UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB/A-1
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Act of 1934
For the fiscal year ended December 31, 2003
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.
The issuer's revenues for the year ended December 31, 2003 were
$2,516,814.
The aggregate market value of the common stock, par value $.01 per
share, held by non-affiliates of the registrant as of April 26, 2004, was
approximately $ 6,000,000.
As of April 26, 2004, there were outstanding 6,662,438 shares of common
stock, par value $.01 per share, of the issuer.
Documents Incorporated By Reference
None.
Transitional Small Business Disclosure Format. Yes No X
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TABLE OF CONTENTS
Page
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PART I
Item 1. Description of Business............................................ 1
Item 2. Description of Property............................................ 20
Item 3. Legal Proceedings.................................................. 21
Item 4. Submission of Matters to a Vote of Security Holders................ 21
PART II
Item 5. Market for Common Stock and Related Stockholder Matters............ 21
Item 6. Management's Discussion and Analysis of Financial Condition
and Results of Operations ...................................... 22
Item 7. Financial Statements and Supplementary Data........................ 29
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure ........................................... 55
Item 8A. Controls and Procedures............................................ 55
PART III
Item 9. Directors and Executive Officers of the Registrant ................ 56
Item 10. Executive Compensation............................................. 58
Item 11. Security Ownership of Certain Beneficial Owners and Management..... 61
Item 12. Certain Relationships and Related Transactions..................... 62
Item 13. Exhibits and Reports on Form 8-K................................... 63
Item 14. Principal Accountant Fees and Services............................. 65
Signatures ................................................................. 66
ii
PART I
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", "we", "us" and "our") 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 the level of production from oil and gas properties;
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 the level of utilization of our pipelines;
o availability and cost of capital;
o actions or inactions of third party operators for properties
where we have 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. We
undertake no duty to update these forward-looking statements. Readers are urged
to carefully review and consider the various disclosures made by us which
attempt to advise interested parties of the additional factors which may affect
our business, including the disclosures made under the caption "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
this report.
Item 1. Description of Business
THE COMPANY
Blue Dolphin Energy Company is a holding company that conducts substantially all
of its operations through its subsidiaries. We conduct our business activities
in two primary business segments: (i) oil and gas exploration and production,
and (ii) pipeline operations, which includes developmental projects.
Substantially all of its assets consist of equity in its subsidiaries. The
subsidiaries and affiliates are as follows:
o Blue Dolphin Petroleum Company, a Delaware corporation;
o Blue Dolphin Pipe Line Company, a Delaware corporation;
o Blue Dolphin Exploration Company, a Delaware corporation;
o Blue Dolphin Services Co., a Texas corporation;
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o Petroport, Inc., a Delaware corporation;
o New Avoca Gas Storage, LLC, a Texas limited liability company
in which we own a 25% interest;
o Drillmar, Inc., a Delaware corporation in which we own a 12.8%
interest; and
o American Resources Offshore, Inc., a Delaware corporation;
Our principal executive office is located at 801 Travis, Suite 2100,
Houston, Texas, 77002, telephone number (713) 227-7660. Shore based facilities
are maintained in Freeport, Texas serving our Gulf of Mexico operations. We have
9 full-time employees. Our common stock is traded on the National Association of
Securities Dealers, Inc. Automated Quotation System ("NASDAQ") Small Cap Market
under the trading symbol "BDCO". Our home page address on the world wide web is
http://www.blue-dolphin.com.
Recent Developments
Abandonment of Buccaneer Field. We owned a 100% working interest in the
Buccaneer Field. In November 2000, we elected to abandon the Buccaneer Field due
to adverse developments in the field. In August 2001, we reached an agreement
with Tetra Applied Technologies, Inc. ("Tetra") to remove the Buccaneer Field
platforms for a cost of approximately $2.6 million. Pursuant to the agreement,
we agreed to pay 20% upon completion of the abandonment operations and 5% per
month for twelve months, with the remaining balance due in the thirteenth month.
To provide security for the extended payment terms, we provided Tetra with a
first lien on a 50% interest in the Blue Dolphin Pipeline System. Operations to
remove the platforms commenced in August 2001 and were completed in August 2003.
Before the removal operations were completed we commenced discussions with the
Texas Parks and Wildlife Department ("TPW"), and were granted permission, to
leave the underwater portion of the platforms in place as artificial reefs. We
executed Deeds of Donation in January 2003. As a result of TPW's approval, the
scope of the work to be performed by Tetra was changed to include reefing, from
complete removal. Pursuant to the Deeds of Donation with TPW, we agreed to pay
TPW $390,000, of which $350,000 represented half of the site clearance work that
was eliminated (which payment the TPW required) and $40,000 represented the cost
of buoys to mark the reef sites. While the scope of work with Tetra was changed,
the contract price and payment terms remained unchanged. Our payments to Tetra
began in September 2003. As of December 31, 2003, we had paid $.4 million to
TPW, $.9 million to Tetra and $.3 million of other costs. At December 31, 2003,
accounts payable includes $1.7 million due to Tetra, payable as described above.
We also reduced our provision for the Buccaneer Field abandonment costs
resulting in a gain of approximately $.5 million for the year ended December 31,
2003.
Blue Dolphin Exploration provided the U.S. Minerals Management Service
("MMS") surety bonds in the amount of $4.2 million for its abandonment
obligations for the Buccaneer Field. In January 2004, the surety terminated, and
the bonds were released.
Pipeline Operations and Activities
Our pipeline assets are held and operations conducted by Blue Dolphin
Pipe Line Company.
Our economic return on our pipeline system investments is solely
dependent upon the amounts of gas and condensate gathered and transported
through our pipeline systems. Competition for provision of gathering and
transportation services, similar to those provided by us, is intense in the
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market areas we serve. See Competition below. Since contracts for provision of
such services with third party producer/shippers may be for specified time
periods, 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 will be maintained in the future. We actively market gathering and
transportation services to prospective third party producer/shippers in the
vicinity of our 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. We own 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
facilities for condensate and gas separation and dehydration, 85,000 Bbls of
above-ground tankage for storage of crude oil and condensate, a barge loading
terminal on the Intracoastal Waterway and 360 acres of land in Brazoria County,
Texas where the Blue Dolphin Pipeline comes ashore and 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" liquids pipeline, transports crude oil and condensate
from the storage tanks to our 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 liquids (crude oil and condensate) and is
comprised of approximately 34 miles of 20-inch pipeline from a platform in
Galveston Area Block 288 to shore. An additional 4 miles onshore connects the
offshore segment to the shore facility at Freeport, Texas. In 2001, we installed
a platform in GA Block 288 to operate and maintain the Blue Dolphin Pipeline
System as a result of our 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. Additionally, the offshore segment includes 5
field gathering lines totaling approximately 27 miles, connected to the main
20-inch line. The 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. Current system capacity is
approximately 160 MMcf per day of gas and 7,000 Bbls per day of crude oil and
condensate. Gas throughput for the Blue Dolphin System averaged approximately 6%
and 9% of capacity during 2003 and 2002, respectively. During 2003, 100% of gas
and liquids volumes transported were attributable to production from third party
producer/shippers. See Note 11 to the Consolidated Financial Statements included
in Item 7.
Galveston Area Block 350 Pipeline. We own 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 "GA 350 Pipeline"),
approximately 14 miles south of our Blue Dolphin Pipeline. Current system
capacity is 65 MMcf per day of gas. The pipeline currently transports
approximately 14,000 Mcf of gas per day.
Other. We also own 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
3
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.
Avoca Gas Storage Project
In November 1999, we formed New Avoca Gas Storage, LLC ("New Avoca")
with WBI Holdings, Inc. ("WBI"), and together acquired the assets of Avoca Gas
Storage, Inc. from Northeastern Gas Caverns ("Northeastern"). We have a 25%
equity interest and are the manager of New Avoca. We record our 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 a pipeline for fresh water
o A 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 A 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. 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.
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 has reviewed 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 one or more salt plants
in the area. New Avoca also studied the transportation of brine to the salt
4
plants by rail cars. New Avoca believes that a combination of the use of
disposal wells and brine deliveries by either the pipeline or rail cars 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. New Avoca
estimates that it will take between 9 months to 15 months to file and receive
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.
We are currently, along with WBI, marketing our ownership interest in
New Avoca. We also began marketing capacity to potential users of the project to
enhance our sales effort. If we do not sell our interest in New Avoca, we will
need to secure financing in order to proceed with the project or otherwise
liquidate our interest. There can be no assurance that we will be able to sell
our interest in New Avoca on acceptable terms or that we will be able to secure
financing necessary to proceed with the project.
Oil and Gas Exploration and Production Activities
Our oil and gas assets are held by Blue Dolphin Petroleum and Blue
Dolphin Exploration. Our oil and gas exploration and production activities
include the exploration, acquisition, development, operation and, when
appropriate, disposition of oil and gas properties. We focus our oil and gas
acquisition and exploration activities in the western and central Gulf of
Mexico, and onshore Texas and Louisiana. The leasehold interests in properties
held by us are subject to royalty, overriding royalty and interests of others.
In the future, our 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 our rights and obligations with respect to our
properties, are defined in the "Glossary of Certain Oil and Gas Terms" on pages
20 and 21 of this Form 10-KSB.
Sale of Oil and Gas Properties. During 2002, we sold all of our
interests in our American Resources oil and gas properties in two separate
transactions described below. From October 2002 to late April 2003, we had no
interest in any producing oil and gas properties.
In July 2002, we sold our working interest in the South Timbalier Block
148 property for $2.3 million to Newfield Exploration Company. Production from
this field accounted for 15% of our oil and gas sales revenues and 9% of our
total revenues for the year ended December 31, 2002. In November 2002, we sold
our working interest in all of our remaining American Resources proved oil and
gas properties for $2.7 million to Fidelity Exploration & Production Company.
Production from these fields accounted for 85% of our oil and gas sales revenues
and 52% of our total revenues for the year ended December 31, 2002.
The following is a description of our oil and gas exploration and
production assets and activities:
High Island Block A-7. In April 2003, we began to receive revenue from
our 8.9% reversionary working interest in the High Island Block A-7 field, in
the Gulf of Mexico, as a result of "payout" occurring. Payout occurred when all
of the other working interest owners recovered their costs and expenses
associated with developing the field from sales of gas and oil production from
the field. High Island Block A-7 is located 33 miles offshore Texas in an
average water depth of 39 feet. We own an 8.9% working interest in this lease
that covers approximately 5,760 acres. The lease contains two wells which are
operated by Spinnaker Exploration Company. During 2003, each of the wells was
5
recompleted at a combined cost of approximately $107,000, net to our interest.
During the year ended December 31, 2003, we recorded revenues from oil and gas
sales of approximately $1,447,000 and associated operating expenses of
approximately $144,000 from this field.
High Island Block 34. In January 2004, it was determined that effective
in August 2003, "payout" had occurred on the High Island Block 34 field, in
which we own a 1.8% reversionary interest. High Island Block 34 is located 13.5
miles offshore Texas in an average water depth of 36 feet. This lease covers
approximately 5,760 acres. The lease has one well that is operated by Hunt
Petroleum. During the year ended December 31, 2003, we recorded revenues from
oil and gas sales of approximately $61,000 and associated operating expenses of
approximately $2,000.
Offshore Oil and Gas Prospect Generation Activities. We suspended our
prospect generation program in 2001 as a result of the withdrawal of our partner
from the program. We developed oil and gas exploration prospects in the Gulf of
Mexico for sale to third parties. In addition to recovering prospect development
costs, we sought to retain a reversionary working interest in each drillable
prospect we sold. Although the program is suspended, we own 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 October 2003, we were awarded a lease on Galveston Area Block 287 in
the Gulf of Mexico. We were the joint high bidder on this lease at the August
20, 2003 OCS Western Gulf of Mexico lease sale. We own a 50% working interest in
the block with the remaining 50% held by Fidelity Exploration and Production
Company ("Fidelity Exploration"). The net cost of this lease to us was
approximately $80,000. We intend to sell our interest and retain a reversionary
working interest. The Blue Dolphin Pipeline traverses this lease block.
Unproved Leasehold Interests. Our leased prospect inventory, which we
continue 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 Galveston Area Block 287
We have after payout reversionary working interests in several offshore
leases. These leases are:
o Galveston Area Block 297
o Galveston Area Block 271
o Galveston Area Block 284
Other. In connection with our acquisition of a controlling interest in
American Resources in December 1999, Fidelity Exploration acquired an 80%
interest in American Resources' oil and gas assets located in the Gulf of Mexico
and agreed to assign us 10% of their working interest in the proved properties
of American Resources after they recovered their investment in these properties.
In addition, Fidelity Oil agreed to assign us 15% of their working interest in
each exploratory property after they recovered their investment in these
exploratory properties on a property-by-property basis.
In the fourth quarter 2001, Fidelity Exploration recovered their
investment in the proved properties. However, instead of assigning 10% of their
interest in the proved properties, Fidelity paid us $1.4 million in December
2001, for the property interest owed to us.
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In January 2004, Fidelity Exploration determined that the exploratory
property located in High Island Block 34 paid out in August 2003 (see High
Island Block 34 above).
Proved Oil and Gas Reserves. We have prepared estimates of proved
reserves, future net revenues, and discounted present value of future net
revenues to our net interest as of December 31, 2003.
The quantities of proved oil and gas reserves presented below include
only those amounts which we reasonably expect 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 our 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 our Proved Reserves, changes
in Proved Reserves, estimated future net revenues and costs incurred in our oil
and gas activities and the discounted present value of estimated future net
revenues from our 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 our net interest in oil and gas
properties as of December 31, 2003. The discounted present value of future net
revenues and future net revenues are calculated using the SEC Method (defined
below) and are not intended to represent the current market value of the oil and
gas reserves we own.
PROVED RESERVES
As of December 31, 2003 (1)(2)
Discounted
Net Oil Net Gas Future Present Value of Future
Reserves Reserves Net Revenues Net Revenues (1)
(Mbbls) (Mmcf) (in thousands) (in thousands)
-------------- -------------- -------------- --------------
High Island Block A-7 0.2 30.0 $ (98) $ (77)
High Island Block 34 0.1 11.7 $ 40 $ 39
-------------- -------------- -------------- --------------
Total Proved Reserves 0.3 41.7 $ (58) $ (38)
============== ============== ============== ==============
High Island Block A-7 0.2 30.0 $ (98) $ (77)
High Island Block 34 0.1 11.7 $ 40 $ 39
-------------- -------------- -------------- --------------
Total Proved Developed
Reserves 0.3 41.7 $ (58) $ (38)
============== ============== ============== ==============
(1) The estimated discounted present value of future net revenues
before deductions for income taxes from our Proved Reserves
have been determined by using prices of $31.25 per barrel of
oil and $5.23 per Mcf of gas, representing the December 31,
7
2003 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").
At December 31, 2003, the value of our reserves is negative as
a result of asset retirement obligations exceeding future
revenues.
(2) As of December 31, 2003, we reported no proved undeveloped
reserves.
Capital Expenditures for Proved Reserves. The following table presents
information regarding the costs we expect to incur in development activities
associated with our proved reserves. These expenditures include recompletion
costs, workover costs and the cost of drilling additional wells required to
recover proved reserves and the plugging and abandonment of wells. 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)
------------------------------------------
2004 2005 2006 2007 2008
------ ------ ------ ------ ------
High Island Block A-7 $ 27 186 -- -- --
High Island Block 34 -- 13 -- -- --
We will continue to evaluate our capital expenditure program based on,
among other things, demand and prices obtainable for our production. The
availability of capital resources and the willingness of other working interest
owners to participate in development operations may affect our 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 our interest for each of the
periods indicated.
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NET PRODUCTION, PRICE AND COST DATA
Year Ended December 31,
---------------------------------------
2003 2002 2001
----------- ----------- -----------
Gas:
Production (Mcf) 274,268 418,895 815,184
Revenue $ 1,513,182 $ 1,221,168 $ 3,607,910
Average Production (Mcf) per day 1,138.3 1,147.7 2,233.4
Average Sales Price
Per Mcf $ 5.52 $ 2.92 $ 4.43
Oil:
Production (Bbls) $ 2,271 28,230 40,769
Revenue $ 68,872 $ 560,790 $ 1,086,292
Average Production (Bbls) per day $ 9.4 77.3 111.7
Average Sales Price
Per Bbl $ 30.33 $ 19.87 $ 26.65
Production Costs (*):
Per Mcfe: $ 0.51 $ 0.88 $ 1.06
(*) 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 2003 and 2002 there was no drilling
activity.
We maintain a professional staff and consultants capable of supervising
and coordinating the operation and administration of our 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.
Customers
We generated revenues from both of our primary business segments.
Revenues from major customers exceeding 10% of revenues were as follows for 2003
and 2002.
Oil and gas Pipeline
sales operations Total
----------- ----------- -----------
Year ended December 31, 2003:
Spinnaker Exploration Company $ 1,446,622 -- 1,446,622
Houston Exploration and Production Company
Year ended December 31, 2002:
Houston Exploration and Production Company $ -- 290,223 290,293
Apache Corporation -- 282,215 282,215
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
9
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 our assets.
Several highly competitive alternative transportation and delivery options exist
for current and potential customers of our 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 oil and gas, and the prices of
such oil and gas, depends upon a number of factors, which are beyond our
control. 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 we provide.
Governmental Regulation
The production, processing, marketing, and transportation of oil and
gas, and the development of storage of gas by us are subject to federal, state
and local regulations which can have a significant impact upon our 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 the
Federal Energy Regulatory Commission ("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.
Although problems associated with inaccurate reporting to natural gas
pricing indices have prompted FERC to conduct investigations and urge improved
price discovery, gas sales remain deregulated. We 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 our operations or
competitive position. However, we do not believe that any action taken will
affect us in any way that materially differs from the way that such action
affects our competitors.
All of our 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 ("OCS") will transport for non-owner
shippers in a nondiscriminatory manner and will be operated in accordance with
certain pro-competitive principles. Recent court rulings have clarified
10
significant limitations on FERC's jurisdiction under the OCSLA, so that FERC has
withdrawn reporting and recordkeeping requirements FERC had sought to impose on
gas pipelines on the Outer Continental Shelf.
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 our offshore pipelines fall within the exemption for feeder facilities and
already operate on the basis required under OCSLA, we do 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, we cannot predict how application of
the OCSLA to our pipelines may ultimately affect our 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. Our operation of the Buccaneer
Pipeline has been subject to a variety of regulations promulgated by the FERC
and imposed on all oil pipelines pursuant to federal law. Recently, however, oil
pipelines have been granted permanent exemptions from certain FERC filing
requirements because of rulings that oil pipeline transportation tariff
movements of crude petroleum occurring solely on or across the OCS, or across
the OCS to onshore points where transportation ends are not subject to FERC
jurisdiction under the OCSLA or the Interstate Commerce Act.
Safety and Operational Regulations. Our operations 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 OCS
vessels, rigs, platforms 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, we believe that we are in
material compliance with the various safety and operational regulations that we
are subject to. However, as safety and operational regulations are frequently
changed, we are unable to predict the future effect changes in these regulations
will have on our operations, if any.
Federal Oil and Gas Leases. All of our exploration and production
operations are located on federal oil and gas leases in the OCS, which are
administered by the 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 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.
11
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. We are currently in
compliance with the bonding requirements of the MMS. Under some circumstances,
the MMS may require any of our operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially adversely affect
our financial condition and results of operations.
Our 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 our 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 of our 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. Our 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 natural gas 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 we believe 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 our operations, could result in substantial costs and liabilities. It is
not anticipated that, in response to such regulation, we will be required in the
near future to expend amounts that are material relative to our total capital
structure.
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 present owner or operator of a site where the release
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occurred, the owner or operator of the site at the time of disposal of the
hazardous substance, 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 our operations. At this time, neither we nor any
of our predecessors have 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 our oil and gas operations
are currently exempt from regulation as "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.
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We currently own or lease, or have 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 our 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 our control. These
properties and any waste disposed thereon may be subject to CERCLA, RCRA, and
state laws which could require us 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. 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. We believe we have established adequate financial
responsibility. While the financial responsibility requirements under OPA may be
amended to impose additional costs on us, the impact of such a change is not
expected to be any more burdensome on us than on others similarly situated.
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. We 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 we do 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 our operations, we are 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. We
believe we are 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 us.
Various federal and state programs regulate the conservation and
development of coastal resources. The federal Coastal Zone Management Act was
passed to preserve and, where possible, restore the natural resources of the
Nation's coastal zone and to provide for federal grants for state management
programs that regulate land use, water use and coastal development. Under the
Louisiana Coastal Zone Management Program, coastal use permits are required for
14
certain activities, even if the activity only partially infringes on the coastal
zone. Among other things, projects involving use of state lands and water
bottoms, dredge or fill activities that intersect with more than one body of
water, mineral activities, including the exploration and production of oil and
gas, and pipelines for the gathering, transportation or transmission of oil, gas
and other minerals require such permits. General permits, which entail a reduced
administrative burden, are available for a number of routine oil and gas
activities. The Texas Coastal Coordination Act ("CCA") establishes the Texas
Coastal Management Program that applies in the nineteen Texas counties that
border the Gulf of Mexico and its tidal bays. The CCA provides for the review of
state and federal agency rules and agency actions for consistency with the goals
and policies of the Coastal Management Plan. These coastal programs may affect
agency permitting of our facilities.
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. 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. We currently maintain 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 our operations.
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 our 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, we will
be required in the near future to expend amounts that are material relative to
our 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, we are unable to predict the ultimate
cost of compliance.
RISK FACTORS
We need capital to meet our obligations during 2004. Our capital
requirements raise substantial doubt about our ability to continue as a going
concern.
In order to satisfy our working capital and capital expenditure
requirements for the year ending December 31, 2004, we believe that we will need
to raise approximately $1.5 million of capital. We will need to arrange external
financing and/or sell assets to raise the necessary capital.
Historically, we have 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 our operations. There can be no
assurance that we will be able to obtain financing or sell assets on
commercially acceptable terms to meet our capital requirements. Our inability to
raise capital may have a material adverse effect on our financial condition,
ability to meet our obligations and operating needs, and results of operations.
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We are primarily dependent on revenues from our pipeline systems.
As a result of our sale of substantially all of our proved oil and gas
reserves in 2002 and the limited remaining reserves that were added in 2003, our
future revenues are primarily dependent on the level of use of our pipeline
systems. Various factors will influence the level of use of our pipeline systems
including the amount of oil and gas production near our pipelines and our
ability to attract new users. There are various competing pipelines in and
around our pipeline systems that we vigorously compete with to attract new users
to our pipeline systems. There can be no assurance that our marketing activities
will result in attracting new oil and gas reserves to our pipeline systems.
Our future success depends, in part, upon our ability to find, develop
and acquire new oil and gas reserves and mid-stream (pipeline) assets.
We are currently attempting to find and acquire properties containing
proved reserves as well as mid-stream assets. Until we acquire additional proved
reserves and/or mid-stream assets, substantially all of our revenues will be
from our pipeline systems and reversionary interests in oil and gas properties.
There can be no assurance that we will be able to acquire proved reserves or
other assets.
We face strong competition from larger companies that may negatively
affect our ability to carry on operations.
We operate in a highly competitive industry. Our 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 other resources than
we do. Our ability to successfully compete in the marketplace is affected by
many factors.
o Most of our competitors have greater financial resources than
we do, which gives them better access to capital to acquire
and develop oil and gas properties and acquire pipelines.
o Most of our competitors have longer operating histories and
have more data generally available to them, including
information relating to oil and gas properties and pipelines.
o We often establish a higher standard for the minimum projected
rate of return on an investment than some of our competitors
since we cannot afford to absorb certain risks. We believe
this puts us at a competitive disadvantage in acquiring oil
and gas properties and pipelines.
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 us.
Our revenues, profitability, operating cash flow and our 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 our control. These factors include:
o weather conditions in the United States;
o the condition of the United States economy;
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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 us, including the following:
o reducing the exploration and development of oil and gas
reserves held by third party companies around our pipeline
systems;
o increasing our dependence on external sources of capital to
meet our cash needs; and
o impairing our ability to obtain needed equity.
Volatile oil and gas prices also make it difficult to estimate the
value of producing properties we may acquire and also make it difficult for us
to budget for and project the return on acquisitions and development and
exploitation projects.
We cannot control the activities on properties we do not operate.
Currently, other companies operate all of the oil and gas properties in
which we have an interest. As a result, we 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 us, including the amount and timing of revenues, if any, we
receive from our interest.
We have and generally anticipate that we will typically own
substantially less than a 50% working interest in our prospects and will
therefore engage in joint operations with other working interest owners. In
instances in which we own or control 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 we are
unwilling or unable to participate in the costs of operations approved by a
majority of the working interests in a well, our 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 our interest in the well or a relinquishment of our
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 us if we had elected to
participate, which often ranges from 400% to 600% of such costs.
We have pursued, and intend to continue to pursue, acquisitions. Our
business may be adversely affected if we cannot effectively integrate acquired
operations.
17
One of our business strategies has been to acquire operations and
assets that are complementary to our existing businesses. Acquiring operations
and assets involves financial, operational and legal risks. These risks include:
o inadvertently becoming subject to liabilities of the acquired
company that were unknown to us 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 us to pay a higher
price than we otherwise might have to pay and reduce our acquisition
opportunities. We are often out-bid by larger, better capitalized companies for
acquisition opportunities we pursue. Moreover, our past success in making
acquisitions and in integrating acquired businesses does not necessarily mean we
will be successful in making acquisitions and integrating businesses in the
future.
Operating hazards, including those peculiar to the marine environment,
may adversely affect our ability to conduct business.
Our 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 us from injury and loss of
life, damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations. Our 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 our financial
condition and operations.
18
We maintain several types of insurance to cover our 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. We also maintain
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.
We may not be able to maintain adequate insurance in the future at
rates we consider reasonable or losses may exceed the maximum limits under our
insurance policies. If a significant event that is not fully insured or
indemnified occurs, it could materially and adversely affect our financial
condition and results of operations.
Compliance with environmental and other government regulations could be
costly and could negatively impact production and pipeline operations.
Our 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 operations can be
commenced;
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
our 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 our
operating costs, as well as on the oil and gas industry in general.
Our 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. We 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 our financial condition
and results of operations. We maintain insurance coverage for our operations,
including limited coverage for sudden and accidental environmental damages, but
we do 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, we may be subject to liability
or may lose the privilege to continue exploration or production activities upon
substantial portions of our 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
19
modification of existing, environmental laws or regulations, including
regulations promulgated pursuant to the OPA, could have a material adverse
impact on us.
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 lease where the owner is not the operator of the lease.
20
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.
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. Description of Property
Information appearing in Item 1 describing our oil and gas properties,
pipelines and other assets under the caption "Description of Business" is
incorporated herein by reference.
We lease our executive offices in Houston, Texas, under an operating
lease expiring December 31, 2006. Our aggregate annual lease payment obligation
under this lease is approximately $195,000.
In March 2003, we entered into a sublease agreement expiring December
31, 2006 for certain of our office space with Tri-Union Development Corporation.
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Our annual receipts from this sublease will be approximately $78,500. One of our
Directors, Mr. James M. Trimble, is the Chairman and Chief Executive Officer of
Tri-Union.
Item 3. Legal Proceedings
Neither us nor any of our property is subject to any material pending
legal proceedings.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
PART II
Item 5. Market for Common Stock and Related Stockholder Matters
Market Price for Common Stock
Our common stock is quoted on the NASDAQ Small Cap Market under the
symbol "BDCO". As of March 22, 2004, there were an estimated 600 stockholders of
record and we estimate there are more than 1,000 beneficial owners of our common
stock. NASDAQ quotations reflect inter-dealer prices, without adjustment for
retail mark-ups, markdowns or commissions and may not represent actual
transactions. The following table sets forth, for the periods indicated, the
high and low bid price for the common stock as reported by the NASDAQ.
High Low
---- ---
Quarter Ended March 31, 2002 .............$ 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
Quarter Ended March 31, 2003 .............$ 0.63 $ 0.41
Quarter Ended June 30, 2003 .............$ 1.85 $ 0.38
Quarter Ended September 30, 2003.............$ 4.00 $ 0.75
Quarter Ended December 31, 2003 .............$ 3.20 $ 1.65
On July 15, 2002, we received a notice from the NASDAQ, that because
our Common Stock traded below the minimum bid requirement of $1.00 for 30
consecutive trading days the Common Stock would be delisted if our bid price did
not close above $1.00 for 10 consecutive trading days by January 15, 2003. This
deadline to regain compliance with NASDAQ's listing requirements was extended to
October 8, 2003. On August 27, 2003, we received a notice from the NASDAQ that
we had regained compliance with the listing requirements as a result of the bid
price of our common stock closing above $1.00 for 10 consecutive trading days.
If our common stock were to trade below the minimum bid requirement of $1.00 for
30 consecutive trading days, the bid price of our common stock would again be
required to close above $1.00 for 10 consecutive trading days to avoid
delisting.
Dividend Policy
We have not declared or paid any dividends on our common stock since
our incorporation. We currently intend to retain earnings for our capital needs
and expansion of our business and do not anticipate paying cash dividends on the
common stock in the foreseeable future. Previously, we were restricted, pursuant
to a loan agreement from paying dividends on the common stock if there was an
22
outstanding balance under the loan agreement. Any loan agreements which we may
enter into in the future will likely contain restrictions on the payment of
dividends on our common stock. Future policy with respect to dividends will be
determined by our Board of Directors based upon our earnings and financial
condition, capital requirements and other considerations. We are a holding
company that conducts substantially all of our operations through our
subsidiaries. As a result, our ability to pay dividends on the common stock is
dependent on the cash flow of our subsidiaries.
Securities Authorized for Issuance Under Equity Compensation Plan
We have 501,919 shares of common stock reserved for issuance under our
stock option plans. See Note 7 to the Consolidated Financial Statements.
Item 6. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following is a review of certain aspects of our financial condition
and results of operations and should be read in conjunction with the
Consolidated Financial Statements included in Item 7. and Item 1. Description of
Business.
EXECUTIVE SUMMARY
-----------------
We are engaged in two lines of business; pipeline operations and oil
and gas exploration and production. We conduct our operations through our
subsidiaries. We provide pipeline transportation services to producer/shippers,
and sell oil and gas from our producing properties. Our assets primarily are
located offshore and onshore in the Texas Gulf coast area. We also own an
interest in and manage the New Avoca gas storage project located in Avoca, New
York.
Our future cash flows are subject to a number of variables, primarily
utilization of our pipeline systems. Although approximately 57% of our revenues
for the year ended December 31, 2003 were from sales of oil and gas production
from the High Island Block A-7 field, oil and gas production from the High
Island Block A-7 field has declined significantly and production is expected to
cease by the third quarter 2004, and we expect a significant portion of our
revenues in 2004 will be derived from utilization of our pipeline systems. As a
result of our expected decline in revenues from oil and gas sales and our
remaining payments associated with the abandonment/reefing of the Buccaneer
Field of approximately $1.7 million during 2004, we will need to raise
approximately $1.5 million of capital. Our inability to raise capital may have a
material adverse effect on our financial condition, ability to meet our
obligations and operating needs, and results of operations. As a result of
potential liquidity problems, our auditors, Mann Frankfort Stein & Lipp CPAs,
L.L.P. added an explanatory paragraph in their opinion on our consolidated
financial statements as of and for the year ended December 31, 2003, indicating
that substantial doubt exists about our ability to continue as a going concern.
See Note 2 in Item 7 of the Consolidated Financial Statements.
In addition to satisfying our liquidity and capital needs, our focus in
2004 is to increase utilization of existing assets, strategic acquisitions and
cost management. Our long-term goal is to create greater value for our
stockholders.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------
Historically, we have 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 our operations. We incurred a net loss
23
of $793,058 and we have an accumulative deficit of $21,332,863 at December 31,
2003. These factors combined with the cash requirements inherent in our
businesses raise substantial doubt about or ability to continue as a going
concern. Our long-term viability as a going concern is dependent upon the
following factors:
o our ability to raise capital to meet current commitments and
fund the continuation of our business operations; and
o our ability to ultimately achieve profitability and cash flows
from operations in amounts that will sustain our operations.
The following table summarizes certain of our contractual obligations
and other commercial commitments at December 31, 2003 (amounts in thousands).
Payments Due by Period
----------------------
Contractual 1 year After
Obligations Total or less 2-3 years 4-5 years 5 years
----------- --------- --------- --------- --------- ---------
Accounts Payable - Tetra $ 1,737 1,737 -- -- --
Long-Term Debt 837 -- 837 -- --
Operating Leases, net of sublease 361 124 237 -- --
--------- --------- --------- --------- ---------
Total Contractual
Obligations $ 2,935 1,861 1,074 -- --
========= ========= ========= ========= =========
Amount of Commitment Expiration Per Period
------------------------------------------
Other Commercial 1 year After
Commitments Total or less 2-3 years 4-5 years 5 years
----------- --------- --------- --------- --------- ---------
Abandonment - Costs $ 1,552 -- 199 -- 1,353
--------- --------- --------- --------- ---------
Total Commercial
Obligations $ 1,552 -- 199 -- 1,353
========= ========= ========= ========= =========
The following table summarizes our financial position for the periods
indicated:
December 31,
(amounts in thousands)
-----------------------------------------
2003 2002
------------------- -------------------
Amount % Amount %
-------- -------- -------- --------
Working Capital $ 680 9 $ 2,243 29
Property and equipment, net 5,775 79 4,687 60
Other noncurrent assets 848 12 845 11
-------- -------- -------- --------
Total $ 7,303 100 $ 7,775 100
======== ======== ======== ========
Long-term Liabilities $ 2,302 32 $ 2,010 26
Stockholders' equity 5,001 68 5,765 74
-------- -------- -------- --------
Total $ 7,303 100 $ 7,775 100
======== ======== ======== ========
24
The change in our financial position from December 31, 2002 to December
31, 2003, was primarily due to the adoption of SFAS No. 143 regarding accounting
for asset retirement obligations, and the payment of approximately $1.6 million
of Buccaneer Field abandonment costs. See Note 1 in Item 7 of the Consolidated
Financial Statements.
The net cash provided by or used in operating, investing and financing
activities is summarized below:
Years Ended December 31,
---------------------------
(amounts in thousands)
2003 2002
----------- -----------
Net cash provided by (used in):
Operating activities $ (1,365) $ (2,836)
Investing activities (338) 3,898
Financing activities -- --
----------- -----------
Net increase (decrease) in cash $ (1,703) $ 1,062
=========== ===========
The net cash used in operating activities during the year ended
December 31, 2003, primarily reflects the payment of Buccaneer Field abandonment
costs. In August 2003, we completed the abandonment/reefing of the Buccaneer
Field. See Recent Developments in Item 1. During 2003, we paid
abandonment/reefing costs of approximately $1.6 million. Remaining costs of $1.7
million are due to our contractor, Tetra, with whom we arranged payment terms.
The remaining payments include nine monthly installments of $133,600 and a final
payment of $534,400 due in October 2004.
During 2002, we sold substantially all of our interests in our proved
oil and gas properties for approximately $5.0 million. The properties sold
generated all of our oil and gas sales revenues in 2002. From October 2002 to
late April 2003, we had no interest in any producing oil and gas properties. In
late April 2003, we began to receive revenue from our 8.9% reversionary working
interest in the High Island Area Block A-7 field, in the Gulf of Mexico. See
"Sale of Oil and Gas Properties" and "High Island Block A-7" in Item 1. Oil and
gas production from this field now comes from one well that currently produces
at a gross rate of 2.4 MMcf/day. During the year ended December 31, 2003, we
recorded revenues from oil and gas sales of approximately $1,447,000 and
associated operating expenses of approximately $144,000, from this field.
During 2003, we incurred capital expenditures of approximately $107,000
for development of our proved reserves. The reserves and future net revenues
presented in Item 1 "Description of Business" reflect projected capital
expenditures totaling $27,000 and $199,000 in the years ending December 31, 2004
and 2005, respectively. Capital expenditures in 2005 represent the abandonment
costs of our High Island Block A-7 and 34 properties. Additionally in 2003, we
incurred capital expenditures of approximately $80,000 for a 50% interest in the
Galveston Block 287 lease. We intend to sell our interest and retain a
reversionary interest in this lease block. See "Offshore Oil and Gas Prospect
Generation Activities" in Item 1.
25
We have significant available capacity in our Blue Dolphin Pipeline
system in a market area that we believe is experiencing an increased level of
interest by oil and gas operators. Natural gas transportation throughput on our
Blue Dolphin Pipeline system is currently 8 MMBtu per day representing 6% of
system capacity. Future utilization of our pipeline and related facilities will
depend upon the success of drilling programs around our pipeline systems, and
attraction and retention of producer/shippers to the systems. As a result of
increased leasing activities around the Blue Dolphin Pipeline system and
anticipated drilling activity, we expect that utilization of the Blue Dolphin
Pipeline system will increase in late 2004 or 2005.
We currently are continuing our efforts to sell our interest in the New
Avoca gas storage project. To enhance this effort, we began marketing
prospective capacity to potential users of the project. During 2003, we incurred
costs associated with the development of New Avoca of approximately $94,000 net
to our interest. We currently expect that costs net to our interest during the
year ending December 31, 2004 will be approximately $80,000.
In February 2002, we acquired an additional 1/3 interest in the Blue
Dolphin Pipeline System and the inactive Omega Pipeline from MCNIC Pipeline and
Processing Group, Inc. ("MCNIC"). Pursuant to the terms of the purchase and
sales agreement, Blue Dolphin Pipeline Company 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. See Note 5 to the
Consolidated Financial Statements. As of December 31, 2003, the amount owed
MCNIC is $750,000 plus accrued interest of $87,245.
RESULTS OF OPERATIONS
For the year ended December 31, 2003 ("2003"), we reported a net loss
of $793,058, compared to net income of $482,054 for the year ended December 31,
2002 ("2002").
2003 compared to 2002
---------------------
Revenue from oil and gas sales. Our revenues from oil and gas sales
decreased by $199,904 in 2003, from those of 2002. The decrease was primarily
due to the sale of oil and gas properties in the second half of 2002. The
properties sold represented all of our 2002 oil and gas sales. 2003 revenues
include approximately $1.4 million in sales from our interest in the High Island
Block A-7 field, which interest was received in April 2003, $.1 million in sales
from our interest in the High Island Block 34 field, which interest was received
effective in August 2003, and approximately $.1 million for adjustments for
periods prior to the sale of oil and gas properties in 2002.
Revenue from pipeline operations. Revenues from pipeline operations
decreased by $193,559 or 17% in 2003 to $934,760. The decrease was due primarily
to a decrease in transportation volumes on the Blue Dolphin Pipeline system of
33% resulting in a decrease in revenues of approximately $267,000, offset in
part by a 44% increase in revenues of approximately $73,000 from the GA 350
Pipeline.
Lease operating expenses. Lease operating expenses for 2003 decreased
by $332,264, or 64% from 2002. The decrease resulted primarily from the sale of
our proved oil and gas reserves during 2002, offset in part by expenses incurred
primarily from our interest in the High Island A-7 field in 2003.
26
Pipeline operating expenses. Pipeline operating expenses in 2003
increased by $360,122 from $838,607 in 2002. The increase was due to increased
insurance premiums of approximately $.1 million, legal costs of approximately
$.1 million, and repairs and maintenance of approximately $.1 million. These
legal costs are associated with an action filed against us, the outcome of which
we do not believe will have a material impact on us. However, if this litigation
continues for a prolonged period of time we would incur significant legal
expenses, which could have a material effect on our financial condition.
Depletion, depreciation and amortization expense. Depletion,
depreciation and amortization expenses decreased by $330,590 from 2002. In 2002
we recorded depletion of approximately $.6 million associated with the oil and
gas properties sold in the second half of 2002 compared to depletion of
approximately $.1 million recorded in 2003. Pipeline depreciation expense
increased by approximately $.1 million in 2003, due to depreciation expense
associated with the offshore platform used to maintain the Blue Dolphin Pipeline
system and the associated asset retirement obligation.
Impairment of assets and bad debt expense. In 2003, we recorded a
partial impairment of our oil and gas properties of approximately $89,000, do to
the decline in proved reserves from our interest in the High Island Block A-7
field. In 2002, we elected to record a full impairment of our investment in
Drillmar of $.3 million and a full reserve for the accounts receivable amount
owed from Drillmar of $.2 million due to Drillmar's working capital deficiency
and delays in securing capital funding.
General and administrative expenses. General and administrative
expenses for 2003 decreased $822,023 from 2002. The decrease in 2003 is
primarily due to a cost reduction program initiated in 2002 that resulted in a
reduction in personnel and related costs of approximately $.5 million,
elimination of legal costs associated with litigation that was settled in the
previous period of approximately $.2 million and a reduction in rental expense
as a result of subleasing certain of our office space of approximately $.1
million.
Interest and other expense. Interest and other expense decreased by
$84,554 in 2003. In 2003, we incurred costs of approximately $.1 million
associated with capital funding activities. In 2002, we recorded an expense
associated with the settlement of litigation 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, associated with our acquisition of
American Resources in 1999.
Gain on sale of assets. In 2002, we recorded gains on the sale of our
proved oil and gas reserves of $2.2 million.
Interest and other income. Interest and other income decreased $15,773
in 2003. In 2003 and 2002, we recorded a $0.5 and $0.7 million reduction in our
provision for the Buccaneer Field abandonment costs, respectively.
Equity in income (losses) of affiliate. In 2003 and 2002, we recorded
income (loss) from our equity interest in New Avoca of ($90,764) and $60,158,
respectively.
Cumulative effect of a change in accounting principal. In 2003, as a
result of our adoption of SFAS No. 143, we recorded accretion expense of
$80,428, reflecting an increase in future asset retirement obligations, and we
recorded a cumulative effect adjustment at January 1, 2003 of a change in
accounting principle for asset retirement obligations of $40,455. See Note 1 in
Item 7 of the Consolidated Financial Statements.
27
Critical Accounting Policies
The selection and application of accounting policies is an important process
that has developed as our 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
our business. We make every effort to properly comply with all applicable rules
at or before their adoption, and believe 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, we must use our best judgment to adopt a policy for accounting for these
situations. We accomplish this by comparatively analyzing similar situations and
reviewing the accounting guidance governing them, and may consult with our
independent accountants about the appropriate interpretation and application of
these policies.
Our most critical accounting policy currently relates to the accounting for the
impairment of long-lived assets, which include primarily our pipeline assets, as
of December 31, 2003.
In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets", we initiate our 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, our pipeline assets are significantly under utilized and therefore is
an indicator of possible impairment at December 31, 2003. Accordingly, we
developed future cash flows as of December 31, 2003 expected to be generated
from our 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 prospective drilling activity
surrounding our pipelines. 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,
2003.
The accounting for future abandonment costs changed on January 1, 2003 with the
adoption of SFAS No. 143. This new standard requires that a liability for the
discounted fair value of an asset retirement obligation be recorded in the
period in which it is incurred and the corresponding cost capitalized by
increasing the carrying amount of the related long-lived asset. The liability is
accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is
recognized. Future asset retirement costs include costs to dismantle and
relocate or dispose of our offshore platforms, pipeline systems and related
onshore facilities and restoration costs of land and seabed. We develop
estimates of these costs for each of our assets based upon the type of platform
structure, depth of water, reservoir characteristics, depth of the reservoir,
market demand for equipment, currently available procedures and consultations
with construction and engineering consultants. Because these costs typically
extend many years into the future, estimating these future costs is difficult
and requires management to make judgments that are subject to future revisions
based upon numerous factors, including changing technology and the political and
regulatory environment. We review our assumptions and estimates of future
abandonment costs on an annual basis.
28
Recently Issued Accounting Pronouncements and Accounting Developments
In May 2003, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both Liabilities and
Equity," which establishes how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity.
Instruments that have an unconditional obligation requiring the issuer to redeem
the instrument by transferring an asset at a specified date are required to be
classified as liabilities on the balance sheet. Instruments that require the
issuance of a variable number of equity shares by the issuer generally do not
have the risks associated with equity instruments and as such should also be
classified as liabilities on the balance sheet. This statement was effective for
financial instruments entered into or modified after May 31, 2003, and otherwise
was effective at the beginning of the first interim period beginning after June
15, 2003. The adoption of SFAS 150 did not have a material impact on our
consolidated financial position or results of operations or cash flows.
In January 2003, the FASB issued Interpretation ("FIN") No. 46,
"Consolidation of Variable Interest Entities--An Interpretation of ARB No. 51."
In December 2003, the FASB issued the updated and final interpretation, FIN No.
46R. FIN No. 46R requires that an equity investor in a variable interest entity
have significant equity at risk (generally a minimum of 10%, which is an
increase from the 3% required under previous guidance) and hold a controlling
interest, evidenced by voting rights, and absorb a majority of the entity's
expected losses, receive a majority of the entity's expected returns, or both.
If the equity investor is unable to evidence these characteristics, the entity
that retains these ownership characteristics will be required to consolidate the
variable interest entity as the primary beneficiary. The disclosure requirements
of FIN No. 46 were effective for financial statements initially issued after
January 31, 2003, regardless of the date on which the variable interest entity
was created. The recognition and measurement requirements of FIN No. 46 for
variable interest entities created after January 31, 2003, were effective
immediately. For variable interest entities created before February 1, 2003, the
provisions of FIN No. 46 (other than the disclosure provisions) were effective
no later than the beginning of the first interim or annual reporting period
beginning after June 15, 2003. FIN No. 46R is effective as of December 31, 2004;
this effective date includes those entities to which FIN No. 46 had previously
been applied. However, prior to the required application of FIN No. 46R, for
variable interest entities that are considered to be special-purpose entities
this interpretation is effective as of December 31, 2003. If FIN No. 46 had been
applied to an entity prior to the effective date of FIN No. 46R, then the entity
shall either continue to apply FIN No. 46 until the effective date of FIN No.
46R or apply FIN No. 46R at an earlier date. The adoption of FIN No. 46 and FIN
No. 46R did and are not expected to have a material impact on our consolidated
financial position or results of operations or cash flows.
In July 2003, an issue was brought before the FASB regarding whether or
not contract-based oil and gas mineral rights held by lease or contract
("mineral rights") should be recorded or disclosed as intangible assets. The
issue presents a view that these mineral rights are intangible assets as defined
in SFAS No. 141, "Business Combinations," and, therefore, should be classified
separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No.
142, "Goodwill and Other Intangible Assets," became effective for transactions
subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142
required as of January 1, 2002. SFAS No. 141 requires that all business
combinations initiated after June 30, 2001 be accounted for using the purchase
method and that intangible assets be disaggregated and reported separately from
goodwill. SFAS No. 142 established new accounting guidelines for both finite
29
lived intangible assets and indefinite lived intangible assets. Under the
statements, intangible assets should be separately reported on the face of the
balance sheet and accompanied by disclosure in the notes to financial
statements. SFAS No. 142 does not apply to accounting utilized by the oil and
gas industry as prescribed by SFAS No. 19, and is silent about whether or not
its disclosure provisions apply to oil and gas companies. The Emerging Issues
Task Force has added the treatment of oil and gas mineral rights to an upcoming
agenda, which may result in a change in how we classify these assets. Should
such a change be required, the amounts related to business combinations and
major asset purchases that would be classified as "intangible undeveloped
mineral interest" are immaterial as of December 31, 2003. The amounts related to
business combinations and major asset purchases that would be classified as
"intangible developed mineral interest" are also immaterial as of December 31,
2003 .
Item 7. Financial Statements and Supplementary Data
Index to Financial Statements: Page
----
Independent Auditors' Report........................................ 31
Consolidated Balance Sheet, at December 31, 2003.................... 32
Consolidated Statements of Operations, for the years
ended December 31, 2003 and 2002............................. 34
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 2003 and 2002....................... 35
Consolidated Statements of Cash Flows, for the years
ended December 31, 2003 and 2002............................. 36
Notes to Consolidated Financial Statements..................... 38
30
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, 2003, 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, 2003. 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, 2003, and the
consolidated results of their operations and their cash flows for each of the
years in the two-year period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 2 to the
consolidated financial statements, the Company has incurred net losses and
negative cash flows from operations in recent years and has projected a cash
deficit for 2004. Those conditions raise substantial doubt about the Company's
ability to continue as a going concern. Management's plans in regard to those
matters are described in Note 2. The consolidated financial statements do not
include any adjustments that might result from the outcome of this uncertainty.
As discussed in Note 1, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations," as of January 1, 2003.
/s/ Mann Frankfort Stein & Lipp CPAs, LLP
Houston, Texas
March 5, 2004
31
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet
December 31, 2003
Assets
------
Current assets:
Cash and cash equivalents $2,702,892
Trade accounts receivable 471,819
Related party receivable 17,266
Prepaid expenses and other assets 157,654
----------
Total current assets 3,349,631
Property and equipment, at cost:
Oil and gas properties, including $160,697
of unproved leasehold cost (full-cost method) 525,688
Pipelines 4,546,287
Onshore separation and handling facilities 1,664,128
Land 860,275
Other property and equipment 305,041
----------
7,901,419
Less accumulated depletion, depreciation,
amortization, and impairment 2,126,963
----------
5,774,456
Deferred federal income tax 244,444
Investment in New Avoca 588,699
Other assets 14,664
----------
$9,971,894
==========
See accompanying notes to consolidated financial statements.
32
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet, continued
December 31, 2003
Liabilities and Stockholders' Equity
------------------------------------
Current liabilities:
Trade accounts payable $ 2,557,972
Accrued expenses and other liabilities 111,390
------------
Total current liabilities 2,669,362
Long-term liabilities:
Note payable 750,000
Asset retirement obligations 1,551,509
------------
Total long-term liabilities 2,301,509
Stockholders' equity:
Common stock, $.01 par value, 10,000,000 shares
authorized and 6,657,845 shares issued
and outstanding 66,578
Additional paid-in capital 26,267,308
Accumulated deficit (21,332,863)
------------
Total stockholders' equity 5,001,023
------------
$ 9,971,894
============
See accompanying notes to consolidated financial statements.
33
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
Years ended December 31, 2003 and 2002
2003 2002
----------- -----------
Revenue from operations:
Oil and gas sales $ 1,582,054 $ 1,781,958
Pipeline operations 934,760 1,128,319
----------- -----------
Revenue from operations 2,516,814 2,910,277
Cost of operations:
Lease operating expenses 186,656 518,920
Pipeline operating expenses 1,198,729 838,607
Depletion, depreciation and amortization 488,052 818,642
Impairment of assets 88,819 339,984
General and administrative expenses 1,685,693 2,507,716
Accretion expense 80,428 --
----------- -----------
Cost of operations 3,728,377 5,023,869
----------- -----------
Loss from operations (1,211,563) (2,113,592)
Other income (expense):
Interest and other expense (135,047) (219,601)
Gain on sale of assets -- 2,220,549
Interest and other income 684,771 700,544
Bad debt expense -- (221,750)
Equity in income (losses) of affiliate (90,764) 60,158
----------- -----------
Income (loss) before minority interest and income taxes (752,603) 426,308
Minority interest -- 55,746
Income tax expense -- --
----------- -----------
Income before cumulative effect of a change
in accounting principle (752,603) 482,054
Cumulative effect of a change in accounting principle
for asset retirement obligations (40,455) --
----------- -----------
Net income (loss) $ (793,058) $ 482,054
=========== ===========
Income (loss) per common share - basic
Income before accounting change $ (0.11) $ 0.08
=========== ===========
Cumulative effect of a change in accounting principle $ (0.01) $ --
=========== ===========
Net income (loss) $ (0.12) $ 0.08
=========== ===========
Income (loss) per common share - diluted
Income before accounting change $ (0.11) $ 0.08
=========== ===========
Cumulative effect of a change in accounting principle $ (0.01) $ --
=========== ===========
Net income (loss) $ (0.12) $ 0.08
=========== ===========
Weighted average number of common shares
- basic 6,640,285 6,343,834
=========== ===========
- diluted 6,640,285 6,359,072
=========== ===========
See accompanying notes to consolidated financial statements.
34
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended December 31, 2003 and 2002
Additional Total
Common paid-in Accumulated stockholders'
stock capital deficit equity
----------- ----------- ----------- -----------
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 2,378 156,865 -- 159,243
Net income -- -- 482,054 482,054
----------- ----------- ----------- -----------
Balance at December 31, 2002 $ 66,066 26,239,098 (20,539,805) 5,765,359
Common stock issued for services 512 28,210 -- 28,722
Net Loss -- -- (793,058) (793,058)
----------- ----------- ----------- -----------
Balance at December 31, 2003 66,578 26,267,308 (21,332,863) 5,001,023
=========== =========== =========== ===========
See accompanying notes to consolidated financial statements.
35
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended December 31, 2003 and 2002
2003 2002
----------- -----------
Operating activities:
Net income (loss) $ (793,058) $ 482,054
Adjustments to reconcile net income (loss) to net cash
used in operating activities:
Depletion, depreciation and amortization 488,052 818,642
Minority interest -- (55,746)
Gain on sale of assets -- (2,220,549)
Impairment of assets 88,819 339,984
Change in Abandonment costs (500,589) (410,816)
Accretion of asset retirement obligations 80,428 --
Change in accounting principle 40,455 --
Equity in (income) loss of affiliate 90,764 (60,158)
Bad debt expense -- 221,750
Common stock issued for services 28,722 159,243
Changes in operating assets and liabilities:
Trade accounts receivable and related party receivable 26,207 521,197
Prepaid expenses and other assets 137,289 (130,367)
Abandonment costs incurred (3,288,413) (194,592)
Trade accounts payable,
accrued expenses and other liabilities 2,236,867 (2,307,021)
----------- -----------
Net cash used in
operating activities (1,364,457) (2,836,379)
Investing activities:
Exploration and development costs (190,237) (512,393)
Purchases of property and equipment (54,256) (180,600)
Net proceeds from sale of assets -- 5,030,000
Development costs - New Avoca (93,834) (82,000)
Purchase of minority interest in subsidiary -- (356,512)
----------- -----------
Net cash provided by (used in)
investing activities (338,327) 3,898,495
----------- -----------
See accompanying notes to consolidated financial statements.
36
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows, Continued
Years ended December 31, 2003 and 2002
2003 2002
----------- -----------
Financing activities -- --
----------- -----------
Increase (decrease) in cash and cash equivalents (1,702,784) 1,062,116
Cash and cash equivalents at beginning of year 4,405,676 3,343,560
----------- -----------
Cash and cash equivalents at end of year $ 2,702,892 $ 4,405,676
=========== ===========
Supplementary cash flow information:
Interest paid $ -- $ 2,755
=========== ===========
Non cash investing and financing activities
Purchase of property and equipment financed with debt $ -- $ 750,000
=========== ===========
See accompanying notes to consolidated financial statements.
37
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2003 and 2002
(1) Organization and Significant Accounting Policies
Organization
Blue Dolphin Energy 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. We were formed pursuant to a
reorganization effective June 9, 1986.
Principles of Consolidation
Our consolidated financial statements include the accounts of our
wholly-owned subsidiaries. All significant intercompany balances and
transactions have been eliminated in consolidation.
Accounting Estimates
We have 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 financial institutions which at times,
exceed insured limits. We monitor the financial condition of the financial
institutions and have 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. We
utilize one cost center for all of our 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. For the year ended December 31,
2003, we recorded a partial impairment of our oil and gas properties of
approximately $.1 million.
38
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Estimated proved oil and gas reserves are based upon reports prepared
internally by us. The net carrying value of oil and gas properties, less
related deferred income taxes, is limited to the lower of unamortized cost
or the cost center ceiling, defined as the sum of the present value (10%
discount rate applied) of estimated future net revenues from proved
reserves, after giving effect to income taxes, and the lower of cost or
estimated fair value of unproved properties. Disposition of oil and gas
properties are recorded as adjustments to capitalized costs, with no gain
or loss recognized unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves.
The following table reflects the depletion expense incurred from oil and
gas properties during the periods indicated:
Year Ended
December 31,
2003 2002
-------- --------
Depletion expense per Mcf
equivalent
produced $ 0.51 $ 1.05
======== ========
At December 31, 2003 oil and gas properties included $160,697 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 federal leases located in the Gulf of Mexico
with expiration dates ranging from November 2004 to November 2008. 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 2003 2002 Prior Years
----------- ----------- ----------- -----------
Property acquisition costs, net* $ 121,561 20,464 (76,421) 177,518
Exploration costs, net* 39,136 -- (5,178) 44,314
----------- ----------- ----------- -----------
$ 160,697 20,464 (81,599) 221,832
=========== =========== =========== ===========
* Costs are net of leasehold costs transferred to the amortization base
when they are evaluated and proved reserves are discovered, impairment is
indicated or when the lease term expires.
We capitalize 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.
39
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
In July 2003, an issue was brought before the FASB regarding whether
or not contract-based oil and gas mineral rights held by lease or contract
("mineral rights") should be recorded or disclosed as intangible assets.
The issue presents a view that these mineral rights are intangible assets
as defined in SFAS No. 141, "Business Combinations," and, therefore, should
be classified separately on the balance sheet as intangible assets. SFAS
No. 141 and SFAS No. 142, "Goodwill and Other Intangible Assets," became
effective for transactions subsequent to June 30, 2001, with the disclosure
requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141
requires that all business combinations initiated after June 30, 2001 be
accounted for using the purchase method and that intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142
established new accounting guidelines for both finite lived intangible
assets and indefinite lived intangible assets. Under the statements,
intangible assets should be separately reported on the face of the balance
sheet and accompanied by disclosure in the notes to financial statements.
SFAS No. 142 does not apply to accounting utilized by the oil and gas
industry as prescribed by SFAS No. 19, and is silent about whether or not
its disclosure provisions apply to oil and gas companies. The Emerging
Issues Task Force (EITF) has added the treatment of oil and gas mineral
rights to an upcoming agenda, which may result in a change in how we
classify these assets. Should such a change be required, the amounts
related to business combinations and major asset purchases that would be
classified as "intangible undeveloped mineral interest" are immaterial as
of December 31, 2003. The amounts related to business combinations and
major asset purchases that would be classified as "intangible developed
mineral interest" are also immaterial as of December 31, 2003 .
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.
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.
Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 143 ("SFAS 143"),
"Accounting for Asset Retirement Obligations", which addresses financial
40
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
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, we will recognize a gain or loss on settlement.
SFAS 143 amended Statement of Financial Accounting Standards No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies"
("SFAS 19") to require 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. Under the provisions of
SFAS 143, asset retirement obligations are capitalized as part of the
carrying value of the long-lived asset. Under the provisions of SFAS 19,
asset retirement obligations were recognized using a cost-accumulation
approach. Prior to the adoption of SFAS 143, we recorded asset retirement
obligations through the unit-of-production method for oil and gas
properties, and the straight-line method for pipelines and related
facilities.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $1.0 million increase in the carrying value of
pipelines, (ii) a $0.4 million decrease in accumulated depreciation,
depletion, and amortization of property, plant and equipment, and (iii) a
$1.4 million increase in non-current abandonment liabilities. The net
impact of items (i) through (iii) was to record an expense of $40 thousand,
net of tax, as a cumulative effect adjustment of a change in accounting
principle in our consolidated statement of operations upon adoption on
January 1, 2003.
The following pro forma data summarizes our net income (loss) and net
income (loss) per share as if we had adopted the provisions of SFAS 143 on
January 1, 2002, including an associated pro forma asset retirement
obligation on that date of $1.0 million:
Year ended
December 31,
2003 2002
---------- ----------
(in thousands, except
per share amounts)
Net income (loss), as reported ............. $ (793) $ 482
Pro forma adjustments to reflect retroactive
adoption of SFAS 143 ....................... -- (40)
---------- ----------
Pro forma net income (loss) ................ $ (793) $ 442
========== ==========
Net income (loss) per share:
Basic - as reported ..................... $ (0.12) $ 0.08
========== ==========
Basic - pro forma ....................... $ (0.12) $ 0.07
========== ==========
Diluted - as reported ................... $ (0.12) $ 0.08
========== ==========
Diluted - pro forma ..................... $ (0.12) $ 0.07
========== ==========
We have asset retirement obligations associated with the future abandonment
of pipelines and related facilities and offshore oil and gas properties.
The following table summarizes our asset retirement obligation transactions
41
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
recorded in accordance with the provisions of SFAS 143 during the year
ended December 31, 2003, and in accordance with the provisions of SFAS 19
during the year ended December 31, 2002.
Year ended
December 31,
2003 2002
(in thousands)
Beginning asset retirement obligations ...... $ 3,800 $ 4,600
Cumulative effect adjustment ................ 401 --
Liabilities incurred during period .......... 1,060 --
Liabilities settled during period ........... (3,288) (195)
Gain from adjustment to estimated obligations (501) (605)
Accretion expense ........................... 80 --
------- -------
Ending asset retirement obligations .......... $ 1,552 $ 3,800
======= =======
Our asset retirement obligations at December 31, 2002 of $3.8 million
represented the cost to complete the abandonment of the Buccaneer Field.
During 2003, we abandoned/reefed the Buccaneer Field at a cost of
approximately $3.3 million. Additionally, we reduced our provision for the
Buccaneer Field abandonment costs resulting in a gain of approximately $.5
million for the year ended December 31, 2003.
Investment in New Avoca and Drillmar
We record our investment in New Avoca (25% owned and managed by us) using
the equity method of accounting. We previously recorded our investment in
Drillmar (12.8% owned by us) using the equity method of accounting until
2002 when we suspended doing so after we recorded a full impairment of our
investment in Drillmar. Under the equity method, investments are recorded
at cost plus our equity in undistributed earnings and losses after
acquisition.
Stock-Based Compensation
We apply SFAS No. 123, Accounting for Stock-Based Compensation, which
allows us 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. We account for
stock-based compensation under the intrinsic value method and provide the
pro forma effects of the fair value method as required.
Had compensation cost for our stock option plans been determined based on
the fair market value at the grant dates for awards made, our net income
(loss) and income (loss) per share would have been adjusted to the pro
forma amounts indicated below:
42
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Year ended December 31,
-----------------------
2003 2002
--------- ---------
Net income (loss) as reported $(793,058) $ 482,054
Less total stock based employer compensation
expense determined under fair value based
method for all awards, net of tax related effects (30,347) (135,940)
--------- ---------
Pro Forma net income (loss) $(823,405) $ 346,114
========= =========
Basic and diluted income (loss) per share
As reported $ (0.12) $ 0.08
Pro Forma $ (0.12) $ 0.05
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 our net revenue interest in production.
Similarly, when deliveries are below our net revenue interest in
production, sales are recorded to reflect the full net revenue interest.
Our imbalance liability at December 31, 2003 and 2002 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
We provide 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
We follow SFAS No. 128 ("Statement 128"), "Earnings per Share", for
computing and presenting earnings per share which requires, among other
things, dual presentation of basic and diluted earnings per share on the
face of the statement of operations.
43
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Employee stock options at December 31, 2003, 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:
Weighted-
Average Number
of Common Shares
Outstanding
and Potential Per
Net Income Dilutive Share
(Loss) Common Shares Amount
---------------- ---------------- ----------------
Year ended December 31, 2003
Basic and diluted earnings per share $ (793,058) 6,640,285 $ (0.12)
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
================ ================ ================
Environmental
We are 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 us 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 May 2003, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 150, "Accounting
for Certain Financial Instruments with Characteristics of Both Liabilities
and Equity," which establishes how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. Instruments that have an unconditional obligation requiring the
issuer to redeem the instrument by transferring an asset at a specified
date are required to be classified as liabilities on the balance sheet.
44
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Instruments that require the issuance of a variable number of equity shares
by the issuer generally do not have the risks associated with equity
instruments and as such should also be classified as liabilities on the
balance sheet. This statement was effective for financial instruments
entered into or modified after May 31, 2003, and otherwise was effective at
the beginning of the first interim period beginning after June 15, 2003.
The adoption of SFAS 150 did not have a material impact on our consolidated
financial position or results of operations or cash flows.
In January 2003, the FASB issued Interpretation ("FIN") No. 46,
"Consolidation of Variable Interest Entities--An Interpretation of ARB No.
51." In December 2003, the FASB issued the updated and final
interpretation, FIN No. 46R. FIN No. 46R requires that an equity investor
in a variable interest entity have significant equity at risk (generally a
minimum of 10%, which is an increase from the 3% required under previous
guidance) and hold a controlling interest, evidenced by voting rights, and
absorb a majority of the entity's expected losses, receive a majority of
the entity's expected returns, or both. If the equity investor is unable to
evidence these characteristics, the entity that retains these ownership
characteristics will be required to consolidate the variable interest
entity as the primary beneficiary. The disclosure requirements of FIN No.
46 were effective for financial statements initially issued after January
31, 2003, regardless of the date on which the variable interest entity was
created. The recognition and measurement requirements of FIN No. 46 for
variable interest entities created after January 31, 2003, were effective
immediately. For variable interest entities created before February 1,
2003, the provisions of FIN No. 46 (other than the disclosure provisions)
were effective no later than the beginning of the first interim or annual
reporting period beginning after June 15, 2003. FIN No. 46R is effective as
of December 31, 2004; this effective date includes those entities to which
FIN No. 46 had previously been applied. However, prior to the required
application of FIN No. 46R, for variable interest entities that are
considered to be special-purpose entities this interpretation is effective
as of December 31, 2003. If FIN No. 46 had been applied to an entity prior
to the effective date of FIN No. 46R, then the entity shall either continue
to apply FIN No. 46 until the effective date of FIN No. 46R or apply FIN
No. 46R at an earlier date. The adoption of FIN No. 46 and FIN No. 46R did
and are not expected to have a material impact on our consolidated
financial position or results of operations or cash flows.
Reclassifications
Certain 2002 balances have been reclassified to conform with the 2003
financial statement presentation. There is no effect on net income due to
the reclassifications.
(2) Liquidity and Going Concern
At December 31, 2003, our working capital was approximately $.7 million. We
began receiving payments from our working interest in the High Island Block
A-7 field which provided revenues net of operating expenses and capital
expenditures of approximately $1.2 million during the year ended December
31, 2003. Revenues from the High Island Block A-7 Field have declined
significantly and are expected to cease by mid-2004. In order to satisfy
our working capital and capital expenditure requirements for the year
ending December 31, 2004, we believe that we will need to raise
approximately $1.5 million of capital. We will need to arrange external
financing and/or sell assets to raise the necessary capital.
45
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Historically, we have 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 our operations. There
can be no assurance that we will be able to obtain financing or sell assets
on commercially acceptable terms to meet our capital requirements. Our
inability to raise capital may have a material adverse effect on our
financial condition, ability to meet our obligations and operating needs,
and results of operations. Our financial statements contained herein have
been prepared assuming that we will continue as a going concern. Our
capital requirements raise substantial doubt about our ability to continue
as a going concern. Our financial statements do not include any adjustments
that might result from the outcome of this uncertainty.
(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 2003 and 2002 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, 2003 are presented below:
Deferred tax assets:
Net operating loss and capital loss carryforwards $ 16,607,126
Alternative minimum tax credit 388,336
Basis differences in property and equipment (231,521)
------------
Total gross deferred tax asset 16,763,941
Net deferred tax asset 16,763,941
Less valuation allowance (16,519,497)
------------
Deferred tax asset $ 244,444
============
In 1999, we 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, we apply 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, our
valuation allowance at December 31, 2003 reduces the deferred tax assets to
$244,444.
46
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Our effective tax rate applicable to continuing operations in 2003 and 2002
is as follows:
2003 2002
---------- ----------
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, we have a net operating loss carryforward ("NOL")
of approximately $45.0 million and $32.0 million for the years ended
December 31, 2003 and 2002, respectively. These NOLs must be utilized prior
to their expiration, which is between 2004 and 2023. Of the $45.0 million
of NOLs as of December 31, 2003, $17.5 million relate to American
Resources.
We have 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, we 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, we 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, 2003, 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, we do 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, 2004.
Long-term debt at December 31, 2003 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
==========
47
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
(6) Stockholders' Equity
On December 2, 1999, we acquired a 75% ownership interest in American
Resources by purchasing approximately 39.5 million shares of American
Resources common stock. On February 19, 2002, we completed our 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 us 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 our 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, we
issued 277,330 shares of Common Stock and paid $255,000 in cash.
We incurred costs totaling $101,128 in 2002 associated with the
registration of shares of its Common Stock that were issued to American
Resources stockholders. In addition, we issued 14,040 and 62,603 shares of
our Common Stock in 2003 and 2002, respectively, as a severance payment to
former employees and recorded compensation expense of $7,722 and $70,740 in
2003 and 2002, respectively. We also issued 37,227 and 25,060 shares in
2003 and 2002, respectively, to the board of directors and recorded an
expense of $21,000 and $21,000 in 2003 and 2002, respectively.
(7) Stock Options
Effective April 14, 2000, we 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 our Common Stock. We
amended the 2000 Plan effective March 19, 2003, after approval by our
stockholders on May 21, 2003, increasing the number of shares of Common
Stock available for incentive stock options ("ISOs") from 500,000 to
750,000 shares. The 2000 Plan is administered by the Compensation Committee
of our 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.
We 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 Common
Stock. The remaining options outstanding issued pursuant to this plan
expired in January 2004.
At December 31, 2003 we had reserved a total of 501,919 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 Common Stock, are as follows:
48
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Exercise
price per share
-----------------------
Shares From To
---------- ---------- ----------
Balance, December 31, 2001 153,173 1.90 6.00
========== ========== ==========
Granted 340,277 0.33 1.55
Expired (77,129) 1.55 6.00
---------- ---------- ----------
Balance, December 31, 2002 416,321 0.33 6.00
========== ========== ==========
Granted 186,000 0.43 0.43
Expired 100,402 0.43 6.00
---------- ---------- ----------
Balance, December 31, 2003 501,919 0.33 6.00
========== ========== ==========
As of December 31, 2003, options for 501,919 shares of Common Stock were
immediately exercisable. There were 186,000 and 340,277 options granted in
2003 and 2002, respectively. Pursuant to the requirements of FASB No. 123,
the weighted average fair market value of options granted during 2003 and
2002 was $0.16 per share and $0.40 per share, respectively. The weighted
average closing bid prices for the Company's stock at the date the options
were granted during 2003 and 2002 were $0.43 per share and $1.15 per share,
respectively. The weighted average exercise price for outstanding options
at December 31, 2003 and 2002 per share was $1.06 and $1.37, 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 98% and 88%, risk-free
interest rate of 1.03% and 1.45% for grants in 2003 and 2002, respectively,
and an expected life of 1 year. As we have not declared dividends on our
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
our 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 2003 and
2002 for stock options granted.
Outstanding options at December 31, 2003 expire between January 13, 2004
and January 5, 2013.
(8) Related Party Transactions
Related party transactions which are not disclosed elsewhere in these
consolidated financial statements are discussed in the following
paragraphs:
We own 12.8% of the common stock of Drillmar, Inc. Our Chairman, Ivar Siem,
and one of our Directors, Harris A. Kaffie, are 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.
49
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Effective March 31, 2002, we recorded a full impairment of our investment
in Drillmar of approximately $340,000 and a full reserve for the accounts
receivable amount owed to us from Drillmar of approximately $200,000 due to
Drillmar's working capital deficiency and delays in securing capital
funding. During February and March 2004, we collected $30,000 from Drillmar
and we expect to receive $15,000 per month until the accounts receivable is
fully collected.
In May 2002, we entered into an agreement with Drillmar effective as of May
1, 2002, whereby we provided office space and minimal accounting and
administrative services to Drillmar for $2,000 per month. In addition, if
Drillmar is able to secure financing to implement its business plan, the
fee will increase by $18,000 to $20,000 per month retroactive to May 1,
2002.
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, our ownership in Drillmar can be reduced
to less than 1%. However, in November 2003, we converted our contingent
obligation due from Drillmar for providing office space, accounting and
administrative services from May 2002 through January 2003 totaling
$162,000 (9 months at $18,000 per month) into a convertible note, which if
converted along with all of Drillmar's outstanding convertible notes would
represent 7.7% of Drillmar's common stock. Messrs. Siem, Kaffie and Trimble
(one of our Directors) hold Drillmar convertible notes which if converted
along with all of Drillmar's outstanding convertible notes would represent
22.2%, 27.5% and 2.1%, respectively, of Drillmar's common stock.
In February 2003, we entered into a new agreement with Drillmar effective
as of February 1, 2003, whereby we provide office space to Drillmar for
$1,500 per month. We also provide professional, accounting and
administrative services to Drillmar based on hourly rates based on our
cost. The agreement can be terminated upon 30 days notice or by the mutual
agreement of the parties.
(9) Leases
We have various noncancelable operating leases which continue through 2006.
In March 2003, we entered into a sublease agreement expiring December 31,
2006 for certain of our office space with Tri-Union Development
Corporation. Our annual receipts from this sublease are $78,552. One of our
Directors, Mr. Trimble, 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, 2003:
50
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Future Future
minimum Future minimum
Year ending lease sublease lease
December 31, payments payments payments, net
-------------- -------------- -------------- --------------
2004 201,431 78,552 122,879
2005 198,153 78,552 119,601
2006 195,617 78,552 117,065
-------------- -------------- --------------
$ 595,201 $ 235,656 $ 359,545
============== ============== ==============
Rental expense on operating leases, net of sublease income for the years
indicated are as follows:
Year ended
December 31,
------------
2003 $ 89,319
2002 186,498
(10) Commitments and Contingencies
We are involved in various claims and legal actions arising in the ordinary
course of business. In our opinion, the ultimate disposition of these
matters will not have a material effect on our financial position, results
of operations or cash flows.
(11) Business Segment Information
Our income producing operations are conducted in two principal business
segments: oil and gas exploration and production and pipeline operations,
which includes mid-stream projects. The intercompany revenues and expenses
are eliminated in consolidation. Information concerning these segments for
the years ended December 31, 2003 and 2002 is as follows:
51
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, 2003:
Oil and gas exploration and
production $ 1,582,054 419,674 687,984 234,991
Pipeline operations 934,760 (1,100,096) 5,905,021 324,174
Other -- (531,141) 3,378,889 17,706
---------------- ---------------- ---------------- ----------------
Consolidated 2,516,814 (1,211,563) 9,971,894 576,871
Other income 458,960
----------------
Loss before income taxes (752,603)
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
1. Consolidated income (loss) from operations includes $513,435 and
$1,030,897 in unallocated general and administrative expenses, and
unallocated depletion, depreciation, amortization and impairment of
$17,706 and $361,084 for the years ended December 31, 2003 and 2002,
respectively.
2. Pipeline depletion, depreciation and amortization include a provision
for pipeline abandonment of $48,595 and $32,901 for the years ended
December 31, 2003 and 2002, respectively. Oil and gas depletion,
depreciation, amortization and impairment includes a provision for
abandonment costs of platforms and wells of $50,723 and $0 for the
years ended December 31, 2003 and 2002, respectively.
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 $875,777 (of which
$874,753 was recorded for future asset retirement obligations) and
$180,600 were recorded for pipeline operations for the years ended
December 31, 2003 and 2002, respectively.
Our primary market area is the Texas and Louisiana Gulf Coast region of the
United States. We have a concentration of credit risk with customers in the
energy industry. Our customers may be similarly affected by changes in
economic, regulatory or other factors. Trade receivables are generally not
collateralized; however, our 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.
52
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
Oil and gas Pipeline
sales operations Total
----------- ----------- -----------
Year ended December 31, 2003:
Spinnaker Exploration Corporation $ 1,446,662 -- $ 1,446,662
Year ended December 31, 2002:
Houston Exploration and Production Company -- 290,223 290,223
Apache Corporation -- 282,215 282,215
(12) Supplemental Oil and Gas Information - Unaudited
The following supplemental information regarding our oil and gas activities
are 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, we sold our 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% of our
oil and gas sales revenues for the year ended December 31, 2002, and 9% of
our total revenues for this period.
In November 2002, we sold our working interest in substantially all of our
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% of our oil and gas sales
revenues for the year ended December 31, 2002 and 52% of our total revenues
for this period.
In April 2003, we began to receive revenue from our 8.9% reversionary
working interest in the High Island Block A-7 field, in the Gulf of Mexico.
Production from this field accounted for 91% of our oil and gas sales for
the year ended December 31, 2003, and 57% of our total revenues for this
period.
In January 2004, it was determined that effective in August 2003, "payout"
had occurred on the High Island Block 34 field, which we own a 1.8%
reversionary interest in. Production from this field accounted for 4% of
our oil and gas sales for the year ended December 31, 2003, and 2% of our
total revenues for this period.
Estimated Quantities of Proved Oil and Gas Reserves
Set forth below is a summary of the changes in the estimated quantities of
our crude oil and condensate, and gas reserves for the periods indicated,
as estimated by us as of December 31, 2003 and 2002. All of our 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
53
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
as a result of new information obtained from drilling and production
history, new geological and geophysical data and changes in economic
conditions.
Proved reserves are estimated quantities of 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, 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
Reserve additions 70 11,702
Revisions to previous estimate 1,045 24,216
Production (2,271) (274,268)
---------- ----------
Total proved reserves at December 31, 2003 291 41,650
Proved developed reserves:
December 31, 2003 291 41,650
December 31, 2002 1,447 280,000
Capitalized Costs of Oil and Gas Producing Activities
The following table sets forth the aggregate amounts of capitalized costs
relating to our oil and gas producing activities and the aggregate amount
of related accumulated depletion, depreciation, amortization and impairment
as of December 31, 2003:
Unproved properties and prospect generation
costs not being amortized $ 160,697
Proved properties being amortized 170,046
Asset retirement obligation 194,945
Less accumulated depletion, depreciation,
amortization and impairment (234,991)
---------
Net capitalized costs $ 290,697
=========
54
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
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:
Year Ended
December 31,
-------------------
2003 2002
-------- --------
Exploration costs $ 83,423 $ --
Development costs 107,087 512,393
Asset retirement obligations 194,945 --
-------- --------
$385,455 $512,393
======== ========
Standardized Measure of Discounted Future Net Cash Flows
The following table reflects the Standardized Measure of Discounted Future
Net Cash Flows relating to our interest in proved oil and gas reserves as
of:
December 31,
--------------------------
2003 2002
----------- -----------
Future cash inflows $ 227,000 $ 1,183,824
Future development costs (63,000) (342,210)
Future production costs (27,000) (84,930)
Future Asset Retirement Costs (195,000) --
----------- -----------
Future net cash inflows (outflows) before income taxes (58,000) 756,684
Future income taxes 19,720 (257,273)
----------- -----------
Future net cash flows (38,280) 499,411
10% discount factor 13,200 (6,017)
----------- -----------
Standardized measure of discounted
future net cash inflows (outflows) $ (25,080) $ 493,394
=========== ===========
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.
55
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (continued)
We caution 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. We do 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 our proved oil and gas reserves for the periods
indicated are as follows:
December 31,
----------------------------
2003 2002
------------ ------------
Sales and transfers, net of production costs $ (1,395,398) $ (1,263,038)
Acquisition of reserves -- --
Net change in estimated future development costs 8,598 --
Sales of minerals in place -- (4,454,581)
Revisions in previous quantity estimates 159,067 162,782
Net changes in sales and transfer prices, 256,823 (161,868)
net of production costs
Accretion of discount 74,757 602,801
Net change in income taxes 267,092 3,236,489
Change in production rates (timing) and other (110,587) (14,604,636)
------------ ------------
Net change $ (518,474) $(16,482,051)
============ ============
56
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
None.
Item 8A. Controls and Procedures
As of the end of the period covered by this report, we carried out an
evaluation, under the supervision and with the participation of our management,
including our Chief Executive Officer and Principal Accounting Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rules 13a - 14(c) and 15d - 14 (c) under the
Securities Exchange Act of 1934, as amended). Based upon the evaluation, the
Chief Executive Officer and Accounting Officer concluded that our disclosure
controls and procedures are effective to ensure that information required to be
disclosed by us in reports that we file or submit under the Securities Exchange
Act of 1934, are recorded, processed, summarized and reported within the time
periods specified in Securities and Exchange
Commission rules and forms. There were no significant changes in our 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.
PART III
Item 9. Directors and Executive Officers of the Registrant
Directors and Executive Officers
The following table provides certain information with respect to our
directors and executive officers.
Position
Name Age Position Held Since
---- --- -------- ----------
Ivar Siem 57 Chairman of the Board, and 1989
Director
Michael S. Chadwick 52 Director 1992
Harris A. Kaffie 54 Director 1989
James M. Trimble 55 Director 2002
Michael J. Jacobson 58 President and Chief 1990
Executive Officer
John P. Atwood 52 Vice President 1998
G. Brian Lloyd 45 Vice President, Treasurer 1989
and Secretary
57
The following is a brief description of the background and principal
occupation of each director and executive officer:
Ivar Siem - Chairman of the Board of Directors - Since September 2000,
Mr. Siem has served as Chairman and President of Drillmar, Inc. a well
construction and intervention company. From 1995 to 2000, Mr. Siem served on the
Board of Directors of Grey Wolf, Inc., during which time he served as Chairman
from 1995 to 1998 and as interim President in 1995 during its restructuring.
Since 1985, he has been an international consultant in energy, technology and
finance. He has served as a Director of Business Development for Norwegian
Petroleum Consultants and as an independent consultant to the oil and gas
exploration and production industry based in London, England. Mr. Siem holds a
Bachelor of Science Degree in Mechanical Engineering from the University of
California, Berkeley, and has completed an executive MBA program at Amos Tuck
School of Business, Dartmouth University.
Michael S. Chadwick - Director - Mr. Chadwick has been engaged in the
commercial and investment banking businesses since 1975. From 1988 to 1994, Mr.
Chadwick was President of Chadwick, Chambers & Associates, Inc., a private
merchant and investment banking firm in Houston, Texas, which he founded in
1988. In 1994, Mr. Chadwick joined Sanders Morris Harris Group, Inc., an
investment banking and financial advisory firm, as Senior Vice President and a
Managing Director in the Corporate Finance Group, a position he continues to
hold today. He currently serves on the boards of directors of Landry's
Restaurants, Inc. and Home Solutions of America, as well as numerous privately
held companies. Mr. Chadwick holds a Bachelor of Arts Degree in Economics from
the University of Texas at Austin and a Master of Business Administration Degree
from Southern Methodist University.
Harris A. Kaffie - Director - Mr. Kaffie is a partner in Kaffie
Brothers, a real estate, farming and ranching partnership. He currently serves
as a Director of KBK Capital Corporation and Drillmar, Inc. Mr. Kaffie received
a Bachelor of Business Administration Degree from Southern Methodist University
in 1972.
James M. Trimble - Director - Mr. Trimble has been President and CEO of
Tri-Union Development Corporation since July 2002. Previously he served as
President of Elysium Energy, L.L.C., from July 2000 until the contribution of
its properties to a public oil and gas company in November 2001. Prior to
Elysium, Mr. Trimble served at Cabot Oil & Gas Corporation from May 1983 to May
2000 in several managerial and senior level executive positions. Before joining
Cabot, Mr. Trimble served as President of Volvo Petroleum, Inc. a Houston based,
private domestic and international exploration and production company. Mr.
Trimble graduated from Mississippi State University where he majored in
Petroleum Engineering for undergraduate and graduate studies.
58
Michael J. Jacobson - President and Chief Executive Officer - Mr.
Jacobson has been associated with the energy industry since 1968, serving in
various senior management capacities since 1980. He served as Senior Vice
President and Chief Financial and Administrative Officer for Creole
International, Inc. and it's subsidiaries, international providers of
engineering and technical services to the energy sector, as well as Vice
President of Operations for the parent holding company, from 1985 until joining
us in January 1990. He has also served as Vice President and Chief Financial
Officer of Volvo Petroleum, Inc., and for certain Fred. Olsen oil and gas
interests. Mr. Jacobson began his career with Shell Oil Company, where he served
in various analytical and management capacities in the exploration and
production organization during the period 1968 through 1974. Mr. Jacobson holds
a Bachelor of Science Degree in Finance from the University of Colorado.
John P. Atwood - Vice President, Business Development - Mr. Atwood has
been associated with the energy industry since 1974, serving in various
management capacities since 1981. He served as Senior Vice President of Land and
Administration for Glickenhaus Energy from 1987 to 1991, Area Land Manager for
CSX Oil & Gas Corporation and Division Land Manager for Hamilton Brothers Oil
Company/Volvo Petroleum, Inc. He served in various land capacities for Tenneco
Oil Company from 1977 to 1981. Mr. Atwood is a Certified Professional Landman
and holds a Bachelor of Arts Degree from Oklahoma City University and a Master
of Business Administration Degree from Houston Baptist University. Mr. Atwood
served as our Vice President of Land from 1991 to 1998 and Vice President of
Finance and Corporate Development until his appointment as Vice President of
Business Development in 2001.
G. Brian Lloyd - Vice President, Treasurer and Secretary - Mr. Lloyd is
a Certified Public Accountant and has been employed by us since December 1985.
Prior to joining us, he was an accountant for DeNovo Oil and Gas Inc., an
independent oil and gas company. Mr. Lloyd received a Bachelor of Science Degree
in Finance from Miami University, Oxford, Ohio in 1982 and also attended the
University of Houston. Mr. Lloyd has served as Secretary and Treasurer of the
Company since 1989 and Vice President since March 1998.
There are no family relationships between any director or executive
officer.
Committees And Meetings Of The Board Of Directors
During 2003, our Board of Directors held eight meetings. Each director
attended at least 75% of the total number of meetings of the Board of Directors
and committees on which he served.
At the beginning of 2003, the Audit Committee consisted of Mr. Robert
D. Wagner, Jr. and Mr. Chadwick. Mr. Wagner declined to stand for reelection in
May 2003. In May 2003, the Board elected Messrs. Chadwick, Kaffie and Trimble to
serve as the Audit Committee, with Mr. Chadwick elected as Chairman of the Audit
Committee. The Board of Directors has determined that Mr. Chadwick qualifies as
an "audit committee financial expert" as that term is defined in Item 401(e) of
Regulation S-B promulgated by the SEC. The Audit Committee's duties include
overseeing our financial reporting and internal control functions. The Audit
Committee met five times during the last fiscal year.
59
At the beginning of 2003, the Compensation Committee consisted of
Messrs. Siem and Kaffie. In May 2003, the Board elected Messers. Chadwick,
Trimble and Siem to serve as the Compensation Committee. The Compensation
Committee's duties are to oversee and set our compensation policy and to
administer our stock option plans. The Compensation Committee met twice during
the last fiscal year.
We do not have a nominating committee; instead the entire Board of
Directors participates in such decisions.
Compliance With Section 16 Of The Securities Exchange Act Of 1934, as amended
Section 16(a) of the Securities Exchange Act of 1934, as amended,
requires our directors, executive officers, and stockholders who own more than
10% of our Common Stock, to file reports of stock ownership and changes in
ownership with the Securities and Exchange Commission and to furnish us with
copies of all such reports they file. Based solely on a review of the copies of
the Section 16(a) reports furnished to us, we believe that during fiscal year
2003, all Section 16(a) filing requirements applicable to its directors,
executive officers and greater than 10% shareholders were complied with, except
for Mr. Chadwick who filed one such report late that reported two transactions.
Code of Ethics
We have adopted a code of ethics applicable to our Chairman, Chief Executive
Officer and Senior Financial Officer, which is our principal financial and
accounting officer. The Code of ethics is posted on our website,
www.blue-dolphin.com, and printed copies can be obtained by submitting a written
request to G. Brian Lloyd, Corporate Secretary, 801 Travis, Suite 2100, Houston,
Texas 77002.
Item 10. Executive Compensation
The following table sets forth the compensation paid to our Chief
Executive Officer and each of our executive officers whose annual salary
exceeded $100,000 in fiscal 2003 (collectively, the "Named Executive Officers")
for services rendered to us.
60
SUMMARY COMPENSATION TABLE*
Long-Term
Compensation
Awards
-----------------
Annual Compensation Securities
Name and -------------------------- Underlying
Principal Position Year Salary Bonus Options (#) (1)
------------------------- ------ ------------ ----------- -----------------
Ivar Siem 2003 $ 80,000 -- 30,000
Chairman of the Board 2002 $ 80,000 -- 10,000
2001 $150,000 -- --
Michael J. Jacobson 2003 $125,000 -- 30,000
President and Chief 2002 $125,000 -- 10,000
Executive Officer 2001 $200,000 -- --
John P. Atwood
Vice President - 2003 $120,000 -- 30,000
Business 2002 $ 90,000 -- 10,000
Development 2001 $137,500 -- --
G. Brian Lloyd 2003 $112,500 -- 30,000
Vice President - 2002 $105,000 -- 10,000
Treasurer 2001 $103,083 -- --
* Excludes certain personal benefits, the aggregate value of which do not exceed
10% of the Annual Compensation shown for each person.
(1) In fiscal year 2001 no options were granted to the named Executive Officers.
61
OPTION GRANTS IN LAST FISCAL YEAR
Percent of
Total
Number of Options
Securities Granted to
Underlying Employees Exercise of
Options In Fiscal Base Price* Expiration
Name Granted Year ($/Sh) Date
---- ----------------------------------------------------------
Ivar Siem 30,000 16% $0.43 1/05/2013
Michael J. Jacobson 30,000 16% $0.43 1/05/2013
John P. Atwood 30,000 16% $0.43 1/05/2013
G. Brian Lloyd 30,000 16% $0.43 1/05/2013
(*) The per share market price, as reported by the NASDAQ Smallcap Market on
January 6, 2003, the date of grant, was $0.43.
AGGREGATE OPTION EXERCISES IN LAST FISCAL YEAR AND YEAR-END OPTION VALUES
Value of Unexercised
Number of Unexercised In-the-Money Options
Options at Year End(1) at Year End (2)
Shares Acquired Value --------------------------- ---------------------------
Name on Exercise (#) Relalized Exercisable Unexercisable Exercisable Unexercisable
---- ----------------- ----------- ----------- ------------- ----------- -------------
Ivar Siem -- $ -- 52,000 -- $38,000 $ --
Michael J. Jacobson -- $ -- 50,000 -- $38,000 $ --
John P. Atwood -- $ -- 46,667 -- $38,000 $ --
G. Brian Lloyd -- $ -- 44,667 -- $38,000 $ --
(1) Includes options that expired on January 13, 2004 as follows: Mr. Siem -
4,000, Mr. Jacobson - 4,000, Mr. Atwood - 2,667 and Mr. Lloyd - 1,667.
(2) Based on the difference between the closing bid price on December 31,
2003 (the last trading day of 2003) which was $1.66 per share, which
exceeded the exercise price.
62
Our stock option plans provide that upon a change of control the
Compensation Committee may accelerate the vesting of options, cancel options and
make payments in respect thereof in cash in accordance with the terms of the
stock option plans, adjust the outstanding options as appropriate to reflect
such change of control, or provide that each option shall thereafter be
exercisable for the number and class of securities or property that the optionee
would have been entitled to receive had the option been exercised. The stock
option plans provide that a change of control occurs if any person, entity or
group acquires or gains ownership or control of more than 50% of the outstanding
Common Stock or, if after certain enumerated transactions, the persons who were
directors before such transactions cease to constitute a majority of the Board
of Directors.
Compensation Of Directors
In fiscal 2003, we paid to non-employee members of the Board of
Directors an annual retainer of $12,000, payable 50% in cash and 50% in Common
Stock. The Audit Committee chairman receives an annual retainer of $3,000 and
other Audit Committee members receive an annual retainer of $1,500. No
additional remuneration is paid to directors for committee meetings attended,
except that directors are entitled to be reimbursed for expenses related to
attendance of board or committee meetings. No additional compensation is paid to
directors serving on the Compensation Committee.
Item 11. Security Ownership of Certain Beneficial Owners and Management
The following table sets forth, as of April 15, 2004, certain
information with respect to the beneficial ownership of shares of our Common
Stock (our only class of voting security issued and outstanding) as to (i) all
persons known by us to be beneficial owners of 5% or more of the outstanding
shares of Common Stock, (ii) each director, (iii) each Named Executive Officer
and (iv) all executive officers and directors, as a group. Unless otherwise
indicated, each of the following persons has sole voting and dispositive power
with respect to such shares.
Name of Shares Owned Beneficially
---------------------------------------
Beneficial Owner Number Percent (1)
---------------------------------- ---------------------------------------
Colombus Petroleum
Limited, Inc. (2) 911,712 13.6
Ivar Siem (3) 966,264 14.3
Harris A. Kaffie (3) 804,486 11.8
Michael S. Chadwick (3) 95,130 1.4
James M. Trimble (3) 69,201 1.0
Michael J. Jacobson (3) 207,962 3.1
John P. Atwood (3) 90,265 1.3
G. Brian Lloyd (3) 85,366 1.3
Executive Officers and
Directors, as a Group
(7 persons) (3) 2,318,674 32.6
----------------------------------
(1) Based upon 6,712,438 shares of Common Stock outstanding on April 15,
2004.
63
(2) Based on a Schedule 13D filed with the Securities and Exchange
Commission on February 1, 1999. The address of Colombus Petroleum
Limited, Inc., is Aeulestrasse 74, FL-9490, Vaduz, Liechtenstein.
(3) Includes shares of Common Stock issuable upon exercise of options that
may be exercised within 60 days of April 15, 2004 as follows: Mr. Siem
- 48,000; Mr. Kaffie - 83,571; Mr. Chadwick - 83,571; Mr. Trimble -
57,142; Mr. Jacobson - 46,000; Mr. Atwood - 44,000; Mr. Lloyd - 43,000
and all directors and executive officers as a group - 405,284.
Equity Compensation Plans. The following table sets forth certain
information as of December 31, 2003 with respect to shares of Common Stock that
may be issued under our Incentive Plan and other equity compensation plans.
Equity Compensation Plan Information
Number of
securities
remaining
available for
Number of future issuance
securities to be under equity
issued upon compensation
exercise of Weighted-average plans (excluding
outstanding exercise price of securities
options, warrants outstanding options, reflected in the
Plan Category and rights warrants and rights first column)
------------- -------------------- --------------------- ----------------
Equity compensation plan approved
by security holders (1) 487,084 $1.00 162,916
Equity compensation plan not approved
by security holders (2) 14,835 3.13 381,988
-------------------- -------------------- ----------------
Total 501,919 $1.09 544,904
==================== ==================== ================
(1) Represents shares of Common Stock issuable upon exercise of outstanding
options granted under the Incentive Plan.
(2) All remaining options issued pursuant to this plan expired January 13,
2004.
Item 12. Certain Relationships and Related Transactions
In March 2003, we entered into a sublease agreement expiring December
31, 2006 for certain of our office space with Tri-Union Development Corporation
("Tri-Union"). Our annual receipts from this sublease are $78,552. One of our
directors, Mr. James M. Trimble, is the Chairman and Chief Executive Officer of
Tri-Union.
We own 12.8% of the common stock of Drillmar, Inc. Our Chairman, Ivar
Siem, and one of our Directors, Harris A. Kaffie, are owners of 30.3%, and
30.6%, respectively, of Drillmar's common stock. Messrs. Siem and Kaffie are
both directors, and Mr. Siem is also Chairman and President, of Drillmar.
64
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, our ownership in Drillmar can be reduced to less than 1%.
However, in November 2003, we converted our contingent obligation due from
Drillmar for providing office space, accounting and administrative services from
May 2002 through January 2003 totaling $162,000 (9 months at $18,000 per month)
into a convertible note, which if converted along with all of Drillmar's
outstanding convertible notes would represent 7.7% of Drillmar's common stock.
Messrs. Siem, Kaffie and Trimble, another one of our Directors, hold Drillmar
convertible notes which if converted along with all of Drillmar's outstanding
convertible notes would represent 22.2%, 27.5% and 2.1%, respectively, of
Drillmar's common stock.
In February 2003, we entered into a new agreement with Drillmar
effective as of February 1, 2003, whereby we provide office space to Drillmar
for $1,500 per month. We also provide professional, accounting and
administrative services to Drillmar based on hourly rates based on our cost. The
agreement can be terminated upon 30 days notice or by the mutual agreement of
the parties.
Item 13. Exhibits and Reports on Form 8-K
(a) 1. Exhibits
No. Description
--- -----------
3.1 (1) Certificate of Incorporation of the Company.
3.2 (2) Certificate of Correction to the Certificate of
Incorporation of the Company dated June 30, 1987.
3.3 (2) Certificate of Amendment to the Certificate of Incorporation
of the Company dated June 30, 1987.
3.4 (2) Certificate of Amendment to the Certificate of Incorporation
of the Company dated December 11, 1989.
3.5 (2) Our Certificate of Amendment to the Certificate of
Incorporation dated December 14, 1989.
3.6 (2) Our Bylaws.
3.7 (3) Our Certificate of Amendment to the Certificate of
Incorporation dated December 8, 1997.
4.1 (2) Specimen Certificate of our Company Common Stock.
* 10.1 (4) Blue Dolphin Energy Company 2000 Stock Incentive Plan.
* 10.2 (10) Amendment to the Blue Dolphin Energy Company 2000 Stock
Incentive Plan.
65
10.3 (5) 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.
10.4 (7) Amended and Restated Agreement and Plan of Merger, as
amended, among American Resources Offshore, Inc., Blue
Dolphin Energy Company and BDCO Merger Sub, Inc.
10.5 (6) Amendment No.1 to the Amended and Restated Agreement and
Plan of Merger.
10.6 (7) Purchase and Sale Agreement by and between Blue Dolphin
Energy Company and Newfield Exploration Company.
10.7 (8) Purchase and Sale Agreement by and between Blue Dolphin
Energy Company and Fidelity Exploration and Production
Company.
10.8 (9) Purchase and Sale Agreement by and between Blue Dolphin
Pipeline Company and MCNIC.
* * 14.1 Code of ethics applicable to the Chairman, Chief Executive
Officer and Senior Financial Officer.
** 21.1 List of subsidiaries of the Company.
** 23.1 Consent of Mann Frankfort Stein & Lipp CPAs, LLP.
** 31.1 Michael J. Jacobson Certification Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to section 302 of the
Sarbanes-Oxley Act of 2002.
** 31.2 G. Brian Lloyd Certification Pursuant to 18 U.S.C. Section
1350, as adopted pursuant to section 302 of the
Sarbanes-Oxley Act of 2002.
** 32.1 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.
** 32.2 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
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).
(4) 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).
66
(5) 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).
(6) 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).
(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 July 23, 2002 (Commission File No.
000-15905).
(8) 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).
(9) Incorporated herein by reference to Exhibits filed in connection with
Form 10-KSB of Blue Dolphin Energy Company for the year ended December
31, 2002 under the Securities and Exchange Act of 1934, dated March 21,
2003 (Commission File No. 000-15905).
(10) Incorporated herein by reference to Exhibits filed in connection with
the definitive Proxy Statement of Blue Dolphin Energy Company under the
Securities and Exchange Act of 1934, dated April 16, 2003 (Commission
File No. 000-15905).
* Management Compensation Plan.
** Filed herewith.
(b) Reports on Form 8-K
On November 12, 2003, we filed a current report on Form 8-K
dated November 12, 2003 reporting our fourth quarter 2003
earnings. The Item in such current report was Item 12 (Results
of Operations and Financial Condition).
Item 14. Principal Accountant Fees and Services
The fees we paid to Mann Frankfort Stein & Lipp CPAs, LLP in calendar years 2003
and 2002 are as follows:
2003 2002
-------- --------
Audit Fees ....................................... $ 78,046 $105,699
Audit-Related Fees ............................... -- --
Tax Fees ......................................... 35,398 38,500
All other Fees ................................... 1,300 --
-------- --------
Total ............................................ $114,744 $144,199
======== ========
Audit Fees include fees related to the audit of our consolidated financial
statements and review of our quarterly reports filed with the SEC. Tax Fees were
primarily for preparation of federal and state income tax return, and tax
planning services.
Our Audit Committee must pre-approve all audit and non-audit services provided
to us by our independent accountants.
67
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: April 28, 2004
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 April 28, 2004
----------------------------- executive officer)
Michael J. Jacobson
/s/ G. Brian Lloyd Vice President, Treasurer April 28, 2004
----------------------------- (principal accounting and
G. Brian Lloyd financial officer)
/s/ Ivar Siem Chairman April 28, 2004
-----------------------------
Ivar Siem
/s/ Harris A. Kaffie Director April 28, 2004
-----------------------------
Harris A. Kaffie
/s/ Michael S. Chadwick Director April 28, 2004
-----------------------------
Michael S. Chadwick
/s/ James M. Trimble Director April 28, 2004
-----------------------------
James M. Trimble
68