UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A-3
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Act of 1934
For the fiscal year ended December 31, 1999
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from ________ to ________
Commission file Number: 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 73-1268729
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
801 Travis, Suite 2100, Houston, Texas 77002
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code: (713) 227-7660
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
common stock $.01 par value
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value (estimated solely for purposes of this
calculation) of the voting stock held by non-affiliates of the registrant as of
January 4, 2001, was approximately $12,246,793.
As of January 4, 2001, there were outstanding 6,045,326 shares of
common stock, par value $.01 per share, of the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
The registrant's definitive proxy statement for the 2000 Annual Meeting
of Stockholders of the registrant (Sections entitled "Ownership of Securities of
the Company", "Election of Directors", "Executive Compensation" and
"Transactions With Related Persons"), filed with the Securities and Exchange
Commission pursuant to Regulation 14A, is incorporated by reference in Part III
of this report.
PART I
ITEM 1. BUSINESS
FORWARD LOOKING STATEMENTS. Certain of the statements included below,
including those regarding future financial performance or results or that are
not historical facts, are "forward-looking" statements as that term is defined
in the Section 21E of the Securities Exchange Act of 1934, as amended. The words
"expect," "plan," "believe," "anticipate," "project," "estimate," and similar
expressions are intended to identify forward-looking statements. Blue Dolphin
Energy Company (referred to herein, with its predecessors and subsidiaries, as
"Blue Dolphin" or the "Company") cautions readers that any such statements are
not guarantees of future performance or events and such statements involve
risks, uncertainties and assumptions, including but not limited to industry
conditions, prices of crude oil and natural gas, regulatory changes, general
economic conditions, interest rates, competition, and other factors discussed
below. Should one or more of these risks or uncertainties materialize or should
the underlying assumptions prove incorrect, actual results and outcomes may
differ materially from those indicated in the forward-looking statements.
Readers are cautioned not to place undue reliance on these forward-looking
statements which speak only as of the date hereof. The Company undertakes no
obligation to publish revised forward-looking statements to reflect events or
circumstances after the date hereof or to reflect the occurrence of
unanticipated events. Readers are also urged to carefully review and consider
the various disclosures made by the Company which attempt to advise interested
parties of the additional factors which affect the Company's business, including
the disclosures made under the caption "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in this report, as well as the
Company's periodic reports on Forms 10-Q and 8-K filed with the Securities and
Exchange Commission.
THE COMPANY
The Company is engaged in the acquisition and exploration of oil and gas
properties, and the gathering, transportation and storage of natural gas and
condensate. The Company is actively pursuing midstream projects with long term
revenue potential, such as the Petroport offshore oil terminal and the Avoca
natural gas storage project. The Company's primary geographical focus areas are
the western and central coasts of the U.S. Gulf of Mexico. The Company was
incorporated in 1986 as the result of the corporate combination of ZIM Energy
Corporation, a Texas corporation founded in 1983, and Petra Resources, Inc., an
Oklahoma corporation formed in 1980. The Company succeeded to the business,
properties and assets of ZIM Energy and Petra Resources. In June 1987, the
Company changed its name from ZIM Energy Corporation to Mustang Resources Corp.
In January 1990, the Company's name was changed to Blue Dolphin Energy Company.
In December 1999, the Company acquired a 75% ownership interest in American
Resources Offshore, Inc.
The Company is a holding company that conducts substantially all of its
operations through its subsidiaries. Substantially all of the Company's assets
consist of equity in its subsidiaries. The Company's subsidiaries are as
follows:
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o Blue Dolphin Exploration Company, a Delaware corporation,
o American Resources, a majority owned subsidiary of Blue Dolphin
Exploration;
o Blue Dolphin Pipe Line Company, a Delaware corporation;
o Blue Dolphin Services Co., a Texas corporation;
o Black Marlin Energy Company, a Delaware corporation,
o Black Marlin Pipeline Company, a Texas corporation and wholly owned
subsidiary of Black Marlin Energy;
o Buccaneer Pipe Line Co., a Texas corporation;
o Mission Energy, Inc., a Delaware corporation;
o New Avoca Gas Storage, LLC, a Texas Limited liability company in which the
Company owns a 25% interest; and
o Petroport, Inc., a Delaware corporation.
The principal executive office of the Company is located at 801 Travis,
Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660. American
Resources maintains a division office in New Orleans, Louisiana. Shore base
facilities are maintained in Freeport and Texas City, Texas serving Gulf of
Mexico operations. The Company has 24 full-time employees. The Company's Common
Stock is traded on the National Association of Securities Dealers, Inc.
Automated Quotation System ("NASDAQ") Small Cap Market under the trading symbol
"BDCO". The Company's home page address on the world wide web is
http://www.blue-dolphin.com.
BUSINESS AND PROPERTIES
The Company conducts its business activities in two primary business
segments: (i) pipeline operations, which includes our developmental mid-stream
projects, and (ii) oil and gas exploration and production. The Company owns and
operates, through its subsidiaries, natural gas and condensate pipeline
gathering facilities. The Company's oil and gas exploration and production
activities include the exploration, acquisition, development, operation and,
when appropriate, disposition of oil and gas properties. The Company also
develops for sale to third parties, oil and gas exploration prospects in the
Gulf of Mexico. See Note 10 to Consolidated Financial Statements included in
Item 8 and incorporated herein by reference for information relating to
revenues, operating profit or loss and identifiable assets of the Company's
business segments. The Company is also in varying stages of development of the
Petroport offshore oil terminal project and the Avoca natural gas storage
project.
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PIPELINE OPERATIONS AND ACTIVITIES
The Company's pipeline assets are held and operations conducted by Blue
Dolphin Pipe Line Company, Mission Energy, Buccaneer Pipe Line and Black Marlin,
all wholly owned subsidiaries of the Company.
PURCHASE AND SALE OF PIPELINE INTERESTS. On March 1, 1999, the Company
acquired Black Marlin Pipeline Company from Enron Pipeline Company ("Enron"),
for $5,404,270. In addition, Enron received an option to acquire a minimum of
25% and a maximum of 33-1/3% of the Black Marlin Pipeline System, if Black
Marlin Pipeline should become no longer subject to rate and tariff regulation by
the Federal Energy Regulatory Commission (the "FERC"). This option will expire
on the earlier of the third anniversary of the date of notice that the Black
Marlin Pipeline is no longer subject to rate and tariff regulation or March 1,
2004. Black Marlin Pipeline Company is the owner of the 75-mile Black Marlin
Pipeline System, as defined below. Effective as of March 1, 1999, the Company
sold
o a one-sixth (1/6) undivided interest in the Company's Blue Dolphin
Pipeline System, the Black Marlin Pipeline System and the Omega
Pipeline to WBI Southern, Inc. ("WBI") for $3,712,000, and
o a one-third (1/3) undivided interest in the Black Marlin Pipeline
System to MCNIC Pipeline and Processing Company ("MCNIC") for
$1,801,423.
The Company used the proceeds from these transactions to finance its
acquisition of Black Marlin Pipeline Company. MCNIC owns a one-third (1/3)
interest in the Blue Dolphin Pipeline System and the Omega Pipeline. Neither WBI
nor MCNIC is an affiliate of the Company.
BLUE DOLPHIN PIPELINE SYSTEM. The Company, through Blue Dolphin Pipe Line
Company, Mission Energy and Buccaneer Pipe Line, owns a 50% 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 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 natural gas and condensate
from the Buccaneer Field and other offshore fields in the area to shore
facilities located in Freeport, Texas. After processing, the gas is transported
to an end user and a major intrastate pipeline system with further downstream
tie-ins to other intrastate and interstate pipeline systems and end users. The
Buccaneer Pipeline, an 8" condensate pipeline, transports condensate from the
storage tanks to the Company's barge loading terminal on the Intracoastal
Waterway near Freeport, Texas for sale to third parties.
The Blue Dolphin Pipeline consists of two segments. The offshore segment
transports both natural gas and condensate and is comprised of approximately 36
miles of 20-inch pipeline from the Buccaneer Field platforms to shore and 4
miles to the shore facility at Freeport, Texas. Additionally, the offshore
segment includes 9 field gathering lines totaling approximately 55 miles,
connected to the main 20-inch line. This system's onshore segment consists of
approximately 2 miles of 16-inch pipeline for transportation of natural gas from
the shore facility to a sales point at a Freeport, Texas chemical plants'
complex and intrastate pipeline system tie-in.
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Various fees are charged to producer/shippers for provision of
transportation and shore facility services. Blue Dolphin System natural gas
throughput averaged approximately 21% of capacity during 1999. Current system
capacity is approximately 160 MMcf per day of gas and 7,000 Bbls per day of
condensate. During 1999, 99% of gas and condensate volumes transported were
attributable to production from third party producer/shippers. See Note 10 to
Consolidated Financial Statements included in Item 8 and incorporated herein by
reference.
BLACK MARLIN PIPELINE SYSTEM. Black Marlin is the owner of the Black Marlin
Pipeline System (the "Black Marlin System"). The Black Marlin System includes
the Black Marlin Pipeline, onshore facilities for condensate and gas separation
and dehydration, 3,000 Bbls of above ground tankage for storage of condensate, a
truck loading facility for oil and condensate, and 5 acres of land in Galveston
County, Texas where the Black Marlin Pipeline comes ashore and on which are
located the pipeline system's shore facilities.
Black Marlin is classified as a "natural gas company" pursuant to the
Natural Gas Act of 1938 and the Black Marlin Pipeline is classified as an
"interstate pipeline" pursuant to the Natural Gas Policy Act of 1978 and thus
subject to FERC regulation.
Gas and condensate from various producer/shippers in the High Island and
Galveston Areas of the Gulf of Mexico are gathered and transported through the
Black Marlin Pipeline to its shore facilities. After separation and dehydration,
gas is transported to an industrial end user or to either of two major
intrastate pipeline systems with further downstream tie-ins to other intrastate
and interstate pipeline systems and end users. Condensate is either delivered to
a liquids pipeline or transported by truck.
The Black Marlin Pipeline consists of two segments. The offshore segment
transports natural gas and condensate and is comprised of approximately 67 miles
of 16-inch pipeline from a High Island Block 136 platform, including an
extension from a platform in High Island Block A-6, to an interconnection in
High Island Block 137, across Galveston Bay to the onshore facilities at Texas
City, Texas. The offshore segment also includes approximately 7 miles of 8-inch
pipeline from a platform in High Island Block 199 to an interconnection with the
main line in High Island Block 171. The onshore segment consists of
approximately 2 miles of 16-inch pipeline from the shore facilities to an end
user and pipeline system tie-ins.
Various fees are charged to producer/shippers for provision of
transportation and shore facility services. Black Marlin System natural gas
throughput averaged approximately 28% of capacity during 1999. Current Black
Marlin System capacity is approximately 200 MMcf per day of gas and 1,500 Bbls
per day of condensate. During 1999, all gas and condensate volumes were
attributable to production from third party producer/shippers.
OTHER. The Company also holds a 50% undivided interest in the currently
inactive Omega Pipeline, MCNIC holds a one-third (1/3) interest and WBI holds a
one-sixth (1/6) interest. The Omega Pipeline originates in West Cameron Block
342 and extends to High Island, East Addition Block A-173, where it was
previously connected to the High Island Offshore System ("HIOS"). The line could
either be reconnected to HIOS, or a lateral pipeline could be constructed
connecting into the Black Marlin Pipeline approximately 14 miles to the west.
Reactivation of the Omega Pipeline will be dependent upon future drilling
activity in the vicinity and successfully attracting reserves to the system.
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The economic return to the Company on its pipeline system investments is
solely dependent upon the amounts of gas and condensate gathered and transported
through the pipeline systems. Competition for provision of gathering and
transportation services, similar to those provided by the Company, is intense in
the market areas served by the Company. See Competition, Markets and Regulation
- Competition below. Since contracts for provision of such services between the
Company and third party producer/shippers are generally for a specified time
period, there can be no assurance that current or future producer/shippers will
not subsequently tie-in to alternative transportation systems or that current
rates charged by the Company will be maintained in the future. The Company
actively markets gathering and transportation services to prospective third
party producer/shippers in the vicinity of its pipeline systems. Future
utilization of the pipelines and related facilities will depend upon the success
of drilling programs around the pipelines, and attraction, and retention, of
producer/shippers to the systems.
MIDSTREAM DEVELOPMENT PROJECTS
PETROPORT PROJECT
The Company's investment in and development of an offshore crude oil
terminal is through Petroport. In March 1995, the Company acquired Petroport,
L.C. The form of the transaction was a merger of Petroport, L.C. into Petroport.
Petroport holds proprietary technology, represented by certain patents issued
and or pending, associated with the development and operation of a deepwater
crude oil and products port and offshore storage facility. The Petroport
deepwater terminal will receive crude oil offshore with deliveries to shore by
pipeline. Onshore the Petroport pipeline will connect with an existing onshore
storage and distribution network, accessing Texas Gulf coast and Mid-Continent
refining centers.
In October 1999, the Company announced that Equilon Enterprises, LLC (an
alliance of two major oil companies, Shell and Texaco), agreed to jointly
continue development of the Petroport deepwater port project with the Company.
The agreement provided that the parties would share mutually agreed upon third
party costs for additional economic feasibility and design studies for the
purpose of determining whether to proceed with further development efforts,
including licensing and permitting of the facility. The same agreement
contemplated that the parties would enter into further contractual arrangements
in the event that Equilon chose to participate in the substantial additional
costs of proceeding with licensing of the facility, and that Equilon would have
no interest in the Petroport project if it did not. The agreement contemplated
that those additional contracts would address such matters as the parties'
respective ownership percentages of an entity to be formed to develop, own and
operate Petroport, the sharing of further development costs and cash payments to
the Company. Proposed, non-binding terms concerning those matters were contained
in the agreement but were subject to substantial change depending upon, among
other things, whether the Company or Equilon determined to sell a portion of
their respective interests in the project to other participants. Although the
Equilon agreement expired in December 1999, Equilon and the Company continued to
share relatively minor development expenses, although neither party was
obligated to do so. Costs of the offshore terminal complex, the pipeline to
shore, onshore facilities and facility licensing are estimated to be $200.0
million. Equilon has not advised the Company as to whether it will proceed with
licensing and further documentation. Whether Equilon determines to participate
further in the development of Petroport, the Company intends to continue its
efforts to attract throughput commitments from prospective users.
As currently planned, the facility will be located 40 miles off the Texas
coast in approximately 115 feet of water. The terminal complex will consist of
two single point mooring buoys connected to a central pumping platform, with a
main export pipeline from the platform to shore facilities in the
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Freeport, Texas area. At its onshore terminus, the main oil pipeline will access
existing onshore storage and a distribution network serving the greater Houston
area refiners and the NYMEX crude oil futures settlement hub at Cushing,
Oklahoma. The design capacity of the pipeline to shore will be in excess of 1.25
million barrels per day.
Petroport's future business environment is expected to be characterized by
a continuing significant demand by refiners for imports, with use of short haul
Caribbean Basin crudes as a major source of foreign crude. Petroport will offer
an alternative for receipt of large volumes of imported crude oil. The Company
believes Petroport's commercial success will be driven primarily by economies of
scale derived from use of larger, fully loaded tankers discharging short haul
Caribbean Basin cargoes into Petroport, and efficiencies gained by supertankers
discharging intermediate and long haul West African, North Sea, and Persian Gulf
crudes directly into Petroport versus current use of lightering operations.
Petroport will also be available to serve producers in the Gulf of Mexico.
It can serve as a major gathering hub and trunk line to shore, with crude
received from floating production storage and offloading systems serving
deepwater Gulf of Mexico producers.
Presently, the Company does not have a partner to participate in the
development of Petroport. However, the Company is actively soliciting major oil
and gas companies that import large volumes of crude oil and various other
entities to participate in the ownership and further costs of development. The
Company currently estimates that licensing and permitting costs for the offshore
port facility will be approximately $6.0 million and expects that its partner or
partners in the Petroport project would be responsible for the licensing and
permitting costs. The Company plans to seek financing for the costs associated
with facility construction, and expects that any such financing would be based
on the throughput commitments from prospective users. However, there can be no
assurance that the Company will be able to obtain either a partner and the
necessary throughput commitments to proceed with the development of Petroport.
In the process of evaluating and soliciting prospective partners for the
Petroport project, the Company has identified a second market for an offshore
crude oil port, located off the coast of Port Arthur, Texas. This facility would
be designed to fill a niche created by long term arrangements for the supply of
short haul Caribbean Basin crude oil delivered to conjested shallow water port
complexes. This port would target the smaller tankers used in the short haul
trade. The Company has completed preliminary conceptual design and costing work,
and a general commercial assessment for this project. In addition to the
licensing and permitting costs, the Company estimates that the construction
costs for this facility will be approximately $200.0 million. Presently, the
Company is working with a major potential user regarding the development of this
facility. The Company does not intend to proceed with the development of this
project without a major use commitment and support of a partner. There can be no
assurance that the Company will be able to obtain such use commitment or a
partner for the project.
AVOCA NATURAL GAS STORAGE PROJECT
In November 1999 the Company and WBI Holdings, Inc. ("WBI Holdings") formed
New Avoca Gas Storage LLC ("New Avoca"), 25% owned and managed by the Company
and 75% owned by WBI Holdings, and acquired the Avoca gas storage assets. The
Company records its investment in New Avoca by using the equity method of
accounting.
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The Avoca natural gas salt cavern storage project was conceived as a 5 BCF
working gas facility located south of Rochester near the town of Avoca, New
York. Its design provides for 250 MMcf/d injection and 500 MMcf/d withdrawal
capacities into the Tennessee Gas Pipeline HC400 24" line.
The original owner, Avoca Gas Storage, Inc., filed for bankruptcy on July
7, 1997. The assets were subsequently acquired out of bankruptcy by Northeastern
Gas Caverns ("Northeastern").
New Avoca purchased the Avoca gas storage assets from Northeastern for
$400,000 plus a contingent payment of $500,000. On June 28, 2000 the United
States Bankruptcy Court for the District of Delaware held a hearing to approve a
settlement agreement between Avoca Gas Storage, the Committee of Unsecured
Creditors, and an affiliate of Northeastern. The contingent payment of $500,000,
$125,000 net to the Company's interest in New Avoca, was due to Northeastern on
May 22, 2000. New Avoca made a payment of $50,000 and extended the remaining
$450,000 payment to August 22, 2000. In August 2000, Northeastern extended the
contingent payment until October 2000 in exchange for increasing the contingent
payment by $10,000 to $460,000. The contingent payment would be excused, and the
$40,000 net payment made would be refunded, if Northeastern successfully settles
a claim associated with Avoca Gas Storage, Inc. (the original owner of the Avoca
gas storage assets). In October 2000, Northeastern received a payment on its
claim and refunded the $40,000 previously paid by New Avoca. New Avoca can elect
to liquidate the project at any time.
The existing Avoca physical facilities include:
o 900+ acres of land
o Pumps and pipeline for fresh water
o Pump house containing 12 pumps (6,400 HP) for the solution mining
operation
o 5 cavern wells - 4,000' deep
o 6 brine disposal wells - 9,000' deep
o Storage building with valves, fittings, and miscellaneous parts
o Electrical switch gear
o Solution mining equipment
o Compressor foundations
o Electrical Sub-Station
To create the salt caverns for storage of natural gas, pressurized 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. The disposal wells must have
sufficient porosity and permeability to accept the injected brine at a rate that
will at least keep up 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 recently 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. In October
2000, New Avoca commenced testing of the disposal wells to determine the rate
that these wells will accept brine. New Avoca estimates that the test of the
disposal wells and the subsequent evaluation of the test results will take
approximately two months to complete. Based on the results of the tests, New
Avoca expects to make a decision to either proceed with or liquidate the
project. If liquidated, the Company believes that it can recover its investment
in this project. If the decision is
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made to proceed with the project, New Avoca estimates that it will take between
one and one-half to two years to begin operations at partial capacity, and three
to four years for the facility to operate at full capacity. However, until the
Company has reviewed and analyzed the results from the tests of the disposal
wells it will be unable to establish a definitive schedule or accurately
estimate the costs to complete this project.
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
The Company's oil and gas assets are held, and operations conducted by,
Blue Dolphin Exploration and American Resources. The Company's oil and gas
assets consist of leasehold interests in properties located offshore in the Gulf
of Mexico. The leasehold properties held by the Company may be subject to
royalty, overriding royalty and other outstanding interests customary in the
industry. In the future the Company's properties may become subject to burdens
such as liens incident to operating agreements and current taxes, development
obligations under oil and gas leases and other encumbrances, none of which the
Company believes will detract substantially from the value of the properties or
materially interfere with their use in its operations. Certain terms that are
commonly used in the oil and gas industry, including terms that define our
rights and obligations with respect to each of the Company's properties, are
defined in the "Glossary of Certain Oil and Gas Terms" on pages 18-19 of this
Form 10-K.
The following is a description of the Company's major oil and gas
exploration and production assets and activities:
AMERICAN RESOURCES. On December 2, 1999, Blue Dolphin Exploration acquired
a 75% ownership interest in American Resources by purchasing approximately 39.0
million shares of American Resources common stock. The purchase price for the
shares of American Resources' common stock was approximately $4.5 million.
Concurrently with the sale to Blue Dolphin Exploration, American Resources sold
an 80% interest in its Gulf of Mexico assets to Fidelity Oil Holdings, Inc. a
subsidiary of MDU Resources Group, Inc. The proceeds received by American
Resources were used to retire certain indebtedness.
American Resources' assets consist of an average 6% non-operated working
interest in eight producing properties and one proved undeveloped property along
with leasehold interests in 34 additional offshore tracts, all located in the
Gulf of Mexico offshore Louisiana and Texas. At closing, all significant
liabilities of American Resources were settled and substantially all stock
options and warrants were cancelled. The American Resources properties represent
41% of the discounted present value of estimated future net revenues from Proved
Reserves of the Company as of December 31, 1999. Sales of production from the
American Resources properties accounted for 52% of oil and gas sales revenues
and 10% of total revenues of the Company for the year ended December 31, 1999.
American Resources sells substantially all of its current oil and gas
production through the operators of its properties. The price American Resources
is currently receiving is based on current market prices. Previously, forward
sales contracts were utilized for a significant portion of its gas production to
achieve more predictable cash flow and to reduce the effect of fluctuations in
gas prices.
American Resources has established a preliminary budget of $1.4 million
for exploration and development of American Resources' oil and gas properties in
2000; however, this budget is subject to revision during the year to reflect
drilling results and new opportunities. American Resources will evaluate each of
the exploration and development opportunities and its available capital
resources to determine whether to participate, sell its interest or sell a
portion of its interest and use the proceeds to participate at a reduced
interest.
THE BUCCANEER FIELD. In November 2000, the Company decided to abandon the
Buccaneer Field as a result of the occurrence of unforeseen adverse events. In
July 2000, production from the
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only producing well in the Buccaneer Field, the A-12 well, ceased due to
down-hole mechanical problems. Due to the age of the A-12 wellbore, it is
probable that a new well would be needed to restore production at the Buccaneer
Field, at an estimated cost of $2.8 million.
In addition, in October 2000, during the annual inspection by the U.S.
Minerals Management Service ("MMS") of the two major platform complexes in the
Buccaneer Field, the MMS notified the Company that certain repairs to the
platforms must be made before operating activities can resume. The Company
estimates the cost of these required, unplanned repairs to be in excess of $1.0
million. However, the Company believes that if it elected to resume production
from the Buccaneer Field the actual costs would have been approximately $2.6
million, including an estimated $.6 million to repair one of the platform
complexes. Thus, the total cost to reestablish production would have increased
to an estimated $5.4 million, consisting of $2.6 million in front-end
infrastructure costs and $2.8 million in drilling costs.
After considering the costs associated with drilling a new well to
reestablish production, together with the unplanned cost of repairs to the
platforms and the projected rate of production and discounted cash flow from the
field, the Company has decided to abandon and not reestablish production from
the Buccaneer Field. As a result of our decision to abandon and not to
reestablish production from the Buccaneer Field, our lease on this field,
pursuant to its terms, will terminate at the end of January 2001.
The Buccaneer Field is comprised of interests in parts of four lease blocks
covering 14,660 acres located in the Gulf of Mexico approximately 36 miles south
of Freeport, Texas. Operation of the field is conducted from two platforms
located in waters averaging approximately 65 feet in depth.
The Company owns a 100% working interest in the Buccaneer Field (81.33% net
revenue interest). The Buccaneer Field leasehold interests represent 59% of the
discounted present value of estimated future net revenues from Proved Reserves
of the Company as of December 31, 1999. Production from the Buccaneer Field
accounted for 48% of the total revenues from oil and gas sales of the Company
for the year ended December 31, 1999 and 100% for the years ended December 31,
1998 and 1997. See "Proved Oil and Gas Reserves" below. Buccaneer Field
condensate and natural gas production is delivered to the Blue Dolphin System.
Natural gas produced from the Buccaneer Field was sold under a gas purchase
contract dated May 1, 1991. The contract was extended through September 2000 at
a variable monthly market price. In December 1999, the Company received a price
of $2.04/MMBtu. Buccaneer Field gas sales represented 42% of oil and gas sales
revenues and 8% of total revenues of the Company for the year ended December 31,
1999.
Buccaneer Field condensate sales were based on the average monthly market
price as reported by Koch Oil Company. Sale of condensate from the Buccaneer
Field represented 6% of oil and gas sales revenues and 1% of total revenues of
the Company for the year ended December 31, 1999.
The MMS requires that security be provided for the estimated future
abandonment obligations associated with the Buccaneer Field. Blue Dolphin
Exploration provided the MMS surety bonds in the amount of $1,300,000.
Additionally, Blue Dolphin Exploration was required to make a $250,000 annual
payment to a sinking fund to cover its end of lease abandonment and site
clearance obligations. Blue Dolphin Exploration is required to make payments to
the sinking fund until the balance of the sinking fund is $2,400,000, unless
changed by the MMS. The MMS may periodically increase, or decrease, the amount
of the sinking fund based upon its estimate of Blue Dolphin Exploration's lease
abandonment and site clearance costs. In 1999, Blue Dolphin Exploration elected
to remove an inactive satellite platform in the Buccaneer Field to reduce its
future lease abandonment and site clearance costs. The Company's annual
abandonment escrow fund payment of $250,000 that was due in June 1999 was waived
pursuant to a verbal agreement with the MMS as a result of the removal of
10
the inactive satellite platform. As of December 31, 1999, the sinking fund
totaled approximately $1,168,560.
In October 2000, the MMS notified the Company that they required additional
security to ensure that its abandonment obligations associated with the
Buccaneer Field will be met. The Company has escrowed approximately $1.49
million for abandonment costs and provided $1.3 million in surety bonds. At the
request of the MMS, the Company has delivered an additional $2.9 million in
surety bonds and used the escrowed funds as collateral for the surety bonds.
In addition to conducting traditional oil and gas production operations for
itself, the Company operates and maintains oil and gas production facilities for
third party producers who also utilize the Blue Dolphin System for gathering and
transportation of their production. The Company had a contract with Apache
Corporation to provide operation and maintenance services that terminated in
December 2000. During 1999, approximately 11% of the Company's revenues were
attributable to its contract with Apache Corporation.
OFFSHORE OIL AND GAS PROSPECT GENERATION ACTIVITIES. In August 1994, Blue
Dolphin Exploration initiated a program to develop oil and gas exploration
prospects in the Gulf of Mexico for sale to third parties. The program utilizes
3-D seismic data. The Company owns a non-exclusive license to 150 blocks of 3-D
seismic data covering 850,000 acres in the Western Gulf of Mexico and a
substantial inventory of close grid 2-D seismic data. In addition to recovering
prospect development costs, Blue Dolphin Exploration seeks to retain a
reversionary working interest in each drillable prospect.
In September 1997, the Company entered into an agreement with Fidelity
Oil, Western Production and Forcenergy (the "Participants"), whereby in exchange
for certain participation rights, the Participants partially funded the costs
associated with the Company's 1997/1998 offshore prospect generation program.
The Company is obligated to, among other things, devote its best efforts to
initiate, evaluate, document and present drilling prospects to the Participants.
In order to enhance the productivity of the prospect generation program, during
1998 the Company transitioned from the use of consulting geologists and
geophysicists to a 100% in house effort. This program was suspended in August
1998, as a result of the withdrawal of Forcenergy who filed for bankruptcy.
In 1999 the Company placed a 50% interest in the program with Fidelity
Oil, whereby in exchange for certain participation rights, Fidelity Oil funds
$100,000 per month for the costs associated with the program. Program costs will
be reimbursed to the Company as prospects are developed and leases acquired. A
portion of the reimbursed costs will be paid to Fidelity Oil based on the level
of interest it retains in each prospect. The available 50% interest in the
generated prospects is for sale on an individual prospect basis. In April 2000,
the Company amended the agreement with Fidelity Oil in its prospect generation
program, whereby in exchange for certain participation rights of up to 100%,
Fidelity Oil will fund, on a monthly basis, an aggregate of up to $1,060,000 of
the costs associated with the program during 2000. As of December 31, 2000
Fidelity Oil had paid $1,069,888 of these costs. Fidelity Oil will also
reimburse the Company for the expenses it incurs acquiring seismic data. The
available interests in the prospect inventory are for sale on an individual
prospect basis.
The Company spent the first half of 1999 developing and marketing a
prospect inventory in preparation for the Western Gulf of Mexico Federal Lease
Sale held in August. Of the five prospects developed, one was sold in which the
Company retained a reversionary working interest. Partial interests were sold in
all of the pre-existing inventory of leased prospects. The Company is continuing
to market the remaining interests. The Company's leased prospect inventory
consists of prospects on the following offshore leases:
11
o High Island Area Block A-8
o Mustang Island Area Block 817
o Mustang Island Area Block 839
The Company has reversionary interests in the following offshore leases:
o High Island Area Block A-7
o Galveston Area Block 297
o Matagorda Island Area Block 713
o Galveston Area Block 271
o Galveston Area Block 284
o Galveston Area Block 285
o Matagorda Island Area Block 710
In November 2000, Fidelity Oil notified the Company that it was electing
to withdraw from this program effective December 31, 2000. Presently, the
Company is considering several alternatives including, but not limited to,
finding new participants for the program and changes in the participation terms
of the program. However, there can be no assurance that the Company will not
suspend this program.
PROVED OIL AND GAS RESERVES. Estimates of proved reserves, future net
revenues, and discounted present value of future net revenues to the net
interest of the Company have been prepared as of December 31, 1999, by
Netherland Sewell & Associates, Inc., Ryder Scott Company and the Company
(Buccaneer Field). Both Netherland Sewell & Associates, Inc. and Ryder Scott
Company are independent petroleum engineers.
The following table summarizes the estimates of Proved Reserves, Proved
Developed Reserves (as hereinafter defined), future net revenues and the
discounted present value of future net revenues from Proved Reserves before
income taxes to the net interest of the Company in oil and gas properties as of
December 31, 1999, using the SEC Method (defined below).
PROVED RESERVES INFORMATION
AS OF DECEMBER 31, 1999
NET OIL NET GAS FUTURE DISCOUNTED FUTURE
RESERVES RESERVES NET REVENUES NET REVENUES (3)
(MB) (MMCF) ($000) ($000)
-------- -------- ------------ ----------------
Total Proved: (1)
ARO (4) ............................... 145 4,349 $ 7,714 $ 6,101
Buccaneer Field ....................... 111 17,869 $ 25,726 $ 8,891
-------- -------- ------------ ----------------
TOTAL PROVED RESERVES ................. 256 22,218 $ 33,440 $ 14,992
======== ======== ============ ================
Total Proved Developed Reserves: (2)
ARO (4) .............................. 95 2,531 $ 5,078 $ 4,155
Buccaneer Field ...................... 111 17,869 $ 25,726 $ 8,891
-------- -------- ------------ ----------------
TOTAL PROVED DEVELOPED
RESERVES ......................... 206 20,400 $ 30,804 $ 13,046
======== ======== ============ ================
MB = Thousand Barrels MMCF = Million Cubic Feet
12
(1) "Proved Reserves" means the estimated quantities of oil, natural gas and
condensate which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
(2) "Proved Developed Reserves" are those quantities of oil, natural gas and
condensate which are expected to be recovered through existing wells with
existing equipment and operating methods.
(3) The estimated future net revenues before deductions for income taxes from
the Company's Proved Reserves have been determined and discounted at a 10%
annual rate in accordance with requirements for reporting oil and gas
reserves pursuant to regulations promulgated by the United States
Securities and Exchange Commission (the "SEC Method"). See estimated future
net revenues after deductions for income taxes in Note 11 to Consolidated
Financial Statements of Blue Dolphin Energy Company and Subsidiaries.
(4) The Company acquired a 75% ownership interest in American Resources on
December 2, 1999. The above reflects 100% of American Resources' reserves
and future net revenues, 25% of discounted future net revenues associated
with total Proved Reserves and total Proved Developed Reserves of the
American Resources' properties is $1,525,252 and $1,038,750, respectively.
The quantities of proved natural gas and crude oil reserves presented
include only those amounts which the Company reasonably expects to recover in
the future from known oil and gas reservoirs under existing economic and
operating conditions. Therefore, Proved Reserves are limited to those quantities
that are believed to be recoverable commercially at prices and costs, and under
regulatory practices and technology existing at the time of the estimate.
Accordingly, changes in prices, costs, regulations, technology and other factors
could significantly affect the estimates of Proved Reserves and the discounted
present value of future net revenues attributable thereto.
The reserves and future net revenues summarized above reflect capital
expenditures totaling $1,416,323, $570,139, $404,430, $178,350 and $43,300 in
the years ending December 31, 2000, 2001, 2002, 2003 and 2004, respectively.
Management will continue to evaluate its capital expenditure program based on,
among other things, demand and prices obtainable for the Company's production.
The availability of capital resources may affect the Company's timing for
further development, and there can be no assurance that the timing of the
development of such reserves will be as currently planned.
The discounted present value of estimated future net revenues attributable
to Proved Reserves has been prepared in accordance with the SEC Method after
deduction of royalties and other third-party interests, lease operating
expenses, and estimated production, development, workover and recompletion
costs, but before deduction of income taxes, general and administrative costs,
debt service and depletion and amortization. Estimated future net revenues are
based on prices of oil and gas in effect at the end of the year without
escalation except to the extent contractually committed. Lease operating
expenses, and production and development costs, were estimated based on such
costs in effect at the end of the year, assuming the continuation of existing
economic conditions and without adjustment for inflation or other factors. The
present value of estimated future net revenues is computed by discounting future
net revenues at a rate of 10% per annum. Revenues from wells not currently
producing are included at the time they are expected to be placed into
production based upon estimates of future development; workover and recompletion
costs are included at the time they are expected to be incurred. Of the
Company's total Proved Developed Reserves, 8% of its estimated gas reserves and
29% of its estimated oil reserves were being produced at December 31, 1999.
13
Estimates of production and future net revenues cannot be expected to
represent accurately the actual production or revenues that may be recognized
with respect to oil and gas properties or the actual present market value of
such properties. For further information concerning the Company's Proved
Reserves, changes in Proved Reserves, estimated future net revenues and costs
incurred in the Company's oil and gas activities and the discounted present
value of estimated future net revenues from the Company's Proved Reserves, see
Note 11 - Supplemental Oil and Gas Information to Consolidated Financial
Statements included in Item 8 and incorporated herein by reference.
PRODUCTIVE WELLS AND ACREAGE. The following table sets forth the Company's
interest in productive wells and developed and undeveloped acreage as of
December 31, 1999.
ACREAGE AND WELLS
PRODUCTIVE WELLS (1) DEVELOPED UNDEVELOPED
----------------------------------------- ------------------- -------------------
GROSS NET ACRES (1) ACRES (1)
------------------- ------------------- ------------------- -------------------
OIL GAS OIL GAS GROSS NET GROSS NET
-------- -------- -------- -------- -------- -------- -------- --------
American Resources (2) 17 10 0.73 0.61 45,497 2,820 149,205 8,971
Buccaneer Field ...... 0 1 0 1 8,730 8,730 5,930 5,930
Other ................ 0 0 0 0 0 0 5,760 1,728
-------- -------- -------- -------- -------- -------- -------- --------
17 11 0.73 1.61 54,227 11,550 160,895 16,629
======== ======== ======== ======== ======== ======== ======== ========
(1) "Productive wells" are producing wells and wells capable of production,
and include gas wells awaiting pipeline connections or necessary
governmental certifications to commence deliveries and oil wells to be
connected to production facilities. "Developed acres" include all acreage
as to which proved reserves are attributed, whether or not currently
producing, but exclude all producing acreage as to which the Company's
interest is limited to royalty, overriding royalty, and other similar
interests. "Undeveloped acres" are considered to be those acres on which
wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas regardless of whether
such acreage contains Proved Reserves. "Gross" as it applies to wells or
acreage refers to the number of wells or acres in which a working
interest is owned, while "net" applies to the sum of the fractional
working interests in gross wells or acreage.
(2) The Company acquired a 75% ownership interest in American Resources on
December 2, 1999. The above reflects 100% of American Resources' acreage
and wells.
PRODUCTION, PRICE AND COST DATA. The following table sets forth the
approximate production volumes and revenues, average sales prices and costs
(after deduction of royalties and interests of others) with respect to crude
oil, condensate, and natural gas attributable to the interest of the Company for
each of the periods indicated:
14
NET PRODUCTION, PRICE AND COST DATA
YEAR ENDED DECEMBER 31,
------------------------------------------
1999 1998 1997
------------ ------------ ------------
Gas:
Production (Mcf) ............ 169,329 177,260 176,986
Revenue ..................... $ 393,125 $ 391,913 $ 393,444
Average Mcf per Day ......... 463.9 485.6 484.9
Average Sales Price
Per Mcf .................. $ 2.32 $ 2.21 $ 2.22
Oil:
Production (Bbls) ........... 6,338 1,628 1,156
Revenue ..................... $ 151,974 $ 20,840 $ 21,636
Average Bbls per day ........ 17.4 4.5 3.2
Average Sales Price
Per Bbl .................. $ 23.98 $ 12.80 $ 18.72
Production Costs (1):
Per Equivalent Mcf (2): $ 4.14 $ 3.30 $ 4.16
(1) Production costs, exclusive of workover costs, are costs incurred to
operate and maintain wells and equipment and to pay production taxes.
(2) Equivalent Mcf includes oil and condensate stated in terms of natural gas
at the rate of one Bbl. of oil or condensate to six Mcf of natural gas.
DRILLING ACTIVITY. There was no drilling activity during 1999. There were
two (.5 net) unsuccessful exploratory wells drilled in 1998, including one on a
prospect generated and sold to third parties by the Company. There was no
drilling activity during 1997.
The Company maintains a professional staff capable of supervising and
coordinating the operation and administration of its oil and gas properties and
pipeline and other assets. From time to time, major maintenance and engineering
design and construction projects are contracted to third-party engineering and
service companies.
COMPETITION, MARKETS AND REGULATION
COMPETITION
The oil and gas industry is highly competitive in all segments.
Increasingly vigorous competition occurs among oil, gas and other energy
sources, and between producers, transporters, and distributors of oil and gas.
Competition is particularly intense with respect to the acquisition of desirable
producing properties and the marketing of oil and gas production. There is also
competition for the acquisition of oil and gas leases suitable for exploration
and for the hiring of experienced personnel to manage and operate the Company's
assets. Several highly competitive alternative transportation and delivery
options exist for current and potential customers of the Company's traditional
gas and oil gathering and transportation business as well as for refiners,
shippers, marketers and producers of crude oil whom the Company's proposed
Petroport facility would serve.
15
Gas storage customers who would use the proposed Avoca Gas Storage system have
alternatives, including depleted reservoir and salt cavern storage. Competition
also exists with other industries in supplying the energy and fuel needs of
consumers.
MARKETS
The availability of a ready market for natural gas and oil, and the prices
of such natural gas and oil, depend upon a number of factors which are beyond
the control of the Company. These include, among other things, the level of
domestic production, actions taken by foreign oil and gas producing nations, the
availability of pipelines with adequate capacity, the availability of vessels
for lightering and transshipment and other means of transportation, the
availability and marketing of other competitive fuels, fluctuating and seasonal
demand for oil, gas and refined products, and the extent of governmental
regulation and taxation (under both present and future legislation) of the
production, importation, refining, transportation, pricing, use and allocation
of oil, natural gas, refined products and alternative fuels.
Accordingly, in view of the many uncertainties affecting the supply and
demand for crude oil, natural gas and refined petroleum products, it is not
possible to predict accurately the prices or marketability of the natural gas
and oil produced for sale or prices chargeable for transportation, terminaling
and storage services, which the Company provides or may provide in the future.
GOVERNMENTAL REGULATION
The production, processing, marketing, and transportation of oil and
natural gas, and planned terminaling and storage of crude oil and natural gas
storage by the Company are subject to federal, state and local regulations which
can have a significant impact upon the Company's overall operations.
FEDERAL REGULATION OF NATURAL GAS TRANSPORTATION. The transportation and
resale of natural gas in interstate commerce have been regulated by the Natural
Gas Act, the Natural Gas Policy Act and the rules and regulations promulgated by
FERC. In the past the federal government has regulated the prices at which
natural 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 natural gas,
effective January 1, 1993. Congress could, however, reenact price controls in
the future.
The price and terms for access to pipeline transportation is subject to
extensive federal regulation. In April 1992, the FERC issued Order No. 636,
beginning a series of related orders, which required interstate pipelines to
provide open-access transportation on a basis that is equal for all natural gas
suppliers. The FERC has stated that it intends Order No. 636 to foster increased
competition within all phases of the natural gas industry. Order No. 636 affects
how buyers and sellers gain access to the necessary transportation facilities
and how natural gas is sold in the marketplace. In 2000, the FERC issued Order
No. 637 which, among other things, will permit pipelines to file for
peak/off-peak and term differentiated rate structures and changed existing
regulations relating to scheduling procedures, capacity segmentation pipeline
imbalance processes and penalties and pipeline reporting requirements.
The Company cannot predict whether the FERC's actions will achieve the goal
of increasing competition in the natural gas markets or how these, or future,
regulations will affect its operations or competitive position. However, the
Company does not believe that any action taken will affect it in any way that
materially differs from the way that such action affects the Company's
competitors.
Of the natural gas pipelines owned by the Company, only the Black Marlin
Pipeline is subject to rules and regulations of the Natural Gas Act. As a
result, its gas transportation service and pricing
16
service are subject to the regulatory jurisdiction of the FERC. The previous
owner of the Black Marlin Pipeline completed a FERC rate case which redetermined
the rate the Company charges for use of its pipeline. As a result of the
completion of the FERC case, the Company can expect a certain level of stability
in the rates it charges. However, there is a trend toward greater competition
among gas pipelines subject to the Natural Gas Act making it infeasible for
regulated pipelines to rely upon exclusive monopoly status. Additionally,
requirements of the Gas Industry Standards Board ("GISB") continue to evolve,
and, along with Order No. 637 reporting and operational requirements, may impose
additional obligations and costs upon interstate pipelines subject to these
requirements.
All of the Company's pipelines located in federal offshore waters, whether
subject to Natural Gas Act jurisdiction or exempted as nonjurisdictional
gathering, are subject to the requirements of the Outer Continental 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 natural gas pipelines on the Outer Continental Shelf
will transport for non-owner shippers in a nondiscriminatory manner and will be
operated in accordance with certain pro-competitive principles. More recently,
the FERC has undertaken several investigations into the nature and extent of its
regulatory powers on the Outer Continental Shelf. It issued a policy statement
on Outer Continental Shelf pipelines reaffirming the requirement that all
pipelines provide nondiscriminatory service. Additionally, currently pending
complaints against nonjurisdictional gathering facilities under the OCSLA seek
more stringent FERC regulation of service and pricing.
Further FERC initiatives concerning possibly diminished Natural Gas Act
regulation of pipelines on the OCS and/or broader regulation under the OCSLA are
under consideration. Since all of the Companies' offshore pipelines already
operate on the basis required under OCSLA, the Company does not anticipate
significant changes directly resulting from requirements concerning
nondiscriminatory open access transportation. Moreover, if an offshore
pipeline's throughput increases to the extent that the pipeline's capacity is
completely utilized, under OCSLA, the FERC may be petitioned to direct capacity
allocation on the pipeline. Accordingly, the Company cannot predict how
application of the OCSLA to the Companies' pipelines may ultimately affect
Company operations.
Aside from the OCSLA requirements and federal safety and operational
regulations, regulation of natural gas gathering activities is primarily a
matter of state oversight. Regulation of gathering activities in Texas includes
various transportation, safety, environmental and non-discriminatory
purchase/transport requirements.
FEDERAL REGULATION OF OIL PIPELINES. The Company's operation of the
Buccaneer Pipeline is subject to a variety of regulations promulgated by the
FERC and imposed on all oil pipelines pursuant to federal law. In particular,
the rates chargeable by the Company are subject to prior approval by the FERC,
as are operating conditions and related matters contained in the Company's
transportation tariffs which are on file with the FERC. In October 1993, the
FERC issued Order No. 561, which was intended to simplify oil pipeline
ratemaking, largely through use of a ceiling based on an indexing system.
Because Buccaneer Pipeline has not taken action to become subject to Order No.
561 or Order No. 572 concerning market-based rates for oil pipelines, the
Company cannot predict whether or how an indexed or market-based rate system
will affect the Buccaneer Pipeline's rates.
SAFETY AND OPERATIONAL REGULATIONS. The operations of the Company are
generally subject to safety and operational regulations administered primarily
by the MMS, the U.S. Department of Transportation, the U.S. Coast Guard, the
FERC and/or various state agencies. Currently, the Company believes that it is
in compliance with the various safety and operational regulations that it is
subject to. However, as safety and operational regulations are frequently
changed, the Company is unable to predict the future effect changes in these
regulations will have on its operations, if any.
17
REGULATION OF DEEPWATER PORTS: PERMITTING AND LICENSING. The ownership,
construction and operation of a deepwater crude oil terminal facility (a
"Deepwater Port"), such as the Company's proposed Petroport facility, must
conform to the requirements of a number of Federal, State and local laws. A
license from the Department of Transportation ("DOT") is required under the
Deepwater Port Act of 1974 ("DWPA"), as amended. Permits from the Environmental
Protection Agency and the Federal Communication Commission are required, as well
as permits from the U.S. Army Corps of Engineers and the State of Texas to
construct ancillary port facilities, such as pipelines and onshore facilities.
The DWPA empowers the Secretary of Transportation to license and regulate
Deepwater Ports beyond the territorial sea of the United States. License
applications must include sufficient information to allow the Secretary of
Transportation to judge whether a Deepwater Port will comply with all technical,
environmental, and economic criteria. The application and licensing process
includes the preparation of an Environmental Impact Statement, development of
detailed operations procedures, submission of extensive financial and ownership
data and public hearings.
The Company was a principal participant in the development and passage of
The Deepwater Port Modernization Act in 1996, successfully amending the DWPA.
The amendments to the Deepwater Port Act provide: (1) upon written request of an
applicant for a license, the Secretary may exempt the applicant from certain of
the informational filing requirements if the Secretary determines such
information is not necessary to facilitate his or her determination and such
exemption will not limit public review; (2) the facility is explicitly permitted
to receive domestic production from the United States Outer Continental Shelf;
(3) simplification and streamlining of the regulatory process to which the
facility would be subject during both the licensing process and when in
operation; and (4) elimination of various facility use restrictions. Once a
license is issued, the law states that it remains in effect unless suspended or
revoked by the Secretary of Transportation or is surrendered by the licensee.
Regulations provide for extensive consultation among all interested Federal
agencies, any potentially affected coastal state, and the general public.
Adjacent coastal states are granted an effective veto power or reservation over
proposed Deepwater Ports. The Secretary of Transportation will not issue a
license without the approval of the governor of each adjacent coastal state.
Under the statute, if a Governor of an adjacent coastal state notifies the
Secretary of Transportation that a proposal is inconsistent with the state
programs relating to environmental protection, land and water use, and coastal
zone management, then the Secretary of Transportation shall grant the license on
the condition that the proposal is made consistent with such state programs.
Governors may, in their discretion, also reject proposed Deepwater Ports on
other grounds.
In addition, the DWPA requires all Deepwater Ports, including related
storage facilities, be operated as common carriers. As a common carrier the
Company's proposed Petroport facility would be required to accept, transport or
convey all oil delivered, unless it is subject to "effective competition" from
alternative transportation systems.
Given the nature and complexity of obtaining the necessary license and
permits, there can be no assurance that the Company will be issued a Deepwater
Port license and other necessary permits.
FEDERAL OIL AND GAS LEASES. The Company's operations conducted on offshore
oil and gas leases under the OCSLA must be conducted in accordance with permits
issued by the MMS and are subject to a number of other regulatory restrictions
similar to those imposed by the states.
With respect to any Company operations conducted on offshore federal leases
liability may generally be imposed under OCSLA for costs of clean-up and damages
caused by pollution resulting from such operations, other than damages caused by
acts of war or the negligence of third parties. Under certain circumstances,
including but not limited to conditions deemed a threat or harm to the
18
environment, the MMS may also require any Company operations on federal leases
to be suspended or terminated in the affected area. Furthermore, the MMS
generally requires that offshore facilities be dismantled and removed within one
year after production ceases or the lease expires. However, on July 7, 2000, the
MMS published proposed rules under which offshore structures may be left in
place, subject to EPA approval. See "Oil and Gas Exploration and Production
Activities - The Buccaneer Field."
ENVIRONMENTAL REGULATIONS. The Company may generally be liable for defined
clean-up costs to the U.S. Government, with respect to its operations on both
onshore and offshore properties, under the Federal Clean Water Act for each
incident of oil or hazardous substance pollution and under the Comprehensive
Environmental Response, Compensation and Liability Act of 1981, as amended
("Superfund"), for hazardous substance contamination. Such liability may be
unlimited in cases of gross negligence or willful misconduct, and there is no
limit on liability for environmental clean-up costs or damages with respect to
claims by the states or by private persons or entities. In addition, the
Environmental Protection Agency requires the Company to obtain permits to
authorize the discharge of pollutants into navigable waters. State and local
permits and/or approvals may also be needed with respect to wastewater
discharges and air pollutant emissions. Violations of environmental related
lease conditions or environmental permits can result in substantial civil and
criminal penalties as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental or citizen prosecution.
LEGISLATION AND RULEMAKING. In October 1996 the U.S. Congress enacted the
Coast Guard Authorization Act of 1996 (P.L. 104-324) which amended the Oil
Pollution Act of 1990 ("OPA `90") to establish requirements for evidence of
financial responsibility for certain offshore facilities, other than Deepwater
Ports. The amount required is $35.0 million for certain types of offshore
facilities located seaward of the seaward boundary of a state, including
properties used for oil transportation. The Company currently maintains this
statutory $35.0 million coverage.
In August 1995, the DOT issued a Rulemaking under OPA '90, providing that
the Secretary of Transportation can set the liability limit and associated
Certificate of Financial Responsibility requirement for Deepwater Ports from
between $350.0 million and $50.0 million concurrent with the overall processing
of the DWP license application. Development of the liability limit would be
based upon engineering and environmental analysis provided during the licensing
process.
Federal and state legislative rules and regulations are pending that, if
enacted, could significantly affect the oil and gas industry. It is impossible
to predict which of those federal and state proposals and rules, if any, will be
adopted and what effect, if any, they would have on the operations of the
Company.
In addition, various federal, state and local laws and regulations covering
the discharge of materials into the environment, occupational health and safety
issues, or otherwise relating to the protection of public health and the
environment, may affect the Company's operations, expenses and costs. The trend
in such regulation has been to place more restrictions and limitations on
activities that may impact the general or work environment, such as emissions of
pollutants, generation and disposal of wastes, and use and handling of chemical
substances. It is not anticipated that, in response to such regulation, the
Company will be required in the near future to expend amounts that are material
relative to its total capital structure. However, it is possible that the costs
of compliance with environmental and health and safety laws and regulations will
continue to increase. Given the frequent changes made to environmental and
health and safety regulations and laws, the Company is unable to predict the
ultimate cost of compliance.
19
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 hydrocarbon.
BCF. One billion cubic feet of natural 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 natural gas reserve.
DEVELOPMENT WELL. A well drilled into a proved natural gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
EXPLORATORY WELL. A well drilled to find and produce natural gas or oil
reserves that are not proved, to find a new reservoir in a field previously
found to be productive of natural 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 level.
LEASE BLOCK. Refers to several leases within close proximity of one
another.
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 natural gas.
MCFE. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBTU. One million British Thermal Units.
MMCF. One million cubic feet of natural gas.
MMCFE. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
NET REVENUE INTEREST. A share of a working interest that is not required
to continue to, nor liable for, any portion of the expense of drilling and
completing the well.
NONOPERATING WORKING INTEREST. A working interest, or a fraction of a
working interest, in a tract where the owner does have operating rights.
OVERRIDING ROYALTY. An interest in oil and gas produced at the surface,
free of the expense of production and in addition to the usual royalty reserved
to the lessor in an oil and gas lease.
20
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 and natural gas.
PROVED DEVELOPED RESERVES. Those quantities of oil, natural gas and
condensate that can be expected to be recovered through existing wells with
existing equipment and operating methods.
PROVED RESERVES. The estimated quantities of oil, natural 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 on developed acreage where the subject reserves cannot be
recovered without drilling additional wells.
REVERSIONARY INTEREST. A form of ownership interest in property that
reverts back to the transferor after expiration of an intervening income
interest.
ROYALTY INTEREST. An interest in a natural gas and oil property entitling
the owner to a share of natural gas and oil production free of costs of
production.
UNDIVIDED INTEREST. A form of ownership interest in which more than one
person concurrently owns an interest in the same oil and gas lease or pipeline.
WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production.
ITEM 2. PROPERTIES
Information appearing in Item 1 describing the Company's oil and gas
properties under the caption "Business and Properties" is incorporated herein by
reference.
The Company leases its executive offices in Houston, Texas, under an
operating lease expiring December 31, 2006. The Company also leases under an
operating lease, its division office in New Orleans, Louisiana. The lease has
been extended from April 30, 2000 to April 30, 2002. The Company's aggregate
annual lease payment obligations under these leases are $190,211.
ITEM 3. LEGAL PROCEEDINGS
On May 8, 2000, American Resources, a 75% owned subsidiary of the Company,
and its former Chief Financial Officer, were named in a lawsuit in the United
States District Court for the Southern District of Texas, Houston Division,
styled H&N GAS AND HOWARD ENERGY MARKETING, L.L.C. V. AMERICAN RESOURCES
OFFSHORE, INC. ET AL (Case No H-00-1371). The lawsuit alleges, among other
things, that H&N Gas ("H&N") was defrauded by American Resources in connection
with natural gas purchase options and natural gas price swap contracts entered
into from February 1998 through September 1999. H&N alleges unlawful collusion
between American Resources' prior management and the then president of H&N,
Richard Hale ("Hale"), to the detriment of H&N. H&N generally alleges that Hale
directed H&N to purchase illusory options from American Resources that bore no
relation to any physical gas business and that American Resources did not have
the financial resources and/or sufficient quantity of natural gas to perform.
H&N further alleges that American Resources and Hale colluded with respect to
swap transactions that were designed to benefit American Resources at the
expense of H&N Gas. H&N Gas is seeking approximately $5.65 million in actual
damages, treble damages, punitive damages, prejudgment interest and attorneys'
fees. American Resources intends to vigorously defend this claim.
21
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matter to a vote of security holders during
the quarter ended December 31, 1999.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's common stock trades in the over-the-counter market and is
quoted on the NASDAQ Small Cap Market under the symbol "BDCO". As of November 8,
2000, there were an estimated 325 stockholders of record and the Company
estimates there are more than 1,000 beneficial owners of its common stock.
NASDAQ quotations reflect inter-dealer prices, without adjustment for retail
mark-ups, markdowns or commissions and may not represent actual transactions.
The following table sets forth, for the periods indicated, the high and low
sales price for the common stock as reported on NASDAQ.
SALES
-----------------
HIGH LOW
------ ------
Quarter Ended March 31, 1998 ................. $ 4.50 $ 2.75
Quarter Ended June 30, 1998 .................. $ 3.69 $ 3.13
Quarter Ended September 30, 1998 ............. $ 3.56 $ 2.44
Quarter Ended December 31, 1998 .............. $ 3.50 $ 2.63
Quarter Ended March 31, 1999 ................. $ 4.69 $ 3.13
Quarter Ended June 30, 1999 .................. $ 6.00 $ 4.00
Quarter Ended September 30, 1999 ............. $ 6.88 $ 5.00
Quarter Ended December 31, 1999 .............. $ 7.94 $ 5.75
The Company currently intends to retain earnings for its capital needs and
expansion of its business and does not anticipate paying cash dividends on the
common stock in the foreseeable future. Previously, the Company was restricted,
pursuant to its loan agreement from paying dividends on the common stock if
there was an outstanding balance under the loan agreement. Future policy with
respect to dividends will be determined by the Board of Directors based upon the
Company's earnings and financial condition, capital requirements and other
considerations. The Company is a holding company that conducts substantially all
of its operations through its subsidiaries. As a result, the Company's ability
to pay dividends on the common stock is dependent on the cash flow of its
subsidiaries. The Company has not declared or paid any dividends on the common
stock since its incorporation.
RECENT SALES OF UNREGISTERED SECURITIES. During the year ended December 31,
1999, Directors, Officers and other employees exercised options to purchase
32,004 shares of common stock. The sale of shares was privately made to
Directors, Officers and other employees pursuant to the Company's 1985 and 1996
Stock Option Plans, at exercise prices between $2.7885 and $4.383 per share. The
Company relied on an exemption under Section 4(2) of the Securities Act of 1933
in effecting these transactions.
In June 1999, the Company received $1,960,000 through a private placement
of 392,000 shares of its' common stock at $5.00 per share. The proceeds were
used to replenish working capital.
In order to provide funding for the acquisition of American Resources in
December 1999, the Company arranged a private placement and conversion of
principal and accrued interest on promissory notes into common stock, $.01 par
value per share, of 701,820 shares and 314,898 shares, respectively. The shares
were issued at a price of $6.00 per share. Consideration for the common stock
sold consisted of approximately $4,210,919 cash and the surrender of
approximately $1,811,555
22
of the Company's promissory notes due December 31, 2000, along with accrued
interest of $77,835 through December 1, 1999.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data of the Company and its consolidated
subsidiaries is presented for the five fiscal years ended December 31, 1999.
Such information should be read with Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Consolidated
Financial Statements of the Company and the related Notes included elsewhere in
this report.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------
1999 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
Operating Revenues ......... $ 2,757,056 $ 3,558,773 $ 4,982,606 $ 4,128,568 $ 5,123,053
Income (loss) from
Continuing operations ...... $ (2,086,511) $ (9,059,979)(4) $ 983,095 $ 92,302 $ 7,355,686(2)
Income (loss) from
Continuing operations
per Common Share (1) (3) . $ (0.43) $ (2.02) $ .22 $ (.06) $ 3.04
Weighted average number of
Common Shares (3) ........ 4,837,504 4,492,344 4,462,072 3,107,026 2,323,433
Income (loss) from continuing
Operations per diluted
Common Share(1)(3) ....... $ (0.43) $ (2.02) $ .22 $ (.06) $ 1.77
Weighted average number of
Common Shares and dilutive
Potential Common Shares
Outstanding (3) .......... 4,837,504 4,492,344 4,531,208 3,107,026 4,139,037
Net Income (loss) .......... $ (2,086,511)(5) $ (9,059,979)(4) $ 983,095 $ 92,302 $ 7,355,686 (2)
Working Capital ............ $ 93,231 $ 310,543 $ 1,856,333 $ 917,113 $ 1,207,640
Total Assets ............... $ 21,538,216 $ 14,867,216 $ 24,644,387 $ 23,428,426 $ 23,278,615
Long-term debt ............. -- $ 2,060,600 $ 2,060,600 $ 2,060,600 $ 10,000
(1) Income from continuing operations per Common Share and dilutive Common
Share in 1999, 1998, 1997, 1996 and 1995 is based on the weighted average
number of Common Shares outstanding.
(2) Includes the gain on the sale of a one-third interest in the Blue Dolphin
Pipeline System effective August 1, 1995.
(3) The weighted average number of Common Shares and potential Common Shares
outstanding for the years ended December 31, 1996 and 1995, have been
restated to reflect the one-for-fifteen reverse stock split effected on
December 8, 1997.
(4) Includes a non-cash impairment of oil and gas properties effective December
31, 1998.
(5) Includes the gain on the sale of a one-sixth interest in the Blue Dolphin
Pipeline System effective March 1, 1999, and a non-cash valuation allowance
of its deferred tax assets.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
23
The following is a review of certain aspects of the financial condition and
results of operations of the Company and should be read in conjunction with the
Consolidated Financial Statements included in Item 8 and incorporated herein by
reference, and Item 1. Business and Properties.
FINANCIAL CONDITION: LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes our financial position at December 31, 1999
and 1998 (amounts in thousands):
DECEMBER 31, 1999 DECEMBER 31, 1998
----------------- -----------------
AMOUNT % AMOUNT %
------ ------ ------ ------
Working Capital .................... 93 -- 311 2
Property and equipment, net ........ 15,195 82 8,627 63
Other noncurrent assets ............ 3,316 18 4,718 35
------ ------ ------ ------
Total .............................. 18,604 100 13,656 100
====== ====== ====== ======
Long-term debt ..................... -- -- 2,061 15
Minority Interest .................. 958 5 -- --
Shareholders' equity ............... 17,646 95 11,595 85
------ ------ ------ ------
Total .............................. 18,604 100 13,656 100
====== ====== ====== ======
The significant changes in our financial position from December 31, 1998 to
December 31, 1999 are the increase in property and equipment of $7.2 million and
the increase in stockholders' equity of $6.1 million. The increase in property
and equipment was due to the acquisition of the Black Marlin Pipeline Company
and American Resources. The increase in stockholders' equity was due to private
placements of common stock, offset in part by the Company's 1999 net loss of
$2.1 million.
Historically, the Company has primarily relied on the proceeds from
financing activities to supplement its capital requirements. In 1999, the
Company financed its activities through a combination of private equity and debt
financing and sale of assets. The Company's future cash flows are subject to a
number of variables, including the level of production, utilization of its
pipeline systems, utilization of the Company's services by third parties and
commodity prices among others. The Company believes that it will have sufficient
cash flow from operations and private equity or debt financing activities to
meet its obligations and operating needs for the current year. However, the
Company cannot be assured that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of capital
expenditures. The net cash provided by or used in our operating, investing and
financing activities is summarized below (amounts in thousands):
YEARS ENDING DECEMBER 31
--------------------------------
1999 1998 1997
------ ------ ------
Net cash provided by (used in):
Operating activities ............. (1,087) 397 1,435
Investing activities ............. (5,458) (1,791) (926)
Financing activities ............. 7,118 231 40
------ ------ ------
Net increase (decrease) in cash ......... 573 (1,163) 549
====== ====== ======
The Company's cash flows from operating activities decreased $1.5 million
in 1999 from 1998, due primarily to a decline in oil and gas volumes transported
by the Blue Dolphin System. Cash flow from operating activities decreased by
$1.0 million in 1998 from 1997, also due primarily to a decline in oil and gas
volumes transported by the Blue Dolphin System. The Blue Dolphin System is
dependent upon drilling and development activity in its vicinity which have been
very limited during 1998 and 1999.
24
Cash flow used in investing activities in 1999 primarily included capital
expenditures for the 50% ownership interest in the Black Marlin Pipeline of $2.7
million and the 75% ownership interest in American Resources of $4.5 million
(see Note 12 in Item 8. Financial Statements). Cash flow used in investing
activities in 1998 included the unreimbursed costs of the oil and gas prospect
generation program of $.7 million and development costs of Petroport of $.8
million. Cash flow used in investing activities in 1997 primarily included
plugging and abandonment costs of a well in the Buccaneer Field of $.6 million
and funds escrowed for future abandonment costs of $400,000.
Cash flow provided by financing activities in 1999 consisted of net
proceeds from a private placement of common stock of $6.2 million and debt of
$1.0 million. The Company expects to continue to seek external financing to meet
its liquidity requirements. Cash flow provided by funding activities in 1998 and
1997 were minimal.
The Company issued three convertible promissory notes in 2000 totaling $1.0
million; two in the principal amount of $200,000 each on May 25, 2000 and July
6, 2000, issued to Ivar Siem, Chairman of the Company, and one in the principal
amount of $0.6 million on November 30, 2000, issued to TI A/S, beneficially
controlled by Ivar Siem. These convertible promissory notes are due March 31,
2001, bear interest at the rate of 10% per annum and are convertible into common
stock at the rate of $6.00 per share.
The Company entered into an agreement with Fidelity Oil to manage their
interest in the properties acquired from American Resources for $40,000 per
month. This amount is intended to reimburse the Company for its cost of services
provided. As of December 31, 2000 the Company has received $480,000 in
management fees pursuant to this agreement. The agreement expires in December
2000 and provides for continuation thereafter on a year to year basis unless
terminated by either party or extended by Fidelity Oil. Fidelity Oil has
notified the Company that it is electing to continue the agreement on a month to
month basis, and has indicated that it may terminate this agreement at January
31, 2001. The Company is presently discussing extending this agreement beyond
January 31, 2001 with Fidelity Oil, however there can be no assurance that the
Company will be able to reach an agreement with Fidelity Oil for the extension
of this agreement beyond January 31, 2001.
In order to provide funding for the acquisition of American Resources in
December 1999, the Company arranged a private placement of 701,820 shares of
common stock and conversion of principal and accrued interest on promissory
notes into 314,898 shares of common stock. Two members and one former member of
the board of directors participated in this private placement. Daniel B. Porter,
a former director of the Company, (i) paid $100,000 for 16,667 shares of common
stock and (ii) paid $325 and tendered a note and accrued interest totaling
$99,875 for an additional 16,700 shares. Additionally, Harris A. Kaffie, a
director of the company, paid $149 and tendered a note and accrued interest
totaling $187,651 for 31,300 shares of common stock and Ivar Siem, Chairman of
the Board of Directors, paid $281 and tendered a note and accrued interest
totaling $27,919 for 4,700 shares. (See Notes 5 and 7 in Item 8, Financial
Statements and Supplementary Data). The Company also issued a $1.0 million
convertible promissory note to Harris A. Kaffie, a director of the Company. The
note originally due June 1, 2000, has been extended to March 31, 2001, bears
interest at 10% per annum and can be converted into common stock at $6.00 per
share. The Company believes that if the $1.0 million convertible promissory note
is not converted, the amount due will be refinanced.
In June 1999, the Company received $1.96 million through a private
placement of 392,000 shares of its common stock, $.01 par value per share, at
$5.00 per share. The proceeds were used to replenish working capital.
25
The Company maintained a $10.0 million reducing revolving credit facility
with Bank One, Texas, N.A. (the "Loan Agreement") that expired on December 31,
2000. The facility was available for the acquisition of oil and gas reserve
based assets and working capital. The maximum amount the Company was able to
borrow under the Loan Agreement was $6.5 million. In January 2000, the Company
paid the $80,000 outstanding balance under the Loan Agreement and its borrowing
capacity under the Loan Agreement was adjusted to $0. At December 31, 2000 the
Company did not have an outstanding balance under the Loan Agreement.
The bank redetermined the borrowing base semi-annually based on its
valuation of the Company's oil and gas properties and pipeline contracts.
Accordingly, the bank could increase the borrowing base under the Loan Agreement
to $10.0 million, the maximum amount the Company could borrow under the Loan
Agreement, or some lesser amount based upon the bank's valuation of these
assets. The Loan Agreement included certain restrictive covenants that are
applicable if any amounts were outstanding under the agreement, including
restrictions on the Company's ability to pay dividends on its capital stock and
the maintenance of certain financial ratios. Certain of the various financial
covenants the Company was required to comply with, included maintaining (i) a
total tangible net worth of $10.25 million, (ii) a debt coverage ratio of not
less than 1.2 to 1 calculated on a rolling four-quarter basis and (iii) a
current ratio (as defined in the Loan Agreement) of at least 1 to 1.
In July 2000, the Company executed an agreement to provide transportation
services for Vastar Resources in High Island Block A-5 offshore Texas in the
Gulf of Mexico. To accommodate this production, the Company agreed to construct
a 3.4 mile 12" diameter pipeline from the production platform in High Island A-5
to the Black Marlin Pipeline. The cost to construct the pipeline was $2.0
million, $1.0 million net to the Company's 50% interest in the pipeline. The
pipeline was completed in September 2000. Full operations are expected to
commence in February 2001. The Company financed this pipeline with the
convertible promissory notes issued in 2000.
In July 2000, production from the only producing well in the Buccaneer
Field, the A-12 well, ceased due to down-hole mechanical problems. The Company
retained an outside consultant to advise it concerning the best method to
restore production from the well. Among the various alternatives being
considered were: drilling a new vertical well; sidetracking; conducting a
workover; drilling a new horizontal well; and sidetracking the A-12 well
horizontally. The consultant concluded that the drilling of a new well,
estimated to cost $2.8 million, was the best technical solution to restoring
production because of the age and condition of the A-12 well bore. Based on his
opinion that the most likely rate that the new well could be expected to produce
at was 1,000 Mcf per day and that a positive discounted cash flow from the well
could not be achieved unless a daily production rate of 1,500 Mcf per day or
more was experienced, the consultant recommended that the Company should not
drill the new well. Furthermore, the consultant advised the Company that he did
not feel that the possible returns from the new well justified the risks
involved and recommended the abandonment of the Buccaneer Field. Based on this
recommendation the Company chose not to attempt to restore production to the
A-12 well or redrill.
In early October 2000, as a result of a routine inspection by the MMS of
the two major platform complexes in the field, the MMS dictated that certain
repairs to the platforms must be made before the Company could resume operating
activities in the Buccaneer Field. The Company estimates the cost of these
required, unplanned repairs to be in excess of $1.0 million. The Company
estimates that if it had chosen to pursue restoration of production in the field
the actual infrastructure cost to do so would have been $2.6 million, including
an estimated $.6 million to repair one of the platform complexes. Thus, the cost
to reestablish production would have increased to an estimated $5.4 million,
consisting of $2.6 million in front-end infrastructure costs and $2.8 million in
drilling costs. Instead of making this expenditure and thereafter continue to
incur ongoing operating costs, the Company elected to abandon the Buccaneer
Field.
26
The Company reached an agreement, with Tetra Applied Technologies, Inc.
("Tetra") to plug and abandon the wells and remove its facilities located in the
Buccaneer Field. Tetra will plug and abandon the remaining ten wells in the
Buccaneer Field and remove the platforms and attached quarters platforms in
Galveston Area Blocks 288 and 296. In addition, Maritech Resources, Inc.
("Maritech") an affiliate of Tetra has purchased an adjacent lease on which the
Company provided operation services to Apache Corporation. In December 2000, as
a result of the Company's plans to abandon the Buccaneer Field platform
facilities, the Company and Maritech terminated the operating agreement. A new
platform will be installed to operate and maintain the Blue Dolphin System, as
well as handle the production from Maritech's lease. The Blue Dolphin System is
currently attached to and operated from the Buccaneer Field platforms. The
Company believes that the installation of the new platform is the best
alternative to continue to operate and maintain the Blue Dolphin System. The
platform is expected to be installed by the end of the first quarter of 2001, at
an estimated cost of $1.5 million net to the Company's interest in the Blue
Dolphin System. Plugging and abandonment of the Buccaneer Field wells is
expected to begin in the first quarter of 2001. It is estimated that the
plugging and abandonment costs will be $1.0 million. The removal of the
Buccaneer Field platform facilities is expected to begin in the second half of
2001, at an estimated cost of $4.3 million.
The Company will partially finance the well plugging and abandonment and
the removal of the Buccaneer Field platform facilities totaling $5.3 million, by
using its sinking fund for abandonment obligations of approximately $1.49
million. The Company expects to finance the remaining expenses, and install a
new Blue Dolphin System platform through the sale of assets and/or the private
placement of debt or equity securities.
In July 2000, the Company acquired an 83.3% ownership interest in an
8-inch, 12.78-mile pipeline from Walter Oil and Gas Corp. for approximately
$224,077. The pipeline extends from Galveston Area Block 350 to an interconnect
to another pipeline in Galveston Area Block 391, approximately 14 miles south of
the Company's Blue Dolphin Pipeline. The pipeline currently transports nominal
volumes of gas, but the Company believes it is well positioned to attract future
discoveries in the area.
In June 1999, the Company removed an inactive satellite platform in the
Buccaneer Field at a cost of approximately $345,000. The Company's annual
abandonment escrow fund payment of $250,000 that was due in June 1999 was waived
pursuant to a verbal agreement with the MMS as a result of the removal of the
inactive satellite platform.
The reserves and future net revenues presented in Item 1 "Business - Oil
and Gas Exploration and Production Activities," reflect capital expenditures
totaling $1,416,323, $570,139, $404,430, $178,350 and $43,300 in the years
ending December 31, 2000, 2001, 2002, 2003 and 2004, respectively. Management
will continue to evaluate its capital expenditure program based on, among other
things, field reservoir performance, availability and cost of drilling and
workover equipment, and demand and prices obtainable for the Company's
production, as well as availability of capital resources. There can be no
assurance that reserves will be developed as currently planned.
In 1999 the Company placed a 50% interest in the prospect generation
program, whereby in exchange for certain participation rights, the participant
funds $100,000 per month for the costs associated with the program. Program
costs will be reimbursed to the Company as prospects are developed and leases
acquired. A portion of the reimbursed costs will be paid to the Company's
existing program participant based on the level of interest it retains in each
prospect. During 1999, the Company sold one prospect and retained a reversionary
interest in the prospect. The available interests in the prospect inventory are
for sale on an individual prospect basis. A well is currently being drilled on a
prospect the Company previously sold in which it has retained a reversionary
interest. The Company had previously entered into a multi-year 3-D seismic data
acquisition and licensing agreement, whereby a minimum of $1.5 million was
committed over a 5 year period that ended
27
July 31, 1999 to acquire 3-D seismic data. The final commitment under the
agreement, $450,000, was paid in July 1999.
In April 2000, the Company amended its prospect generation program
agreement with Fidelity Oil, whereby in exchange for certain participation
rights of up to 100%, Fidelity Oil will fund $1.06 million of the costs
associated with the program during 2000. Fidelity Oil will also reimburse the
Company for seismic data acquired. The available interest in the prospect
inventory developed in the program are for sale on an individual prospect basis.
Fidelity Oil withdrew from the prospect generation program December 31, 2000. If
funding from another company is not arranged, the Company may terminate its
prospect generation program.
In November 1999, the Company and WBI Holdings formed New Avoca , 25% owned
and managed by the Company and 75% owned by WBI Holdings, and acquired the Avoca
gas storage assets for $400,000 ($100,000 net to the Company's interest) from
Northeastern. Additionally, a contingent payment of $0.5 million ($125,000 net
to the Company's interest) was due to Northeastern on May 22, 2000. New Avoca
made a payment of $50,000 and extended the remaining $450,000 payment to August
22, 2000. In August 2000, Northeastern extended the contingent payment until
October 2000 in exchange for increasing the contingent payment by $10,000 to
$460,000. The contingent payment would be excused, and the $40,000 net payment
made would be refunded, if Northeastern successfully settles a claim associated
with Avoca Gas Storage, Inc. (the original owner of the Avoca gas storage
assets). In October 2000, Northeastern received a payment on its claim and
refunded the $40,000 previously paid by New Avoca. New Avoca can elect to
liquidate the project at any time.
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. In October 2000, New Avoca
commenced testing of the disposal wells to determine the rate that these wells
will accept brine. Based on the results of the tests, New Avoca expects to make
a decision to either proceed with or liquidate the project. If liquidated, the
Company believes that it can recover its investment in this project. If the
decision is made to proceed with the project, New Avoca estimates that it will
take between one and one-half to two years to begin operations at partial
capacity, and three to four years for the facility to operate at full capacity.
However, until the Company has reviewed and analyzed the results from the tests
of the disposal wells it will be unable to establish a definitive schedule or
accurately estimate the costs to complete this project.
Although the Loan Agreement expired in December 2000 and prior to its
expiration the borrowing base under the Loan Agreement was $0, the Company
believes that it has, or can obtain, adequate capital to continue to meet its
anticipated capital requirements. In the past, the Company's capital
requirements have been financed by the disposition of certain assets, for
example interests in its pipelines, by borrowings under the Loan Agreement,
private placements of its equity and debt securities and investments by its
directors. However, there can be no assurance that the Company will be able to
continue to obtain financing from these sources or sell assets on commercially
reasonable terms. The Company's inability to finance its capital requirements
may adversely affect its results of operations, timing for major pipeline
expansions, growth in oil and gas prospect generation activities, developmental
midstream projects and other projects.
RESULTS OF OPERATIONS
For the year ended December 31, 1999 ("1999"), the Company reported a net
loss of $2,086,511, compared to net loss of $9,059,979 reported for the year
ended December 31, 1998 ("1998"), representing an improvement of $6,973,468. The
improvement is primarily due to a non-cash impairment of oil and gas properties
recorded at December 31, 1998 of $8,952,785, net of
28
income tax benefit, offset in part by a non-cash valuation allowance on its
deferred tax assets of $1,858,608 recorded at December 31, 1999.
For the year ended December 31, 1998 ("1998"), the Company reported a net
loss of $9,059,979, compared to net income of $983,095 reported for the year
ended December 31, 1997 ("1997"), representing a decrease of $10,043,074. The
decrease is primarily due to the non-cash impairment of oil and gas properties
recorded at December 31, 1998 of $8,952,785, net of income tax benefit.
1999 COMPARED TO 1998
REVENUE FROM PIPELINE OPERATIONS. Pipeline system revenues decreased by
$913,228 or 33% in 1999 to $1,875,716 from 1998. The decrease was due to a
decline in gas and oil volumes transported by the Blue Dolphin System of
approximately $1,424,749, and the sale of a one-sixth interest in the Blue
Dolphin System in March 1999, eliminating revenues of $189,623, offset in part
by the acquisition of the Black Marlin System, providing revenues of $701,144.
REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Oil and gas sales and
operating fees increased by $111,511 or 15% in 1999 to $881,340 from 1998. The
acquisition of American Resources in December 1999 provided revenues of
$307,195, partially offset by a reduction in Buccaneer Field revenues of
$195,684 or 25%. Although commodity prices in general increased during 1999, gas
sales from the Buccaneer Field were based on a fixed price of $2.08 per MMBtu
through September 1999. Since October 1999, the price received for Buccaneer
Field gas production has been based on the current monthly market price.
PIPELINE OPERATING EXPENSES. Pipeline operating expenses increased $218,946
or 25% to $1,102,998 from 1998. The increase was due to the acquisition of the
Black Marlin System in March 1999, with expenses of $393,696 in 1999, offset in
part by the sale of a one-sixth interest in the Blue Dolphin System in March
1999, eliminating expenses of $108,205, and cost reductions from continuing
operations of $66,545.
LEASE OPERATING EXPENSES. Lease operating expenses increased by $254,450 or
30% in 1999 to $1,100,549 from 1998. The increase was due primarily to costs of
approximately $187,738 associated with repairs made to the offshore platforms in
the Buccaneer Field in 1999 and approximately $66,712 associated with the
American Resources properties that were acquired in December 1999.
DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A"). DD&A expense increased
by $194,304 or 48% in 1999 to $595,286 from 1998. The increase was due to the
acquisition of the Black Marlin System in March 1999, resulting in depreciation
of approximately $199,017, and American Resources in December 1999, resulting in
depletion of approximately $124,562. These increases were partially offset by a
reduction in depletion due to lower production volumes from the Buccaneer Field
of approximately $92,475, and the sale of a one-sixth interest in the Blue
Dolphin System in March 1999, resulting in a $36,800 reduction in depreciation.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
increased $595,067 or 41% to $2,061,805 from 1998. The increase was primarily
due to increased personnel costs associated with the Company's asset
acquisitions during 1999. The Company expects to maintain this higher level of
general and administrative expenses.
GAIN ON SALE OF ASSETS. In March 1999, the Company reported a gain on the
sale of a one-sixth interest in the Blue Dolphin System of approximately
$2,052,920.
29
INCOME TAX EXPENSE. In 1999 the Company recorded a valuation allowance of
its deferred tax assets in accordance with SFAS No. 109 Accounting for Income
Taxes, whereby the deferred tax asset of $2,103,052 was reduced to $244,444,
resulting in an increase in income tax expense of $1,858,608.
1998 COMPARED TO 1997
REVENUE FROM PIPELINE OPERATIONS. Pipeline system revenues decreased by
$1,373,649 or 33% in 1998 to $2,788,944 from 1997. The decrease was due to a
decrease in oil transportation revenues of $1,120,457, primarily due to the loss
of a producer/shipper in October 1997.
REVENUE FROM OIL AND GAS SALES AND OPERATING FEES. Revenues from oil and
gas sales and operating fees for 1998 decreased $50,184 or 6% to $769,829 from
1997. The reduction in oil and gas sales is attributable to normal production
declines from the Buccaneer Field.
INTEREST AND OTHER INCOME. Other income for 1998 decreased $157,432 or 40%
to $105,994 from 1997. The reduction in other income is due to a refund of prior
years franchise taxes of $152,370 received in 1997.
LEASE OPERATING EXPENSES. Lease operating expenses for 1998 decreased by
$29,472 to $846,099 from 1997 due in part to repairs and modifications to the
Buccaneer Field production platforms and facilities of approximately $68,000
incurred in 1997.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expense
increased by $108,967 or 8% in 1998 from 1997 principally due to an increase in
personnel costs and consulting fees of approximately $95,472, associated with
potential asset acquisitions.
IMPAIRMENT OF OIL AND GAS PROPERTIES. Under the full cost accounting rules,
the Company reviews the carrying value of its proved oil and gas properties
quarterly. Under these rules capitalized costs of proved oil and gas properties,
net of accumulated depreciation, depletion and amortization may not exceed the
present value of estimated future net cash flows from proved oil and gas
reserves, discounted at 10 percent, plus the lower of cost or fair value of
unproved properties included in the costs being amortized, net of related tax
effects. These rules generally require pricing future oil and gas production at
the unescalated oil and gas prices in effect at the end of the period and
require a write-down if the "ceiling" is exceeded. At December 31, 1998, the
Company recorded a non-cash impairment charge of $12,011,544, reflecting the
write down of its oil and gas properties and certain exploration activity costs.
The non-cash impairment of oil and gas properties resulted from a 15% decrease
in the price of gas and a 35% decrease in the price of oil used to value the
Company's reserves from the prior period, as well as changes to the Company's
development plans, whereby development of the Buccaneer Field reserves have been
delayed.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Statement of Financial Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS No. 133"), was issued by the Financial
Accounting Standards Board in June 1998. SFAS No. 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts. In July 1999, SFAS NO. 137, "Deferral of the
Effective Date of SFAS No. 133," was issued and delays the effective date for
one year, to fiscal years beginning after June 15, 2000. The Company is
evaluating the impact of the provisions of SFAS No. 133.
In April 1998, the Accounting Standards Executive Committee of the American
Institute of Certified Public Accountants issued Statement of Position 98-5,
Reporting on the Costs of Start-Up Activities ("SOP 98-5"). SOP 98-5 requires
that costs of start-up activities be charged to expense as
30
incurred and broadly defines such costs. The Company has capitalized certain
costs incurred in connection with a new business segment, and SOP 98-5 requires
that such costs be charged to results of operations upon its adoption. The
Company adopted the requirements of SOP 98-5 as of January 1, 1999 resulting in
a cumulative effect of a change in an accounting principle of $80,334, net of
income tax benefit of $41,480.
YEAR 2000 ISSUE
The Company's computer software was made Year 2000 compliant prior to the
end of 1999; and, therefore, the business, results of operations and financial
condition of the Company were not affected by the millennium change.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk, including adverse changes in
commodity prices and interest rates as discussed below.
COMMODITY PRICE RISK- The Company produces and sells natural gas, crude
oil, and natural gas liquids. As a result, the Company's financial results can
be significantly affected if these commodity prices fluctuate widely in response
to changing market forces. Except as discussed below, the Company has not used
derivative products in the past to manage commodity price risk.
INTEREST RATE RISK: The Company's exposure to changes in interest rates
primarily results from its short-term and long-term debt with floating interest
rates. Since the Company does not have an outstanding balance under the Loan
Agreement a 10% change in the interest rate on the credit facility would not
effect interest expense.
DERIVATIVES: In October 1999, American Resources sold call options for 5
MMBtu's per day of gas at a call price of $3.25 per MMBtu to H & N Gas. The call
options expire in September 2000. In exchange for establishing a ceiling of
$3.25 per MMBtu over the option term, American Resources received an average
option premium of approximately $0.12 per MMBtu on the volumes contracted for
under the call option agreement. Fidelity Oil agreed to assume 80%, or 4 MMBtu's
per day, of any liability from these options. The call options are settled each
month. The months of October 1999 through May 2000 expired with no liability to
American Resources. The liability from the June 2000 option was $147,900, of
which Fidelity Oil reimbursed American Resources $118,320. For the months of
July and August 2000, the settlement amounts were $222,580 and $79,515,
respectively, of which Fidelity Oil has reimbursed American Resources $178,064
and $63,612, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements: PAGE
----
Independent Auditors' Report.................................. 32
Consolidated Balance Sheets, at December 31, 1999 and 1998.... 34
Consolidated Statements of Operations, for the years
ended December 31, 1999, 1998, and 1997.................. 36
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1999, 1998, and 1997............ 37
Consolidated Statements of Cash Flows, for the years
ended December 31, 1999, 1998, and 1997.................. 38
Notes to Consolidated Financial Statements.................... 40
31
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Blue Dolphin Energy Company:
We have audited the accompanying consolidated balance sheets of Blue Dolphin
Energy Company and subsidiaries as of December 31, 1999 and 1998, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the years in the three-year period ended December 31, 1999.
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 did not audit the consolidated
financial statements of American Resources Offshore, Inc., a 75 percent owned
subsidiary, which statements reflect total assets constituting 6 percent and
total revenues constituting 11 percent in 1999 of the related consolidated
totals. Those statements were audited by other auditors whose report has been
furnished to us, and our opinion, insofar as it relates to the amounts included
for American Resources Offshore, Inc., is based solely on the report of the
other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the
consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Blue Dolphin Energy Company and
subsidiaries as of December 31, 1999 and 1998, and the results of its their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1999 in conformity with generally accepted accounting
principles.
/s/ KPMG LLP
Houston, Texas
March 28, 2000
32
Independent Auditors' Report
The Board of Directors and Shareholders
American Resources Offshore, Inc.
We have audited the accompanying consolidated balance sheets of American
Resources Offshore, Inc. as of December 31, 1999 and 1998, and the related
consolidated statements of operations, stockholders' equity and cash flows for
the years then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion of 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 audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of American Resources
Offshore, Inc. as of December 31, 1999 and 1998, and the results of its
operations and its cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States.
/s/ Ernst & Young LLP
New Orleans, Louisiana
March 10, 2000
33
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 1999 and 1998
ASSETS 1999 1998
----------- -----------
Current assets:
Cash and cash equivalents .................... $ 1,166,730 593,509
Trade accounts receivable .................... 1,542,328 771,268
Prepaid expenses and other assets ............ 318,139 157,588
----------- -----------
Total current assets .................. 3,027,197 1,522,365
----------- -----------
Property and equipment, at cost:
Oil and gas properties, including $950,813
and $227,286 of unproved leasehold cost at
December 31, 1999 and 1998, respectively
(full-cost method) ........................... 26,474,957 21,210,806
Onshore separation and handling facilities ... 1,583,610 2,106,189
Land ......................................... 930,500 1,133,333
Pipelines .................................... 3,653,397 1,320,063
Other property and equipment ................. 431,294 343,220
----------- -----------
33,073,758 26,113,611
Less accumulated depletion, depreciation,
amortization and impairment ................. 17,879,183 17,486,651
----------- -----------
15,194,575 8,626,960
Deferred federal income tax ...................... 244,444 2,010,060
Acquisition and development costs - Petroport .... 1,741,823 1,576,391
Escrow fund ...................................... 1,168,564 1,107,573
Other assets ..................................... 161,613 23,867
----------- -----------
$21,538,216 14,867,216
=========== ===========
See accompanying notes to consolidated financial statements.
(Continued)
34
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, CONTINUED
December 31, 1999 and 1998
LIABILITIES AND STOCKHOLDERS' EQUITY 1999 1998
------------ ------------
Current liabilities:
Trade accounts payable and accrued expenses ........ $ 1,347,944 892,190
Current portion of long term debt .................. 319,045 200,000
Note payable - related party ....................... 1,000,000 --
Accrued expenses and other liabilities ............. 266,977 119,632
------------ ------------
Total current liabilities ................... 2,933,966 1,211,822
------------ ------------
Long-term debt ......................................... -- 2,060,600
------------ ------------
Total long-term liabilities ................. -- 2,060,600
------------ ------------
Minority interest ...................................... 958,521 --
------------ ------------
Stockholders' equity:
Common stock, $.01 par value, 10,000,000 shares
authorized at December 31, 1999 and 1998, 5,950,879
shares issued and outstanding at December 31,
1999; 4,504,627 shares issued and outstanding
at December 31, 1998 .............................. 59,509 45,046
Additional paid-in capital ......................... 25,823,817 17,700,833
Accumulated (deficit) .............................. (8,237,597) (6,151,085)
------------ ------------
Total stockholders' equity .................. 17,645,729 11,594,794
$ 21,538,216 14,867,216
============ ============
See accompanying notes to consolidated financial statements.
35
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31, 1999, 1998 and 1997
1999 1998 1997
----------- ----------- -----------
Revenue from operations:
Pipeline operations ................................... $ 1,875,716 2,788,944 4,162,593
Oil and gas sales ..................................... 567,103 412,753 415,081
Operating fees ........................................ 314,237 357,076 404,932
----------- ----------- -----------
Revenue from operations ........................ 2,757,056 3,558,773 4,982,606
----------- ----------- -----------
Cost of operations:
Pipeline operating expenses ........................... 1,102,998 884,052 891,157
Lease operating expenses .............................. 1,100,549 846,099 875,571
Impairment of oil and gas properties .................. -- 12,011,544 --
Depletion, depreciation and amortization .............. 595,286 400,982 372,252
General and administrative expenses ................... 2,061,805 1,466,738 1,357,771
----------- ----------- -----------
Cost of operations ............................. 4,860,638 15,609,415 3,496,751
----------- ----------- -----------
Income (loss) from operations .................. (2,103,582) (12,050,642) 1,485,855
Other income (expense):
Interest expense ...................................... (238,322) (215,141) (218,955)
Gain on sale of assets ................................ 2,052,920 -- --
Interest and other income ............................. 80,722 105,994 262,426
----------- ----------- -----------
Income (loss) before income taxes .............. (208,262) (12,159,789) 1,529,326
Minority interest ........................................ (882) -- --
Income tax benefit (expense) ............................. (1,797,033) 3,099,810 (546,231)
----------- ----------- -----------
Income (loss) before cumulative effect of a .... (2,006,177) (9,059,979) 983,095
change in an accounting principle
Change in accounting principal (net of $41,480 income tax) (80,334) -- --
----------- ----------- -----------
Net income (loss) .............................. $(2,086,511) (9,059,979) 983,095
=========== =========== ===========
Earnings per common share-basic
Income before accounting change ...................... $ (0.41) (2.02) 0.22
Cumulative effect of a change in accounting principle (0.02) -- --
----------- ----------- -----------
Net income ........................................... $ (0.43) (2.02) 0.22
=========== =========== ===========
Earnings per common share-diluted
Income before accounting change ...................... $ (0.41) (2.02) 0.22
Cumulative effect of a change in accounting principle (0.02) -- --
----------- ----------- -----------
Net income ........................................... $ (0.43) (2.02) 0.22
=========== =========== ===========
Weighted average number of common shares
outstanding and dilutive potential common shares:
Basic ................................................. 4,837,504 4,492,344 4,462,072
=========== =========== ===========
Diluted ............................................... 4,837,504 4,492,344 4,531,208
=========== =========== ===========
See accompanying notes to consolidated financial statements.
36
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1999, 1998, and 1997
ADDITIONAL TOTAL
COMMON PAID-IN ACCUMULATED STOCKHOLDERS'
STOCK CAPITAL (DEFICIT) EQUITY
-------- ----------- ----------- -------------
Balance at December 31, 1996 ............. $ 44,513 17,630,265 1,925,799 19,600,577
-------- ----------- ----------- -------------
Exercise of 51,340 stock options ..... 513 159,574 -- 160,087
Cancellation of 10,768 shares of stock (108) (110,324) -- (110,432)
Other ................................ -- (10,000) -- (10,000)
Net income ........................... -- -- 983,095 983,095
-------- ----------- ----------- -------------
Balance at December 31, 1997 ............. 44,918 17,669,515 2,908,894 20,623,327
-------- ----------- ----------- -------------
Exercise of 12,780 stock options ..... 128 35,509 -- 35,637
Other ................................ -- (4,191) -- (4,191)
Net loss ............................. -- -- (9,059,979) (9,059,979)
-------- ----------- ----------- -------------
Balance at December 31, 1998 ............. 45,046 17,700,833 (6,151,085) 11,594,794
-------- ----------- ----------- -------------
Exercise of 32,004 stock options ..... 320 115,073 -- 115,393
Cancellation of 14,470 shares of stock (145) (85,010) -- (85,155)
Issuance of shares to 401K plan ..... 200 59,800 -- 60,000
Private placements ................... 10,939 6,159,980 -- 6,170,919
Notes and accrued interest
tendered for stock ............. 3,149 1,886,241 -- 1,889,390
Other ................................ -- (13,100) (1) (13,101)
Net loss ............................. -- -- (2,086,511) (2,086,511)
-------- ----------- ----------- -------------
Balance at December 31, 1999 ............. $ 59,509 25,823,817 (8,237,597) 17,645,729
======== =========== =========== =============
See accompanying notes to consolidated financial statements.
37
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1999, 1998, and 1997
1999 1998 1997
------------ ------------ ------------
Operating activities:
Net income (loss) .................................... $ (2,086,511) (9,059,979) 983,095
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization .......... 595,286 400,982 372,252
Minority interest ................................. 882 -- --
Deferred income taxes ............................. 1,765,616 (3,113,980) 469,965
Change in accounting principle .................... 121,814 -- --
Gain on sale of property and equipment ............ (2,052,920) -- --
Impairment of oil and gas properties .............. -- 12,011,544 --
Changes in operating assets and liabilities:
(Increase) decrease in trade accounts receivable (771,060) 90,472 (117,457)
(Increase) decrease in prepaid
expenses and other assets .................... (298,298) (62,750) 3,962
(Decrease) increase in trade accounts payable,
accrued interest and other liabilities ....... 1,638,583 130,282 (276,754)
------------ ------------ ------------
Net cash provided by (used in)
operating activities ...................... (1,086,608) 396,571 1,435,063
------------ ------------ ------------
Investing activities:
Oil and gas prospect generation costs ................ (1,268,098) (737,868) (500,460)
Reimbursement of oil and gas prospect generation costs 1,292,125
Proceeds from sales of oil and gas prospect leases ... -- -- 1,018,289
Exploration and development costs .................... -- (100,051) --
Purchases of property and equipment .................. (10,290,563) (354,821) (299,551)
Net proceeds from sale of assets ..................... 5,513,423 -- --
Development costs - Petroport ........................ (299,426) (822,086) (185,641)
Reduction of escrowed abandonment fund ............... -- 593,830 --
Abandonment of oil and gas properties ................ (344,698) -- (570,115)
Funds escrowed for abandonment costs ................. (60,991) (369,806) (388,269)
------------ ------------ ------------
Net cash used in
investing activities .................... (5,458,228) (1,790,802) (925,747)
------------ ------------ ------------
See accompanying notes to consolidated financial statements.
38
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1999, 1998, and 1997
1999 1998 1997
------------ ------------ ------------
Financing activities:
Proceeds from borrowings, Bank .......................... 200,000 200,000 --
Proceeds from borrowings, Director ...................... 1,000,000
Payments on borrowings, Bank ............................ (330,000) -- --
Net proceeds from private placement ..................... 6,170,919
Net proceeds from the exercise of stock and stock options 77,138 31,446 39,655
------------ ------------ ------------
Net cash provided by
financing activities ....................... 7,118,057 231,446 39,655
------------ ------------ ------------
Increase (decrease) in cash .................. 573,221 (1,162,785) 548,971
Cash and cash equivalents at beginning of year ................ 593,509 1,756,294 1,207,323
------------ ------------ ------------
Cash and cash equivalents at end of year ...................... $ 1,166,730 593,509 1,756,294
============ ============ ============
Supplementary cash flow information:
Interest paid ........................................... $ 326,819 214,926 113,000
============ ============ ============
Income taxes (received) paid ............................ $ 12,620 (93,264) 70,881
============ ============ ============
NON-CASH TRANSACTIONS:
During 1999, holders of $1,811,555 of notes payable along with accrued interst
of $77,835 converted the notes payable into 314,898 shares of Common Stock.
See accompanying notes to consolidated financial statements.
39
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
(1) ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Blue Dolphin Energy Company (the Company) was incorporated in Delaware in
January 1986 to engage in oil and gas exploration, production and
acquisition activities and oil and gas transportation and marketing. It
was formed pursuant to a reorganization effective June 9, 1986.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of the Company include the accounts
of its wholly-owned subsidiaries and majority owned subsidiary (ARO). All
significant intercompany balances and transactions have been eliminated in
consolidation.
ACCOUNTING ESTIMATES
Management has made a number of estimates and assumptions relating to the
reporting of assets and liabilities and to the disclosure of contingent
assets and liabilities including reserve information which affects the
depletion calculation as well as the computation of the full cost ceiling
limitation to prepare these financial statements in conformity with
generally accepted accounting principles. Actual results could differ from
those estimates.
CASH EQUIVALENTS
Cash equivalents include liquid investments with an original maturity of
three months or less.
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.
Due to the difference in the expected life of the reserves of the
properties, the Company uses two separate cost centers, one for its
Buccaneer Field property and one for its ARO properties. Amortization of
such costs and estimated future development costs is 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
(Continued)
40
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
be assigned to the properties or impairment has occurred. Estimated proved
oil and gas reserves are based upon reports of independent petroleum
engineers (ARO properties) and the Company's in-house reserve engineers
(Buccaneer property). 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.
At December 31, 1998, the Company recorded an impairment charge on oil and
gas properties and certain exploration activity costs of $12,011,544,
thereby adjusting the net carrying value of oil and gas properties to the
cost center ceiling as described above. The impairment resulted from lower
oil and gas prices and changes to the Company's development plans, whereby
development of oil and gas properties have been deferred. Included in oil
and gas properties at December 31, 1999 and 1998 are $145,101 and
$198,486, respectively in expenditures directly associated with generation
of additional oil and gas prospects, net of reimbursements.
The following table reflects the depletion expense incurred from oil and
gas properties during the periods indicated:
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
Depletion expense per Mcf
equivalent produced ............ 0.83 0.77 0.74
======= ======= =======
At December 31, 1999, oil and gas properties included $950,813 of unproved
leasehold costs that are not being amortized. These costs will begin to be
amortized when they are evaluated and proved reserves are discovered,
impairment is indicated or when the lease term expires. Unproved leasehold
costs consist of interests in state and federal leases located in the Gulf
of Mexico with expiration dates ranging from November 2000 to November
2004. 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.
(Continued)
41
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table reflects the periods when costs were incurred for
unproved leasehold costs:
YEAR ENDED DECEMBER 31,
--------------------------------------
Total 1999 1998 1997
-------- -------- -------- --------
Property acquisition costs.. 800,469 800,469 -- --
Exploration costs .......... 150,344 57,632 92,712 --
-------- -------- -------- --------
950,813 858,101 92,712 --
======== ======== ======== ========
The Company capitalizes interest on expenditures made in connection with
significant exploration and production projects that are not subject to
current amortization. Interest is capitalized only for the period that
activities are in progress to bring these projects to their intended use.
No interest has been capitalized for the periods reflected herein.
PIPELINES AND FACILITIES
Pipelines and facilities are recorded at cost. Depreciation is computed
using the straight-line method over estimated useful lives of 10-25 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 DD&A.
The Company in 1995 adopted Statement of Financial Accounting Standards
(SFAS) No. 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR
LONG-LIVED ASSETS TO BE DISPOSED OF, with no impact to the Company's
consolidated financial statements. Assets are grouped and evaluated based
on the ability to identify separate cash flows generated therefrom.
OTHER PROPERTY AND EQUIPMENT
Depreciation of furniture, fixtures and other equipment, including assets
held under capital leases, is computed using the straight-line method over
estimated useful lives of 2-5 years.
(Continued)
42
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ABANDONMENT
A provision for the abandonment, dismantlement and site remediation of
offshore production platforms and existing wells is made using the
unit-of-production method applied to estimates based on current costs. A
provision for pipeline and pipeline facilities abandonment costs is also
provided using the straight-line method over the estimated useful lives of
the pipeline and pipeline facilities. These provisions are included in
accumulated depletion, depreciation, amortization and impairment, and are
undiscounted. The Company previously recorded its provision for
abandonment as a non-current liability. Aggregate abandonment liability is
estimated to be approximately $3,960,000 at December 31, 1999 and 1998.
NEW AVOCA
The Company records its investment in New Avoca using the equity method of
accounting. Under the equity method, investments are recorded at cost plus
the Company's equity in undistributed earnings and losses after
acquisition.
STOCK-BASED COMPENSATION
The Company applies SFAS No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION,
which allows a company to adopt a fair value based method of accounting
for a stock-based employee compensation plan or to continue to use the
intrinsic value based method of accounting prescribed by Accounting
Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES.
The Company has chosen to continue to account for stock-based compensation
under the intrinsic value method and provides the pro forma effects of the
fair value method as required.
RECOGNITION OF CRUDE OIL AND NATURAL GAS REVENUE
Sales from producing wells are recognized on the entitlement method of
accounting which defers recognition of sales when, and to the extent that,
deliveries to customers exceed the Company's net revenue interest in
production. Similarly, when deliveries are below the Company's net revenue
interest in production, sales are recorded to reflect the full net revenue
interest. The Company's imbalance liability at December 31, 1999 and 1998
was not material.
(Continued)
43
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RECOGNITION OF PIPELINE TRANSPORTATION REVENUE
Revenue from the transportation of gas, condensate and crude oil is
recognized on the accrual basis as products are transported.
OPERATION OF OIL AND GAS PROPERTIES
The Company operates, for a monthly fee, oil and gas properties in which
it does not own an interest. Revenues and costs from these activities are
included in operating fees and lease operating expenses, respectively.
Operating fees received related to properties in which the Company owns an
interest are netted against the appropriate operating costs in the
Statement of Operations. Fees received in excess of costs incurred are
reflected as a reduction of the full cost pool.
INCOME TAXES
The Company provides for income taxes using the asset and liability method
pursuant to SFAS No. 109, ACCOUNTING FOR INCOME TAXES (Statement 109).
Under the asset and liability method of Statement 109, deferred tax assets
and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying
amounts of existing assets and liabilities and their respective tax bases
and operating loss and tax credit carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period
that includes the enactment date.
EARNINGS PER SHARE
The Company follows SFAS No. 128 (Statement 128), EARNINGS PER SHARE, for
computing and presenting earnings per share and requires, among other
things, dual presentation of basic and diluted earnings per share on the
face of the statement of operations.
The following table provides a reconciliation between basic and diluted
earnings (loss) per share:
(Continued)
44
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
WEIGHTED
AVERAGE
COMMON SHARES
OUTSTANDING
AND DILUTIVE PER
NET POTENTIAL SHARE
INCOME COMMON SHARES AMOUNT
----------- ------------- -----------
Year ended December 31, 1999
Basic (loss) per share ......... $(2,086,511) 4,837,504 $ (0.43)
----------- ------------- -----------
4,837,504 $ (0.43)
Diluted (loss) per share ....... $(2,086,511)
=========== ============= ===========
Year ended December 31, 1998
Basic (loss) per share ......... $(9,059,979) 4,492,344 $ (2.02)
----------- ------------- -----------
Diluted (loss) per share ....... $(9,059,979) 4,492,344 $ (2.02)
=========== ============= ===========
Year ended December 31, 1997
Basic earnings per share ....... $ 983,095 4,462,072 $ 0.22
Effect of dilutive stock
Options .................... -- 69,136 --
----------- ------------- -----------
Diluted earnings per share ..... $ 983,095 4,531,208 $ 0.22
=========== ============= ===========
(Continued)
45
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted average number of Common Shares and potential Common Shares
outstanding for the year ended December 31, 1997 reflects the
one-for-fifteen reverse stock split effected on December 8, 1997.
The employee stock options at December 31, 1999 and 1998, 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.
The following unaudited pro forma information for the years ended December
31, 1999 and 1998, presents a summary of consolidated results of
operations as if the acquisition of the 75% ownership interest in ARO made
in 1999 had occurred on January 1, 1998 with pro forma adjustments to give
effect to depreciation and certain other adjustments together with related
income tax effects:
YEAR ENDED
DECEMBER 31,
--------------------------
1999 1998
----------- -----------
Revenues ............................. $ 5,726,056 $ 8,995,773
Net Earnings ......................... $(2,257,225) $(7,905,549)
Basic and diluted earnings per share . $ (0.47) $ (1.76)
The above pro forma information is not necessarily indicative of the
results of operations as they would have been had the acquisition been
effected on January 1, 1998.
ENVIRONMENTAL
The Company is subject to extensive Federal, state and local environmental
laws and regulations. These laws, which are constantly changing, regulate
the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed or capitalized depending on their
future economic benefit. Expenditures that relate to an existing
(Continued)
46
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
COSTS OF START-UP ACTIVITIES
In April 1998, the Accounting Standards Executive Committee of the
American Institute of Certified Public Accountants issued Statement of
Position 98-5, Reporting on the Costs of Start-Up Activities ("SOP 98-5").
SOP 98-5 requires that costs of start-up activities be charged to expense
as incurred and broadly defines such costs. The Company deferred certain
costs incurred in connection with a new business segment, and SOP 98-5
requires that such deferred costs be charged to results of operations upon
its adoption. The Company adopted the requirements of SOP 98-5 on January
1, 1999. The cumulative effect of the change in accounting principle for
the adoption of SOP 98-5 resulted in a charge to results of operations in
the financial statements for the year ended December 31, 1999 of $80,334,
net of $41,480 of income taxes.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities (SFAS No. 133), was issued
by the Financial Accounting Standards Board in June 1998. SFAS No. 133
standardizes the accounting for derivative instruments, including certain
derivative instruments embedded in other contracts. In July 1999, SFAS NO.
137, "Deferral of the Effective Date of SFAS NO. 133," was issued and
delays the effective date for one year, to fiscal years beginning after
June 15, 2000. The Company believes that adoption of this financial
accounting standard will not have a material effect on its financial
condition or results of operations.
(2) 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 notes payable approximates fair
value at December 31, 1999 and 1998.
(Continued)
47
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(3) INCOME TAXES
Income tax expense for 1999, 1998 and 1997 consists of:
1999 1998 1997
----------- ----------- -----------
Current:
Federal .......... $ -- -- 25,466
State ............ -- 14,170 50,800
Deferred - Federal ... 1,797,033 (3,113,980) 469,965
----------- ----------- -----------
$ 1,797,033 (3,099,810) 546,231
=========== =========== ===========
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, 1999 and 1998 are presented below.
1999 1998
------------ ------------
Deferred tax assets:
Accrued abandonment costs ............ $ 136,354 $ 84,541
Net operating loss carryforwards .......... 9,800,517 2,685,789
Alternative minimum tax credit ....... 244,444 244,444
Basis differences in property and
equipment ....................... 1,425,746 29,295
------------ ------------
Total gross deferred tax assets ... 11,607,061 3,044,069
Deferred tax liabilities:
State tax ....................... (34,009) (34,009)
------------ ------------
Total gross deferred tax liability (34,009) (34,009)
------------ ------------
Net deferred tax asset (liability) 11,573,052 3,010,060
Less valuation allowance ......... (11,328,608) (1,000,000)
------------ ------------
Deferred tax asset (liability) ... $ 244,444 $ 2,010,060
============ ============
In 1999, the Company acquired ARO, 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 has been
recorded to reduce the corresponding deferred assets, since it is more
likely than not that they will not be
(Continued)
48
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
realized, due to the limitation of the use of the net operating loss
carryforwards resulting from the ownership change in December 1999.
In assessing the realizability of deferred tax assets, the Company applies
SFAS No. 109 to determine whether it is more likely than not that some
portion or all of the deferred tax assets will not be realized. As a
result, the Company recorded a valuation allowance at December 31, 1999 to
reduce the deferred tax asset to $244,444.
The Company's effective tax rate applicable to continuing operations in
1999, 1998 and 1997 differs from the expected tax rate of 34% due to the
following:
1999 1998 1997
------ ------ ------
Expected tax rate ........................ (34%) (34%) 34%
State taxes, net of federal benefit ...... -- -- 1%
Expenses not deductible for tax purposes . 2% -- 1%
Increase in valuation allowance recognized
in earnings .......................... 893% 8% --
------ ------ ------
Other .................................... 2% -- --
------ ------ ------
863% (26%) 36%
====== ====== ======
For federal tax purposes, the company had a net operating loss
carryforward ("NOL") of approximately $28.8 million and $7.9 million for
the years ended December 31, 1999 and 1998. These NOLs must be utilized
prior to their expiration, which is between 2000 and 2018. Of the $28.8
million of NOLs for the year ended December 31, 1999, $21.0 million
relates to ARO.
The Company has an alternative minimum tax credit carry forward of
$244,444 that does not expire and may be applied to reduce regular tax to
an amount not less than the alternative minimum tax payable in any one
year.
(4) LONG-TERM DEBT
The Company maintains a reducing revolving credit facility (Loan
Agreement) with Bank One, Texas, N.A. (Bank One), in an amount of
$10,000,000. At December 31, 1999, the borrowing base under the Loan
Agreement was $80,000 and reduced to $0
(Continued)
49
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
in January 2000. The Company paid off the $80,000 balance of the credit
facility in January 2000. The borrowing base is redetermined
semi-annually. On the first day of each month interest is due and payable
on the outstanding loan balance at the rate of 1.25% above Bank One's
prime rate of interest. Borrowings under the Loan Agreement are secured by
first liens on the Buccaneer Field, the Blue Dolphin Pipeline, the
Buccaneer Pipeline, the Freeport, Texas acreage, the Shore Facilities and
the Black Marlin Pipeline. The maturity date under the Loan Agreement is
December 31, 2000.
The Loan Agreement includes certain restrictive covenants, including a
restriction of the payment of dividends on capital stock and the
maintenance of certain financial coverage ratios. The Company was in
compliance with these covenants at December 31, 1999.
In December 1996, the Company issued $2,050,600 in promissory notes to the
holders of the Preferred Stock as full payment of the cumulative preferred
stock dividends. The promissory notes are unsecured and bear interest at
the rate of 10.25% per annum. Interest only is payable semi-annually with
the principal due on December 31, 2000. The Company may prepay all or a
portion of the principal at any time prior to maturity with no penalty. On
December 1, 1999, the holders of promissory notes totaling $1,811,555
tendered their promissory notes, along with accrued interest of $77,835
for common stock pursuant to the Company's private placement of shares.
Additionally, the Company retired $20,634 principal amount of promissory
notes in January 2000.
Long-term debt at December 31, 1999 and 1998 is as follows:
(Continued)
50
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31,
-----------------------
1999 1998
---------- ----------
Note payable - related party, interest at
10% per annum, principal due
June 1, 2000, convertible into
common stock at $6.60 per share ........... $1,000,000 --
$10,000,000 bank credit facility,
$80,000 borrowing base, interest
payable monthly at prime rate
(8. 5% at December 31, 1999)
plus 1.25%. Borrowing availability
and reducing base amount are
redetermined semiannually ................. 80,000 $ 210,000
Notes payable, interest at
10.25% per annum payable
semi-annually, principal due
December 31, 2000 ........................ 239,045 2,050,600
---------- ----------
1,319,045 2,260,600
Less current maturities, including note
payable-related party ..................... 1,319,045 200,000
---------- ----------
$ -- $2,060,600
========== ==========
(5) STOCKHOLDERS' EQUITY
In June 1999, the Company received $1,960,000 through a private placement
of 392,000 shares of its' common stock, $.01 par value per share, at $5.00
per share. The proceeds were used to replenish working capital previously
used for planned investments in longer term, high potential projects and
for general working capital.
In order to provide funding for the acquisition of ARO in December 1999,
the Company arranged a private placement and conversion of principal and
accrued interest on promissory notes into common stock, $.01 par value per
share, of 701,820 shares and 314,898 shares, respectively and a $1,000,000
convertible promissory note, see notes 4 and 7. The shares were issued at
a price of $6.00 per share. Consideration for the common stock sold
consisted of approximately $4,210,919 cash and the surrender of
approximately $1,811,555 of the Company's promissory
(Continued)
51
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
notes due December 31, 2000, along with accrued interest of $77,835
through December 1, 1999.
(6) STOCK OPTIONS
The Company adopted a new stock option plan in 1996 (the Plan). The stock
subject to the options and other provisions of the Plan are shares of the
Company's Common Stock, $.01 par value (the Stock). The total amount of
the Stock with respect to which options may be granted shall not exceed in
the aggregate 10% of the number of issued and outstanding shares of Common
Stock of the Company. The stock options become exercisable from time to
time in part or as a whole, as the Compensation Committee (the Committee),
appointed by the Board of Directors, or the Board of Directors in their
discretion may provide. However, the Committee shall not grant options
which may become exercisable in any one calendar year to purchase more
than one-third of the maximum amount granted. All options expire five
years after the date of grant. The price of options granted may not be
less than eighty-five percent of the fair market value of the Stock on the
date the option is granted. Optionees must continue their association with
the Company for six months after exercising the options, or the underlying
stock reverts to the Company. All shares issued for options exercised in
the current year are restricted at December 31, 1999. The Company's
previous stock option plan, with terms and conditions essentially the same
as those of the Plan, expired in 1995.
At December 31, 1999 the Company has reserved a total of 519,229 shares of
Common Stock for issuance under the above mentioned stock option plans, of
which 85,324 shares relate to options granted prior to 1996, under the
previous stock option plan. The outstanding stock options granted to key
employees, officers and directors, for the purchase of shares of the
Company's Common Stock, are as follows:
(Continued)
52
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EXERCISE
PRICE PER SHARE
-------------------
SHARES FROM TO
-------- -------- --------
Balance, December 31, 1997 . 196,016 2.391 4.383
======== ======== ========
Expired ............... (32,005) 4.383 2.789
Exercised ............. (12,780) 2.789 2.789
-------- -------- --------
Balance, December 31, 1998 . 151,231 2.789 4.383
======== ======== ========
Granted ............. 72,100 3.125 5.000
Expired ............... (14,223) 4.383 2.789
Exercised ............. (32,004) 2.789 4.383
-------- -------- --------
Balance, December 31, 1999 . 177,104 2.789 5.000
======== ======== ========
The weighted average exercise price per share was $3.606 and $2.789 in
1999 and 1998, respectively.
As of December 31, 1999, options for 81,478 shares of stock were
immediately exercisable. There were 72,100 options granted in 1999.
Pursuant to the requirements of FASB No. 123, the weighted average fair
market value of options granted during 1999 and 1997 are $1.57 and $2.66,
respectively. The weighted average closing bid prices for the Company's
stock at the date the options were granted during 1999 and 1997 are $3.34
and $4.50, 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 61% and 80% and risk-free interest rates of 3.75% for grants in 1999
and 1997, and an expected life of 3 years. As the Company has not declared
dividends since it became a public entity, no dividend yield was used.
Actual value realized, if any, is dependent on the future performance of
the Company's Common Stock and overall stock market conditions. There is
no assurance the value realized by an optionee will be at or near the
value estimated by the Black-Scholes model.
As discussed in Note 1, no compensation expense has been recorded in 1999,
1998, and 1997 for stock options granted. Had compensation cost for the
Company's stock option plans been determined based on the fair market
value at the grant dates for awards made after December 31, 1996 under
those plans, the Company's net income
(Continued)
53
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(loss) and earnings (loss) per share would have been reduced to the pro
forma amounts indicated below:
YEAR ENDED DECEMBER 31,
-------------------------------------
1999 1998 1997
----------- ----------- ---------
Net income (loss) As reported $(2,086,511) $(9,059,979) $ 983,095
Pro forma (2,190,033) (9,172,801) 801,555
Basic earnings (loss) As reported (0.43) (2.02) 0.22
per share Pro forma (0.45) (2.04) 0.18
Diluted earnings As reported (0.43) (2.02) 0.22
(loss) per share Pro forma (0.45) (2.04) 0.18
Outstanding options at December 31, 1999 expire between August 18, 2000
and January 14, 2004.
Under the provisions of SFAS No. 123, the pro forma disclosures above
include only the effects of stock options granted by the Company
subsequent to December 31, 1994. During this initial phase-in period, the
pro forma disclosures as required by SFAS No. 123 are not representative
of the effects on reported net income for future years as options vest
over several years and additional awards are generally made each year and
there is a risk of forfeiture.
(7) RELATED PARTY TRANSACTIONS
Related party transactions which are not disclosed elsewhere in these
consolidated financial statements are discussed in the following
paragraph.
In June 1999, the Company received $1,960,000 through a private placement
of 392,000 shares of its' common stock, $.01 par value per share, at $5.00
per share. A director of the Company participated in the private
placement, purchasing 100,000 shares.
In order to provide funding for the acquisition of ARO in December 1999,
the Company arranged a private placement and conversion of principal and
accrued interest on promissory notes into common stock, $.01 par value per
share, of 701,820 shares and 314,898 shares, respectively. The shares were
issued at a price of $6.00 per share. Consideration for the common stock
sold consisted of approximately $4,210,919 cash
(Continued)
54
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and the surrender of approximately $1,811,555 of the Company's promissory
notes due December 31, 2000, along with accrued interest of $77,835
through December 1, 1999. Three directors of the Company participated in
this private placement; one director paid $100,002 for 16,667 shares and
tendered a note in the amount of $95,761 plus accrued interest of $4,114
and cash $325 for 16,700 shares, another director tendered a note in the
amount of $179,921 plus accrued interest of $7,730 and cash $149 for
31,300 shares and a third director tendered a note in the amount of
$26,769 plus accrued interest of $1,150 and cash $281 for 4,700 shares.
On December 1, 1999, the Company issued a $1,000,000 promissory note to a
director of the Company. The note is due June 1, 2000 bears interest at
10% per annum, and is convertible into common stock at $6.60 per share.
The due date of the note was subsequently extended to March 31, 2001 and
is convertible into common stock at $6.00 per share.
In 1992, the Company entered into a contract with a company, in which a
director of the Company is a principal, for business development
consulting services. The Company paid $71,250 and $90,000 under the
contract in 1998 and 1997, respectively. The contract was terminated
October 15, 1998.
(8) LEASES
The Company has various noncancelable operating leases which continue
through 2006.
The following is a schedule of future minimum lease payments required
under noncancelable operating leases at December 31, 1999:
YEARS ENDING
DECEMBER 31,
------------
2000 $ 190,211
2001 198,548
2002 186,498
2003 185,521
2004 195,617
Thereafter 391,234
-----------
$ 1,347,629
(Continued)
55
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Rental expense under operating leases for the years indicated are as
follows:
YEARS ENDING
DECEMBER 31,
------------
1999 $ 136,310
1998 119,490
1997 222,838
(9) COMMITMENTS AND CONTINGENCIES
In 1993, the United States Department of the Interior, Minerals Management
Service (MMS) required the Company's wholly-owned subsidiary, Blue Dolphin
Exploration Company (BDEX), to provide additional security to ensure it
could meet the future abandonment and site clearance obligations
associated with the Buccaneer Field. In February 1994, BDEX and the MMS
agreed on the form of such security and the amount of the future
obligations.
As additional security for the future Buccaneer Field abandonment and site
clearance obligations, in February 1994, BDEX provided the MMS with a
$700,000 supplemental surety bond. In October 1996, BDEX provided the MMS
with an additional $600,000 supplemental surety bond. The Company's annual
abandonment escrow fund payment of $250,000 that was due in June 1999 was
not made as a result of the removal of the inactive satellite platform in
1999 at a cost of approximately $345,000.
Additionally, a sinking fund was established in 1994 wherein $250,000
annually will be set aside until a total of approximately $2,400,000 has
been accumulated to meet end of lease abandonment and site clearance
obligations. The Company estimates the remaining useful life of its major
Buccaneer Field facilities to be in excess of ten years.
The Company is involved in various claims and legal actions arising in the
ordinary course of business. In the opinion of management, the ultimate
disposition of these matters will not have a material effect on the
Company's financial position, results of operations or cash flows.
(Continued)
56
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(10) BUSINESS SEGMENT INFORMATION
The Company's income producing operations are conducted in two principal
business segments: oil and gas exploration and production, and pipeline
operations, which includes mid steam projects. Intersegment revenues
consist of transportation, general processing and storage fees charged by
certain subsidiaries to another for natural gas and crude oil transported
through the Blue Dolphin Pipeline System. The intercompany revenues and
expenses are eliminated in consolidation. Information concerning these
segments for the years ended December 31, 1999, 1998, and 1997 is as
follow:
OPERATING DEPLETION,
INTERSEGMENT INCOME IDENTIFIABLE DEPRECIATION AND
REVENUES REVENUES (LOSS)(1) ASSETS AMORTIZATION (2)
----------- ------------ ----------- ------------ ----------------
Year ended December 31, 1999:
Oil and gas exploration,
production and
operating fees ........................ $ 887,340 6,000 (892,032) 12,816,861 212,441
Pipeline operations
1,889,837 14,121 (551,339) 7,735,149 345,600
Other ....................................... (20,121) (660,211) 986,206 37,245
----------- ----------- ------------ ----------------
2,757,056 -- (2,103,582) 21,538,216 595,286
Other income ............................... 1,895,320
-----------
Loss before income taxes .................... (208,262)
Year ended December 31, 1998:
Oil and gas exploration,
production and
operating fees ........................ $ 777,829 8,000 (12,448,875) 6,869,682 179,384
Pipeline operations ......................... 2,818,921 29,976 739,610 5,912,550 193,086
Other ....................................... (37,976) (341,377) 2,084,984 28,512
----------- ----------- ------------ ----------------
Consolidated
3,558,774 -- (12,050,642) 14,867,216 400,982
Other expense ............................... (109,147)
-----------
Loss before income taxes .................... (12,159,789)
Year ended December 31, 1997:
Oil and gas exploration,
production and
operating fees ........................ $ 828,013 8,000 (384,459) 15,568,782 174,988
Pipeline operations ......................... 4,192,343 29,750 2,308,995 9,048,897 169,873
Other ....................................... (37,750) (458,681) 26,708 27,391
----------- ----------- ------------ ----------------
Consolidated ................................ 4,982,606 -- 1,485,855 24,644,387 372,252
Other income ................................ 43,471
-----------
Income before income taxes .................. 1,529,326
(Continued)
57
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Consolidated income from operations includes $602,845, $564,584 and
$373,040 in unallocated general and administrative expenses, and
unallocated depletion, depreciation and amortization of $37,245,
$28,512 and $27,391 for the years ended December 31, 1999, 1998 and
1997, respectively.
(2) Pipeline depletion, depreciation and amortization includes a
provision for pipeline abandonment of $20,840, $26,340 and $26,340,
for the years ended December 31, 1999, 1998 and 1997 respectfully.
Oil and gas depletion, depreciation and amortization includes a
provision for abandonment costs of platforms and wells of $17,656,
$30,378 and $28,466 for the years ended December 31, 1999, 1998 and
1997, respectively.
See the supplemental disclosures for oil and gas producing activities for
discussion of capitalized costs incurred for oil and gas production
operations. Capital expenditures of $3,028,216 were incurred for pipeline
operations for the year ended December 31, 1999. Capitalized expenditures
of $299,426 were incurred for mid stream projects for the year ended
December 31, 1999.
The Company's primary market area is the Texas Gulf Coast region of the
United States. The Company has a concentration of credit risk with
customers in the energy and petro chemical industries. The Company's
customers may be similarly affected by changes in economic, regulatory or
other factors. Trade receivables are generally not collateralized;
however, the Company's customers' historical and future credit positions
are thoroughly analyzed prior to extending credit. Revenues from major
customers exceeding 10% of segment revenues were as follows for the
periods indicated:
(Continued)
58
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS
SALES AND PIPELINE
OPERATING FEES OPERATIONS TOTAL
-------------- ---------- ---------
Year ended December 31, 1999:
Apache Corporation ............. $ 295,525 723,437 1,018,962
The Dow Chemical Company ....... 227,778 22,512 250,290
Year ended December 31, 1998:
Apache Corporation ............. $ 333,787 1,504,375 1,838,162
The Dow Chemical Company ....... 391,913 46,119 438,032
Burlington Resources ........... -- 429,186 429,186
Year ended December 31, 1997:
Apache Corporation ............. $ 359,376 1,466,621 1,825,997
The Coastal Corporation ........ 39,905 1,111,885 1,151,790
Burlington Resources ........... -- 642,492 642,492
The Dow Chemical Company ....... 393,443 114,381 507,824
(11) SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
The following supplemental information regarding the oil and gas
activities of the Company is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange Commission (SEC)
and SFAS No. 69 DISCLOSURES ABOUT OIL AND GAS PRODUCING Activities
(Statement 69).
Per discussion with the Securities and Exchange Commission, proved
reserves previously reported at December 31, 1999 have been revised to
eliminate proved undeveloped reserves attributable to the Buccaneer Field,
before income taxes. This revision has eliminated 76,074 barrels of oil
and 13,123,893 Mcf of natural gas thereby decreasing the standardized
measure of discounted future net cash inflow by $1,234,601.
At December 31, 1999, the Buccaneer Field accounted for 59% of the
Company's discounted future net cash flows from proved reserves.
(Continued)
59
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The timing and amount of estimated future development costs may
significantly increase or decrease the Company's total proved and proved
developed reserve volumes, the Standardized Measure of Discounted Future
Net Cash Flows, and the components and changes therein.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Set forth below is a summary of the changes in the estimated quantities of
the Company's crude oil and condensate, and natural gas reserves for the
periods indicated, as estimated by the Company (Buccaneer Field),
Netherland Sewell & Associates Inc. (ARO) and Ryder Scott Company (ARO).
All of the Company's reserves are located within the United States. Proved
reserves cannot be measured exactly because the estimation of reserves
involves numerous judgmental determinations. Accordingly, reserve
estimates must be continually revised as a result of new information
obtained from drilling and production history, new geological and
geophysical data and changes in economic conditions.
Proved reserves are estimated quantities of natural gas, crude oil, and
condensate which geological and engineering data demonstrate, with
reasonable certainty, to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved
developed reserves are proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
method.
(Continued)
60
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OIL GAS
QUANTITY OF OIL AND GAS RESERVES (BBLS) (MCF)
----------- -----------
Total proved reserves at December 31, 1995 ...... 202,166 33,097,136
----------- -----------
Revisions to previous estimates ................. (6,477) (201,823)
Production ...................................... (1,887) (180,269)
----------- -----------
Total proved reserves at December 31, 1996 ...... 193,802 32,715,044
----------- -----------
Revisions to previous estimates ................. (8,500) (1,125,504)
Production ...................................... (1,156) (176,986)
----------- -----------
Total proved reserves at December 31, 1997 ...... 184,146 31,412,554
=========== ===========
Revisions to previous estimates ................. 6,743 (40,387)
Production ...................................... (1,628) (177,260)
----------- -----------
Total proved reserves at December 31, 1998 ...... 189,261 31,194,907
=========== ===========
Acquisitions .................................... 150,012 4,419,130
Revisions to previous estimates ................. (76,711) (13,226,766)
Production ...................................... (6,338) (169,329)
----------- -----------
Total proved reserves at December 31, 1999 (Restated) 256,224 22,217,942
=========== ===========
Proved developed reserves:
December 31, 1999 ........................... 205,525 20,400,120
December 31, 1998 ........................... 113,183 18,070,961
December 31, 1997 ........................... 108,068 18,288,608
(Continued)
61
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CAPITALIZED COSTS OF OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the aggregate amounts of capitalized costs
relating to the Company's oil and gas producing activities and the
aggregate amount of related accumulated depletion, depreciation and
amortization as of the dates indicated:
DECEMBER 31,
---------------------------
1999 1998
------------ ------------
Unproved properties and prospect generation
costs not being amortized ............. $ 950,813 227,286
Proved properties being amortized ......... 25,524,144 20,983,520
Less accumulated depletion, depreciation,
amortization and impairment ........... (16,129,385) (15,957,436)
------------ ------------
Net capitalized costs ........ $ 10,345,572 5,253,370
============ ============
At December 31, 1998 the Company recorded an impairment charge on its oil
and gas properties and certain exploration activity costs of $12,011,544,
resulting from lower oil and gas prices and changes to its development
plans, whereby development of oil and gas properties have been deferred.
The Company previously reported its provision for abandonment as a
liability separately on the balance sheet. The Company has reclassified
the accrued abandonment liability to be reflected as a component of
accumulated depletion, depreciation and amortization.
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:
(Continued)
62
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
Property acquisition costs $4,538,939 -- 471,861
Exploration costs ........ 57,632 277,501 --
Development costs ........ -- -- 23,685
---------- ---------- ----------
$4,596,571 277,501 495,546
========== ========== ==========
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
The following table reflects the Standardized Measure of Discounted Future
Net Cash Flows relating to the Company's interest in proved oil and gas
reserves as of:
DECEMBER 31,
----------------------------
1999 1998
------------ ------------
(Restated)
Future cash inflows ................... $ 54,304,207 60,296,555
Future development costs .............. (5,208,880) (9,782,601)
Future production costs ............... (15,655,715) (25,093,865)
------------ ------------
Future net cash inflows
before income taxes ............... 33,439,612 25,420,089
Future income taxes ................... (195,748) (213,271)
------------ ------------
Future net cash flows ................. 33,243,864 25,206,818
10% discount factor ................... (18,340,109) (19,235,787)
------------ ------------
Standardized measure of discounted
future net cash inflow ...... $ 14,903,755 5,971,031
============ ============
Future net cash flows at each year end, as reported in the above schedule,
were determined by summing the estimated annual net cash flows computed
by: (1) multiplying estimated quantities of proved reserves to be produced
during each year by current prices (at December 31, 1999, such prices were
$24.66 per barrel of oil and $2.16 per Mcf of gas) and (2) deducting
estimated expenditures to be incurred during each year to develop and
produce the proved reserves (based on current costs).
(Continued)
63
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The price the Company uses to value its oil is higher than year-end posted
market prices. This is due to the premium the Company receives over posted
market prices, primarily from the Buccaneer Field, due to location and
quality differentials. The Buccaneer Field produces high gravity oil.
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.
The Company cautions readers that the standardized measure information
which places a value on proved reserves is not indicative of either fair
market value or present value of future cash flows. Other logical
assumptions could have been used for this computation which would likely
have resulted in significantly different amounts. Such information is
disclosed solely in accordance with Statement 69 and the requirements
promulgated by the SEC to provide readers with a common base for use in
preparing their own estimates of future cash flows and for comparing
reserves among companies. Management of the Company does not rely on these
computations when making investment and operating decision. Principal
changes in the STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
attributable to the Company's proved oil and gas reserves for the periods
indicated are as follows
(Continued)
64
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
(Restated)
Sales and transfers, net of production costs* $ 555,450 433,346 489,564
Acquisitions of reserves .................... 4,335,908 -- --
Net change in estimated future development
costs .................................... 2,523,249 18,918 165,389
Net change in income taxes .................. 17,523 5,322,055 267,388
Revisions in previous quantity estimates .... (9,433,590) 34 (996,557)
Net changes in sales and transfer prices,
net of production costs .................. 9,503,801 (10,944,737) (548,223)
Accretion of discount ....................... 618,430 2,277,393 2,432,226
Change in production rates (timing)
and other ................................ 811,953 (7,835,514) (3,090,710)
----------- ----------- -----------
Net change ........................ $ 8,932,724 (10,728,505) (1,280,923)
=========== =========== ===========
*23% of the Company's estimated proved oil reserves and 7% of its
estimated proved gas reserves were being produced at December 31, 1999.
(12) ACQUISITIONS
BLACK MARLIN PIPELINE SYSTEM. On March 1, 1999 the Company acquired 10% of the
stock of Black Marlin Pipeline Company from Enron Pipeline Company ("Enron"),
for $5,404,270 cash. In addition, Enron received an option to acquire a minimum
of 25% and a maximum of 33-1/3% of the Black Marlin Pipeline System, if Black
Marlin Pipeline should become no longer subject to rate and tariff regulation by
the Federal Energy Regulatory Commission. This option will expire on the earlier
of the third anniversary of notice that the Black Marlin Pipeline is no longer
subject to rate and tariff regulation or March 1, 2004. Black Marlin Pipeline
Company is the owner of the Black Marlin Pipeline System. The Black Marlin
Pipeline System includes the Black Marlin Pipeline, onshore facilities for
condensate and gas separation and dehydration, 3,000 Bbls of above ground
tankage for storage of condensate, a truck loading facility for oil and
condensate, and 5 acres of land in Galveston County, Texas where the Black
Marlin Pipeline comes ashore and on which are located the pipeline system's
shore facilities. The Black Marlin Pipeline consists of two segments. The
offshore segment transports natural gas and condensate and is comprised of
approximately 67 miles of 16-inch pipeline from a High Island Block 136 platform
including an
(Continued)
65
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
extension from a platform in High Island Block A-6, to an interconnection in
High Island Block 137, across Galveston Bay to the onshore facilities at Texas
City, Texas. The offshore segment also includes approximately 7 miles of 8-inch
pipeline from a platform in High Island Block 199 to an interconnection with the
main line in High Island Block 171. The onshore segment consists of
approximately 2 miles of 16-inch pipeline from the shore facilities to an end
user and pipeline system tie-ins. This acquisition was funded by selling a
one-sixth (1/6) undivided interest in the Company's Blue Dolphin Pipeline
System, the Black Marlin Pipeline System and the Omega Pipeline to WBI Southern,
Inc. ("WBI") for $3,712,000 and selling a one-third (1/3) undivided interest in
the Black Marlin Pipeline System to MCNIC Pipeline and Processing Company
("MCNIC") for $1,801,423. These sales were completed effective March 1, 1999. In
addition, conditional consideration may be received from WBI up to a maximum of
$500,000 during the four-year period ending February 28, 2003, if pre-tax cash
flow exceeds certain targets. For the annual period ended February 29, 2000,
pre-tax cash flow was below the target level, thus no conditional consideration
was received by the Company. MCNIC owns a one-third (1/3) undivided interest in
the Blue Dolphin Pipeline System and the Omega Pipeline. WBI and MCNIC are both
independent third parties to the Company.
AMERICAN RESOURCES OFFSHORE, INC. On December 2, 1999, BDEX acquired a 75%
ownership interest in ARO. The purchase price for the ARO shares was
approximately $4.5 million. Concurrently with the sale to BDEX, ARO sold an 80%
interest in its Gulf of Mexico assets to Fidelity Oil Holdings, Inc. a
subsidiary of MDU Resources Group, Inc. ("MDU") and an independent third party
to the Company. The proceeds received by ARO were used to retire certain
indebtedness.
ARO's assets consist of an average 6% non-operated working interest in
eight producing properties and one proved undeveloped property along with
leasehold interests in 34 additional offshore tracts, all located in the Gulf of
Mexico offshore Louisiana and Texas. At closing, all significant liabilities of
ARO were settled and substantially all stock options and warrants were
eliminated.
66
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders filed with the SEC on April 20, 2000.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders filed with the SEC on April 20, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders filed with the SEC on April 20, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 is incorporated by reference to the
Company's definitive proxy statement relating to its 2000 annual meeting of
stockholders filed with the SEC on April 20, 2000.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
The following financial statements and the Reports of Independent
Public Accountants are filed as a part of this report on the pages indicated:
PAGE
Consolidated Balance Sheets, at December 31, 1999
and 1998................................................ 34
Consolidated Statements of Operations, for the
years ended December 31, 1999, 1998, and 1997........... 36
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 1999, 1998, and 1997........... 37
Consolidated Statements of Cash Flows, for the
years ended December 31, 1999, 1998, and 1997........... 38
Notes to Consolidated Financial Statements................ 40
67
(a) 2. Exhibits
NO. DESCRIPTION
--- -----------
3.1 (1) Certificate of Incorporation of the Company.
3.2 (2) Certificate of Correction to the Certificate of Incorporation of
the Company dated June 30, 1987.
3.3 (2) Certificate of Amendment to the Certificate of Incorporation of
the Company dated June 30, 1987.
3.4 (2) Certificate of Amendment to the Certificate of Incorporation of
the Company dated December 11, 1989.
3.5 (2) Certificate of Amendment to the Certificate of Incorporation of
the Company dated December 14, 1989.
3.6 (2) Bylaws of the Company.
3.7 (6) Certificate of Amendment to the Certificate of Incorporation of
the Company dated December 8, 1997.
4.1 (2) Specimen Certificate of Blue Dolphin Energy Company Common Stock.
* 10.1 (1) Blue Dolphin Energy Company 1985 Employee Stock Option Plan.
* 10.2 (4) Blue Dolphin Energy Company 1996 Employee Stock Option Plan.
10.4 (3) Loan Agreement by and among Blue Dolphin Energy Company, Blue
Dolphin Pipe Line Company, Buccaneer Pipe Line Co., Mission
Energy, Inc. dba MEI Mission Energy, Inc., Ivory Production Co.,
Blue Dolphin Services Co., and Bank One, Texas, N. A., dated
January 14, 1994.
10.6 (4) First Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission
Energy, Inc., Ivory Production Co., Blue Dolphin Services Co., and
Bank One, Texas, N.A., dated February 7, 1995.
10.7 (4) Second Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission
Energy, Inc., Blue Dolphin Exploration Company, previously known
as Ivory Production Co., Blue Dolphin Services Co., and Bank One,
Texas, N. A., dated December 22, 1995.
10.8 (5) Third Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission
Energy, Inc., Blue Dolphin Exploration Company, previously known
as Ivory Production Co., Blue Dolphin Services Co., and Bank One,
Texas, N. A., dated November 5, 1996.
10.9 Fourth Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission
Energy, Inc., Blue Dolphin Exploration Company, previously known
as Ivory Production Co., Blue Dolphin Services Co., and Bank One,
Texas, N. A., dated August 18, 1998.
10.10 Fifth Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe
68
Line Co., Mission Energy, Inc. d/b/a MEI Mission Energy, Inc.,
Blue Dolphin Exploration Company, previously known as Ivory
Production Co., Blue Dolphin Services Co., and Bank One, Texas, N.
A., dated December 17, 1999.
10.11 Sixth Amendment to Loan Agreement dated January 14, 1994 by and
among Blue Dolphin Energy Company, Blue Dolphin Pipe Line Company,
Buccaneer Pipe Line Co., Mission Energy, Inc. d/b/a MEI Mission
Energy, Inc., Blue Dolphin Exploration Company, previously known
as Ivory Production Co., Blue Dolphin Services Co., and Bank One,
Texas, N. A., dated January 12, 2000.
10.12 (7) Asset Purchase Agreement between WBI Southern, Inc., Blue Dolphin
Pipeline Company, Buccaneer Pipe Line Co. and Mission Energy, Inc.
10.13 (7) Purchase and Sale Agreement between Enron Pipeline Company, Black
Marlin Energy Company and Blue Dolphin Energy Company.
10.14 (7) Asset Purchase Agreement between WBI Southern, Inc., Black Marlin
Pipeline Company and Black Marlin Energy Company.
10.15 (7) Asset Purchase Agreement between MCNIC Offshore Pipeline &
Processing Company, Black Marlin Pipeline Company and Black Marlin
Energy Company.
10.16 (8) Investment Agreement, as amended, by and between American
Resources Offshore, Inc. and Blue Dolphin Exploration Company.
10.17 Management Services Agreement by and between Fidelity Oil
Holdings, Inc. and Blue Dolphin Exploration Company.
21.1** List of Subsidiaries of the Company.
23.1** Consent of Netherland, Sewell & Associates, Inc., independent
petroleum engineers and geologists.
23.2** Consent of Ryder Scott Company, independent petroleum engineers.
27.1** Financial Data Schedule.
----------
(1) Incorporated herein by reference to Exhibits filed in connection with
Registration Statement on Form S-4 of ZIM Energy Corp. filed under the
Securities Act of 1933 (Commission File No. 33-5559).
(2) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1989
under the Securities and Exchange Act of 1934, dated March 30, 1990
(Commission File No. 000-15905).
(3) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1993
under the Securities and Exchange Act of 1934, dated March 30, 1994
(Commission File No. 000-15905).
(4) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1995
under the Securities and Exchange Act of 1934, dated March 29, 1996
(Commission File No. 000-15905).
(5) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1996
under the Securities and Exchange Act of 1934, dated March 31, 1997
(Commission File No. 000-15905).
69
(6) 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).
(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 March 1, 1999 (Commission File No. 000-15905).
(8) Incorporated herein by reference to Exhibits filed in connection with
Schedule 13D of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated October 22, 1999 (commissions File No.
000-15905).
* Management Compensation Plan.
** Previously filed.
*** Filed herewith.
(b) Reports on Form 8-K
On December 7, 1999, the Company filed a current report on Form 8-K
dated December 2, 1999 that it closed the purchase of 39,509,457 shares
of common stock of American Resources Offshore, Inc. The items reported
in such current report were Item 2 (Acquisitions or Dispositions of
Assets) and Item 7 (Financial Statement and Exhibits).
On December 17, 1999, the Company filed a current report on Form 8-KA
dated December 17, 1999, with respect to the acquisition of American
Resources Offshore, Inc. The items reported in such current report were
Item 2 (Acquisitions or Dispositions of Assets) and Item 7 (Financial
Statement and Exhibits).
70
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: January 10, 2001
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 January 10, 2001
Michael J. Jacobson executive officer)
/S/ G. BRIAN LLOYD Vice President, Treasurer January 10, 2001
G. Brian Lloyd (principal accounting and
financial officer)
/S/ IVAR SIEM Chairman January 10, 2001
Ivar Siem
/S/ HARRIS A. KAFFIE Director January 10, 2001
Harris A. Kaffie
/S/ ROBERT L. BARBANELL Director January 10, 2001
Robert L. Barbanell
/S/ MICHAEL S. CHADWICK Director January 10, 2001
Michael S. Chadwick
71