UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A-4
[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.
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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 undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
REVERSIONARY INTEREST. A form of ownership interest in property that
reverts back to the transferor after expiration of an intervening income
interest.
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.
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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 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
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(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
23
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).
24
(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).
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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
26