------
Net income (loss) as reported $ 482,054 $(2,649,142)
Less total stock based employer compensation
expense determined under fair value based
method for all awards, net of tax related effects (250,234) (110,294)
----------- -----------
Pro Forma $ 231,820 $(2,759,436)
=========== ===========
Basic and diluted (loss)
Per share as reported $ 0.08 $ (0.44)
Pro Forma $ 0.04 $ (0.46)
Outstanding options at December 31, 2002 expire between December 25, 2003
and November 13, 2012.
(8) Related Party Transactions
Related party transactions which are not disclosed elsewhere in these
consolidated financial statements are discussed in the following
paragraphs:
In September 2001, Drillmar, Inc. a 64% owned affiliate of the Company,
entered into a merger agreement and merged with Zephyr Drilling Ltd.
("Zephyr"). Prior to the merger, Zephyr was a limited partnership in which
Drillmar was the general partner. Zephyr owned a semi-submersible drilling
rig that has been prepared for reconfiguration into a semi-tender. As a
result of the merger, the Company's interest in Drillmar decreased from 64%
to 12.8%.
Ivar Siem, Chairman of the Company, Harris A. Kaffie and James M. Trimble,
Directors of the Company, were limited partners of Zephyr. After the merger
between Drillmar and Zephyr, Messers. Siem and Kaffie were owners of 30.3%
and 30.6%, respectively, of Drillmar's common stock. Messrs. Siem and
Kaffie are both Directors, and Mr. Siem is Chairman and President of
Drillmar. Messrs. Siem and Kaffie provided funding to Drillmar in 2002 of
$116,000 and $100,000, respectively, and in 2001 of $300,000 and $425,000,
respectively, and were issued unsecured promissory notes from Drillmar. The
promissory notes were due June 30, 2002 and bore interest at the rate of
10% per annum. Along with the promissory notes, Drillmar issued detachable
warrants to Messrs. Siem and Kaffie of 41,500 and 42,500, respectively. The
promissory notes issued by Drillmar are nonrecourse to the Company.
Effective March 31, 2002, the Company recorded a full impairment of its
investment in Drillmar of approximately $340,000 and a full reserve for the
accounts receivable amount owed from Drillmar of approximately $200,000 due
to Drillmar's working capital deficiency and delays in securing capital
funding.
51
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
In May 2002, the Company and Drillmar entered into a new agreement
effective as of May 1, 2002, whereby the Company will provide office space
and minimal accounting and administrative services to Drillmar for $2,000
per month. If Drillmar is able to secure financing to implement its
business plan, the fee will increase to $20,000 per month retroactive to
May 1, 2002. The agreement can be terminated upon 30 days notice or by the
mutual agreement of the parties.
In January 2003, Drillmar stockholders approved a restructuring plan
whereby Drillmar will issue up to $3.0 million of convertible notes that
will convert into common stock representing over 99% of Drillmar's
outstanding shares. As a result, the Company's ownership in Drillmar will
be reduced to less than 1%. Messrs. Siem and Kaffie are expected to
exchange their promissory notes and accrued interest into Drillmar new
convertible notes.
In February 2003, the Company and Drillmar entered into a new agreement
effective as of February 1, 2003, whereby the Company will provide office
space to Drillmar for $1,500 per month. The Company will also provide
professional, accounting and administrative services to Drillmar based on
hourly rates based on the Company cost. The agreement can be terminated
upon 30 days notice or by the mutual agreement of the parties.
(9) Leases
The Company has various noncancelable operating leases which continue
through 2006. In March 2003, the Company entered into a sublease agreement
expiring December 31, 2006 for certain of its office space with Tri-Union
Development Corporation. The Company's annual receipts from this sublease
will be $81,630. Mr. James M. Trimble, Director of the Company is the
Chairman and Chief Executive Officer of Tri-Union.
The following is a schedule of future minimum lease payments required under
noncancelable operating leases at December 31, 2002:
Future Future
Year ending minimum Future minimum
December 31, lease sublease lease
------------ payments payments payments, net
------------- ------------- -------------
2003 $ 203,826 $ 67,943 $ 135,883
2004 201,432 81,630 119,802
2005 198,153 81,630 116,523
2006 195,618 81,630 113,988
------------- ------------- -------------
$ 799,029 $ 312,833 $ 486,196
============= ============= =============
Rental expense on operating leases, net of sublease income for the years
indicated are as follows:
Year ended
December 31,
------------
2002 $ 186,498
2001 198,548
52
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
(10) Commitments and Contingencies
As a result of the decision to cease operating activities in the Buccaneer
Field, the Company's leases in or on the Buccaneer Field terminated in
January 2001. The Company must plug and abandon all remaining wells and
remove platform facilities within one year from the termination of the
leases. In 2001, the Company plugged its remaining wells at a cost of
approximately $1.4 million. During the operations of removing the Buccaneer
Field platform complexes in 2001, discussions were initiated with the Texas
Parks and Wildlife Department ("TPW") in an effort to leave certain of the
underwater portions of the platform complexes in place as artificial reefs.
By leaving the platform complexes in place as an artificial reef, certain
site clearance costs will be eliminated. On January 3, 2003, the Company
and TPW executed deeds of donation for both of the Company's platform
complexes in the Buccaneer Field, whereby the Company will leave certain of
the underwater portions of the platforms in place as artificial reefs and
donate them to the TPW, along with cash of $390,000, of which $350,000
represents half of the site clearance work that will be eliminated and
$40,000 represents the cost of buoys to mark the reef sites. In addition,
the Company has reduced its provision for abandonment costs by $310,000,
due to the elimination of site clearance and by $373,000 due to lowering
its contingency associated with the abandonment work. The Company requested
and has received an extension from the MMS until April 1, 2003 to complete
the abandonment operations needed to convert the platform complexes into
artificial reefs. The work to complete the abandonment/reefing is expected
to begin and be completed during the second quarter 2003. The Company will
seek a further extension from the MMS. The Company believes that its
provision for abandonment costs of $3.8 million at December 31, 2002 is
adequate.
In May 2002, the Company, American Resources and members of prior
management of American Resources, including its former chief financial
officer, entered into a settlement agreement with H&N Gas. American
Resources paid approximately $0.3 million in settlement of this litigation
and additionally released funds of approximately $0.7 million it was
holding that were due to H&N. The settlement agreement and the payments
made thereunder were made in compromise of disputed claims and are not an
admission of wrongdoing or of liability of any kind.
The Company is involved in various other 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, results of operations or cash flows.
(11) Business Segment Information
The Company's income producing operations are conducted in two principal
business segments: oil and gas exploration and production, which includes
upstream projects, and pipeline operations, which includes mid-stream
projects. Intersegment revenues consist of transportation, general
processing and storage fees charged by one subsidiary to another for 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, 2002
and 2001 is as follows:
53
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Depletion,
Operating Depreciation,
income Identifiable Amortization and
Revenues (loss)(1) assets Impairment (2)
----------------- ----------------- ----------------- ----------------
Year ended December 31, 2002:
Oil and gas exploration and
production $ 1,781,958 (256,252) 4,720,424 615,037
Pipeline operations 1,128,319 (465,358) 4,990,027 182,505
Other -- (1,391,982) 1,037,457 361,084
----------------- ----------------- ----------------- ----------------
Consolidated 2,910,277 (2,113,592) 10,747,908 1,158,626
Other income 2,539,900
-----------------
Income before income taxes 426,308
Year ended December 31, 2001:
Oil and gas exploration and
production and
operating fees $ 4,694,202 (616,124) 5,125,652 2,627,626
Pipeline operations 991,823 (11,756) 4,433,200 163,858
Other -- (3,189,867) 2,230,160 1,966,750
----------------- ----------------- ----------------- -----------------
Consolidated 5,686,025 (3,817,747) 11,789,012 4,758,234
Other income 1,272,727
-----------------
Loss before income taxes (2,545,020)
1. Consolidated income (loss) from operations includes $1,030,897 and
$1,223,117 in unallocated general and administrative expenses, and
unallocated depletion, depreciation, amortization and impairment of
$361,084 and $1,966,750 for the years ended December 31, 2002 and
2001, respectively.
2. Pipeline depletion, depreciation and amortization includes a provision
for pipeline abandonment of $32,901 and $19,740 for the years ended
December 31, 2002 and 2001, respectively. Oil and gas depletion,
depreciation and amortization includes a provision for abandonment
costs of platforms and wells of $0 and $13,793 for the years ended
December 31, 2002 and 2001, respectively. In addition, the Company
recorded an expense of approximately $1.0 million for the year ended
December 31, 2001, as a result of a change in the estimated costs
associated with the Buccaneer Field abandonment.
3. 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 $180,600 and $1,737,331
were incurred for pipeline operations for the years ended December 31,
2002 and 2001, respectively. Capitalized expenditures of $0 and
$59,305 were incurred for mid-stream projects for the years ended
December 31, 2002 and 2001, respectively.
54
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
The Company's primary market area is the Texas and Louisiana Gulf Coast
region of the United States. The Company has a concentration of credit risk
with customers in the energy and petrochemical 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 period
indicated.
Oil and gas
sales and Pipeline
operating fees operations Total
-------------- ------------ ------------
Year ended December 31, 2002:
Houston Exploration and Production Company $ -- 290,223 290,223
Apache Corporation $ -- 282,215 282,215
Year ended December 31, 2001:
Houston Exploration and Production Company $ -- 639,975 639,975
(12) 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").
In July 2002, American Resources sold its working interest in the South
Timbalier Block 148 property to Newfield Exploration Company for $2.3
million and recorded a gain of $1.4 million. Production from this field
accounted for 15% and 19% of the Company's oil and gas sales revenues for
the years ended December 31, 2002 and 2001, respectively, and 9% and 16% of
the Company's total revenues for these periods.
In November 2002, American Resources sold its working interest in all of
its remaining proved oil and gas properties to Fidelity Exploration &
Production Company for $2.7 million and recorded a gain of $0.8 million.
Production from these fields accounted for 85% and 81% of the Company's oil
and gas sales revenues for the years ended December 31, 2002 and 2001,
respectively, and 52% and 67% of the Company's total revenues for these
periods.
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 gas reserves for the periods
indicated, as estimated by the Company as of December 31, 2002 and by Ryder
Scott Company as of December 31, 2001. 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.
55
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Proved reserves are estimated quantities of 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, 2000
185,135 4,667,000
---------- ----------
Revisions to previous estimates (13,476) (841,816)
Production (40,769) (815,184)
---------- ----------
Total proved reserves at December 31, 2001 130,890 3,010,000
---------- ----------
Production (28,230) (418,895)
Reserves sold (101,213) (2,311,105)
---------- ----------
Total proved reserves at December 31, 2002 1,447 280,000
Proved developed reserves:
December 31, 2002 1,447 280,000
December 31, 2001 128,783 2,613,000
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 December 31, 2002:
Unproved properties and prospect generation
costs not being amortized $ 140,233
Proved properties being amortized 21,780,258
Less accumulated depletion, depreciation,
amortization and impairment (21,780,258)
------------
Net capitalized costs $ 140,233
============
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:
56
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Year Ended
December 31,
-----------------------
2002 2001
---------- ----------
Exploration costs $ -- 249,728
Development costs 512,393
773,115
---------- ----------
$ 512,393 1,022,843
========== ==========
Standardized Measure of Discounted
Future Net Cash Flows
Due to the sale of substantially all of the reserves during 2002, there are
no Future Net Cash Flows as of December 31, 2002. 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,
----------------------------
2002 2001
------------ ------------
Future cash inflows $ 1,183,824 $ 10,374,365
Future development costs (342,210) (1,190,585)
Future production costs (84,930) (1,761,074)
------------ ------------
Future net cash inflows before income taxes 756,684 7,422,706
Future income taxes (257,273) 10,473,236
------------ ------------
Future net cash flows 499,411 17,895,942
10% discount factor (6,017) (920,497)
------------ ------------
Standardized measure of discounted
future net cash inflow $ 493,394 16,975,445
============ ============
Future net cash flows at each year end, as reported in the above schedule,
were determined by summing the estimated annual net cash flows computed by:
(1) multiplying estimated quantities of proved reserves to be produced
during each year by current prices 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 flow.
57
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
The Company cautions readers that the standardized measure information
which places a value on proved reserves is not indicative of either fair
market value or present value of future cash flows. Other logical
assumptions could have been used for this computation which would likely
have resulted in significantly different amounts. Such information is
disclosed solely in accordance with Statement 69 and the requirements
promulgated by the SEC to provide readers with a common base for use in
preparing their own estimates of future cash flows and for comparing
reserves among companies. Management of the Company does not rely on these
computations when making investment and operating decisions. Principal
changes in the Standardized Measure of Discounted Future Net Cash Flows
attributable to the Company's proved oil and gas reserves for the periods
indicated are as follows:
December 31,
----------------------------
2002 2001
------------ ------------
Sales and transfers, net of production costs $ (1,263,038) (3,538,653)
Acquisition of reserves -- --
Net change in estimated future development costs -- 980,063
Sales of minerals in place (4,454,581) --
Revisions in previous quantity estimates 162,782 (1,663,095)
Net changes is sales and transfer prices, (161,868) (27,307,388)
net of production costs
Accretion of discount 602,801 3,688,897
Net change in income taxes 3,236,489 13,719,714
Change in production rates (timing) and other (14,604,636) (5,551,671)
------------ ------------
Net change $(16,482,051) (19,672,133)
============ ============
(13) Sales of Assets
On January 22, 2001, the Company sold its 50% interest in the Black Marlin
Pipeline System to affiliates of the Williams Companies, Inc. for
approximately $4.6 million. The Black Marlin Pipeline System includes a
75-mile gas and condensate gathering line with related shore facilities
servicing the High Island Area, offshore Texas (the "Black Marlin
Pipeline") and a 3-mile lateral pipeline extending from High Island Block
A-5 to an interconnection to the Black Marlin Pipeline in High Island Block
A-6 (the "A-5 Lateral").
This disposition was consummated, in part, through a sale of all of the
outstanding capital stock of Black Marlin Pipeline Company (formerly an
indirect wholly owned subsidiary of the Company) the owner of a 50%
interest in the Black Marlin Pipeline, pursuant to a Purchase and Sale
Agreement dated January 12, 2001 (the "Stock Purchase Agreement") among
Black Marlin Energy Company, a wholly owned subsidiary of the Company,
MCNIC Pipeline & Processing Company ("MCNIC"), WBI Southern, Inc. ("WBI")
and Williams Field Services Group, Inc. The Company received $3.6 million
for the outstanding capital stock of Black Marlin Pipeline Company for a
gain of $1,305,534.
The remaining part of this disposition was consummated through the sale of
the A-5 Lateral owned 50% by Blue Dolphin Pipe Line Company, a wholly owned
subsidiary of the Company ("BDPL"), pursuant to a Purchase and Sale
Agreement dated January 12, 2001, among BDPL, MCNIC, WBI and Williams Field
Services - Gulf Coast Company, L.P. The Company received $1.0 million for
its interest in the A-5 Lateral, for a gain of $112,092.
58
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
In connection with Blue Dolphin Exploration's acquisition of American
Resources in December 1999, Blue Dolphin Exploration arranged for Fidelity
Oil to acquire an 80% interest in American Resources oil and gas assets
located in the Gulf of Mexico for approximately $24.2 million. For the
right to participate in the acquisition of these assets, Fidelity Oil
agreed to assign Blue Dolphin Exploration 10% of its working interest in
the proved properties acquired from American Resources after it has
recovered its investment in these properties. In the fourth quarter 2001,
Fidelity Oil had recovered its investment in the proved properties.
However, instead of assigning 10% of its interest in the proved properties,
Fidelity Oil paid Blue Dolphin $1.4 million in cash in December 2001. The
proceeds were accounted for as a reduction to capitalized costs of oil and
gas properties.
See footnote (12) Supplemental Oil and Gas Information - Unaudited for
disclosure of oil and gas properties sold in 2002.
59
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
None.
Item 9. Directors and Executive Officers of the Registrant
The information required by Item 9 is incorporated by reference to the
Company's definitive proxy statement relating to its 2003 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 10. Executive Compensation
The information required by Item 10 is incorporated by reference to the
Company's definitive proxy statement relating to its 2003 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. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholders Matters
The information required by Item 11 is incorporated by reference to the
Company's definitive proxy statement relating to its 2003 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. Certain Relationships and Related Transactions
The information required by Item 12 is incorporated by reference to the
Company's definitive proxy statement relating to its 2003 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.
PART III
Item 13. Exhibits and Reports on Form 8-K
(a) 1. Exhibits
60
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 (4) 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 (3) Blue Dolphin Energy Company 1996 Employee Stock Option Plan.
* 10.2 (6) Blue Dolphin Energy Company 2000 Stock Incentive Plan
10.11(5) Investment Agreement, as amended, by and between American
Resources Offshore, Inc. and Blue Dolphin Exploration Company.
10.12(7) Purchase and Sale Agreement by and between Williams Field
Services Group, Inc. and Black Marlin Energy Company
10.13(7) Purchase and Sale Agreement by and between Williams Field
Services - Gulf Coast Company, L.P. and Blue Dolphin Pipeline
Company
10.14(8) Amended and Restated Agreement and Plan of Merger dated as of
December 19, 2001 (the "Merger Agreement") among Blue Dolphin
Energy Company, American Resources Offshore, Inc. and BDCO Merger
Sub, Inc.
10.15(10) Amended and Restated Agreement and Plan of Merger, as amended,
among American Resources Offshore, Inc., Blue Dolphin Energy
Company and BDCO Merger Sub, Inc.
10.16(9) Letter agreement between Blue Dolphin Exploration Company and
Fidelity Exploration & Production Company.
10.17(9) Amendment No.1 to the Amended and Restated Agreement and Plan of
Merger.
10.18(11) Purchase and Sale Agreement by and between Blue Dolphin Energy
Company and Newfield Exploration Company.
10.19(12) Purchase and Sale Agreement by and between Blue Dolphin Energy
Company and Fidelity Exploration and Production Company.
61
** 10.20 Purchase and Sale Agreement by and between Blue Dolphin Pipeline
Company and MCNIC.
** 21.1 List of subsidiaries of the Company.
** 23.1 Consent of Mann Frankfort Stien & Lipp CPAs, LLP.
** 99.1 Michael J. Jacobson Certification Pursuant to 18 U.S.C. Section
1350, as adopted pursuant to section 906 of the Sarbanes-Oxley
Act of 2002.
** 99.2 G. Brian Lloyd Certification Pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to section 906 of the Sarbanes-Oxley Act of
2002.
(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, 1995
under the Securities and Exchange Act of 1934, dated March 29, 1996
(Commission File No. 000-15905).
(4) 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).
(5) Incorporated herein by reference to Exhibits filed in connection with
Schedule 13D of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated October 22, 1999 (Commission File No.
000-15905).
(6) Incorporated herein by reference to Exhibits filed in connection with the
Proxy Statement of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated May 18, 2000 (Commission File No. 000-15905).
(7) 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 January 22, 2001 (Commission File No. 000-15905).
(8) Incorporated herein by reference to Exhibits filed in connection with Form
S-4 of Blue Dolphin Energy Company under the Securities Act of 1933
(Commission File No. 333-82186).
(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 February 25, 2002 (Commission File No. 000-15905).
(10) 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 July 23, 2002 (Commission File No. 000-15905).
62
(11) 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 November 4, 2002 (Commission File No. 000-15905).
* Management Compensation Plan.
** Filed herewith.
(b) Reports on Form 8-K
None
ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this Annual Report, the Company
carried out an evaluation, under the supervision and with the participation
of the Company's management, including the Company's Chief Executive
Officer and Primary Financial Officer, of the effectiveness of the design
and operation of the Company's disclosure controls and procedures (as
defined in Rules 13a - 14(c) and 15d - 14 (c) under Securities Exchange Act
of 1934, as amended). Based upon the evaluation, the Chief Executive
Officer and Primary Financial Officer concluded that the Company's
disclosure controls and procedures are effective to ensure that information
required to be disclosed by the Company in reports that it files or submits
under the Securities Exchange Act of 1934, as amended is recorded,
processed, summarized and reported within the time periods specified in
Securities and Exchange Commission rules and forms. There were no
significant changes in the Company's internal controls or in other factors
that could significantly affect these controls subsequent to the date of
their evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
63
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 21, 2003
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 21, 2003
------------------------- executive officer)
Michael J. Jacobson
/s/ G. Brian Lloyd Vice President, Treasurer March 21, 2003
------------------------- (principal accounting and
G. Brian Lloyd financial officer)
/s/ Ivar Siem Chairman March 21, 2003
-------------------------
Ivar Siem
/s/ Harris A. Kaffie Director March 21, 2003
-------------------------
Harris A. Kaffie
/s/ Michael S. Chadwick Director March 21, 2003
-------------------------
Michael S. Chadwick
/s/ Robert D. Wagner, Jr. Director March 21, 2003
-------------------------
Robert D. Wagner, Jr.
/s/ James M. Trimble Director March 21, 2003
-------------------------
James M. Trimble
64
CERTIFICATION BY MICHAEL J. JACOBSON PURSUANT TO SECURITIES EXCHANGE ACT RULE
13a-14
I, Michael J. Jacobson, certify that:
I have reviewed this annual report on Form 10-KSB of Blue Dolphin Energy Company
(the "Registrant").
1. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report
2. Based on my knowledge, the financial statements and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the Registrant as of, and for, the periods presented in this annual report;
3. The Registrants other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the Registrants disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
4. The Registrants other certifying officer and I have disclosed, based on our
most recent evaluation, to the Registrants auditors and the audit committee
of Registrants board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrants ability to record,
process, summarize and report financial data and have identified for the
registrants auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrants internal controls;
and
5. The Registrants other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weakness.
Date: March 21, 2003
/s/ Michael J. Jacobson
------------------------
Michael J. Jacobson
President and Chief Executive Officer
65
CERTIFICATION BY G. BRIAN LLOYD PURSUANT TO SECURITIES EXCHANGE ACT RULE 13a-14
I, G. Brian Lloyd, certify that:
I have reviewed this annual report on Form 10-KSB of Blue Dolphin Energy Company
(the "Registrant")
1. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
2. Based on my knowledge, the financial statements and other financial
information included in this Annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the Registrant as of, and for, the periods presented in this annual report;
3. The Registrants other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the Registrants disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
4. The Registrants other certifying officer and I have disclosed, based on our
most recent evaluation, to the Registrants auditors and the audit committee
of Registrants board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrants ability to record,
process, summarize and report financial data and have identified for the
registrants auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrants internal controls;
and
5. The Registrants other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weakness.
Date: March 21, 2003
/s/ G. Brian Lloyd
-------------------
G. Brian Lloyd
Vice President, Treasurer (Principal Accounting Officer)
66