UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
X Annual Repor t Pursuant to Section 13 or 15(d) of the Securities Act
----- of 1934
For the fiscal year ended December 31, 2001
or
Transition eport Pursuant to Section 13 or 15(d) of the Securities
----- Exchange Act of 1934
For the transition period from ____________ to ____________
Commission file Number: 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Name of small business issuer in its charter)
Delaware 73-1268729
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
801 Travis, Suite 2100, Houston, Texas 77002
(Address of principal executive office) (Zip Code)
Issuer's telephone number (713) 227-7660
Securities registered pursuant to Section 12(b) of the Exchange Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act:
common stock, $.01 par value
(Title of Class)
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such
shorter period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days. Yes X No
--- ---
Check if there is no disclosure of delinquent filers in response to
Item 405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. X
---
The issuer's revenues for the year ended December 31, 2001 were
$5,686,025.
The aggregate market value of the voting stock held by non-affiliates
of the registrant as of March 22, 2002, was approximately $6,624,578.
As of March, 22, 2002, there were outstanding or in the process of
distribution 6,371,845 shares of common stock, par value $.01 per share, of the
issuer.
Documents Incorporated By Reference
The registrant's definitive proxy statement for the 2002 Annual Meeting
of Stockholders of the registrant (Sections entitled "Ownership of Securities of
the Company", "Election of Directors", "Executive Compensation" and
"Transactions With Related Persons"), to be filed with the Securities and
Exchange Commission pursuant to Regulation 14A, is incorporated by reference in
Part III of this report.
PART I
Item 1. Business
Forward Looking Statements. Certain of the statements included in this
annual report on Form 10-KSB, including those regarding future financial
performance or results or that are not historical facts, are "forward-looking"
statements as that term is defined in the Section 21E of the Securities Exchange
Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as
amended. The words "expect", "plan", "believe", "anticipate", "project",
"estimate", and similar expressions are intended to identify forward-looking
statements. Blue Dolphin Energy Company (referred to herein, with its
predecessors and subsidiaries, as "Blue Dolphin" or the "Company") cautions
readers that any such statements are not guarantees of future performance or
events and such statements involve risks and uncertainties that may cause actual
results and outcomes to differ materially from those indicated in
forward-looking statements. Some of the important factors, risks and
uncertainties that could cause actual results to vary from forward-looking
statements include:
o the risks associated with exploration;
o gas and oil price volatility;
o uncertainties in the estimation of proved reserves and in the
projection of future rates of production and timing of development
expenditures;
o availability and cost of capital;
o actions or inactions of third party operators for properties where the
Company has an interest;
o regulatory developments; and
o general economic conditions.
Additional factors that could cause actual results to differ materially from
those indicated in the forward-looking statements are discussed under the
caption "Risk Factors". Readers are cautioned not to place undue reliance on
these forward-looking statements which speak only as of the date hereof. The
Company undertakes no duty to update these forward-looking statements. Readers
are urged to carefully review and consider the various disclosures made by the
Company which attempt to advise interested parties of the additional factors
which may affect the Company's business, including the disclosures made under
the caption "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in this report.
THE COMPANY
The Company conducts its business activities in two primary business
segments: (i) oil and gas exploration and production, which includes our
developmental-stage upstream projects, and (ii) pipeline operations, which
includes our developmental-stage mid-stream projects. The Company's oil and gas
exploration and production activities include the exploration, acquisition,
development, operation and, when appropriate, disposition of oil and gas
properties. The Company focuses its oil and gas acquisitions and exploration
activities in the western and central Gulf of Mexico.
The Company is a holding company that conducts substantially all of its
operations through its subsidiaries. Substantially all of the Company's assets
consist of equity in its subsidiaries. The Company's subsidiaries and affiliates
are as follows:
2
o American Resources Offshore, Inc., a Delaware corporation;
o Blue Dolphin Petroleum Company, a Delaware corporation;
o Blue Dolphin Exploration Company, a Delaware corporation;
o Blue Dolphin Pipe Line Company, a Delaware corporation;
o Blue Dolphin Services Co., a Texas corporation;
o Petroport, Inc., a Delaware corporation;
o New Avoca Gas Storage, LLC, a Texas limited liability company in which
the Company owns a 25% interest; and
o Drillmar, Inc., a Delaware corporation in which the Company owns a
12.8% interest.
Effective January 1, 2002, two wholly owned subsidiaries, Mission
Energy, Inc. and Buccaneer Pipe Line Co. were merged into Blue Dolphin Pipe Line
Company.
The principal executive office of the Company is located at 801 Travis,
Suite 2100, Houston, Texas, 77002, telephone number (713) 227-7660. Shore based
facilities are maintained in Freeport, Texas serving Gulf of Mexico operations.
The Company has 15 full-time employees. The Company's common stock is traded on
the National Association of Securities Dealers, Inc. Automated Quotation System
("NASDAQ") Small Cap Market under the trading symbol "BDCO". The Company's home
page address on the world wide web is http://www.blue-dolphin.com.
Recent Developments
On December 2, 1999, the Company, through Blue Dolphin Exploration,
acquired a 75% ownership interest in American Resources by purchasing
approximately 39.5 million shares of American Resources Common Stock. On
February 19, 2002, the Company completed its acquisition of American Resources,
pursuant to the Amended and Restated Agreement and Plan of Merger dated as of
December 19, 2001 (the "Merger Agreement"). Pursuant to the Merger Agreement,
American Resources became a wholly owned subsidiary of the Company and each
outstanding share of (i) American Resources common stock, par value $.00001 per
share, was converted into the right to receive, at the option of the holder,
either $.06 per share in cash or .0362 of a share of the Company's common stock,
par value $.01 per share (the "Common Stock"), and (ii) American Resources
Series 1993 Preferred Stock, par value $12.00 per share, was converted into the
right to receive, at the option of the holder, either $.07 in cash or .0301 of a
share of Common Stock.
As a result of elections made by American Resources' stockholders, the
Company will issue approximately 273,336 shares of Common Stock and will pay
approximately $255,000 in cash.
In February 2002, the Company acquired a 1/3 interest in the Blue
Dolphin Pipeline System and the inactive Omega Pipeline from MCNIC Pipeline and
Processing Company ("MCNIC"). Pursuant to the terms of the purchase and sales
agreement, Blue Dolphin issued MCNIC a $750,000 promissory note due December 31,
2006, with required monthly payments to be made out of 90% of the net revenues
of the interest acquired. The note bears interest at the rate of 6% per annum
and is secured by the interest acquired. Additionally, contingent payments of up
to $750,000 will be made, if the promissory note is retired before its maturity
date, payable annually after the promissory note is retired until December 31,
3
2006, out of 50% of the net revenues from the interest acquired. The termination
date, December 31, 2006, will be extended by one additional year, up to a
maximum of two years, for years in which non-recurring, extraordinary
expenditures attributable to the interest acquired, exceeds $200,000, in the
aggregate, during any year.
Oil and Gas Exploration and Production Activities
The Company's oil and gas assets are held, and operations conducted, by
American Resources, Blue Dolphin Petroleum and Blue Dolphin Exploration. 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 are subject to royalty, overriding royalty and interests of others. In
the future, the Company's properties may become subject to burdens and
encumbrances typical to oil and gas operators, such as liens incident to
operating agreements and current taxes, development obligations under oil and
gas leases and other encumbrances.
Certain terms that are commonly used in the oil and gas industry,
including terms that define the Company's rights and obligations with respect to
each of its properties, are defined in the "Glossary of Certain Oil and Gas
Terms" on pages 27, 28 and 29 of this Form 10-KSB.
The following is a description of the Company's major oil and gas
exploration and production assets and activities:
The Buccaneer Field. The Company owned a 100% working interest in the
Buccaneer Field (81.33% net revenue interest). Production from the Buccaneer
Field accounted for 5% of the total revenues from oil and gas sales of the
Company for the year ended December 31, 2000. In addition to conducting
traditional oil and gas production operations for itself, the Company operated
and maintained oil and gas production facilities for third party producers who
utilized the Blue Dolphin Pipeline System for gathering and transportation of
their production. The Company had a contract to provide operation and
maintenance services to another company, which during 2000, accounted for
approximately 3% of the Company's revenues.
In November 2000, after considering the costs associated with drilling
a new well to reestablish production, together with the unplanned cost of
repairs to the platforms, approximately $5.8 million, and the projected rate of
production and discounted cash flow from the field the Company decided to
abandon and not reestablish production from the Buccaneer Field. As a result of
this decision, the leases in this field terminated in January 2001 pursuant to
their terms, and the Company's operation and maintenance services contract was
terminated in December 2000.
As a result of the termination of the Company's leases in or around the
Buccaneer Field, the Company must plug and abandon all remaining wells and
remove platform facilities. The U.S. Minerals Management Service ("MMS")
requires that security be provided for the estimated abandonment obligations
associated with the Buccaneer Field. Blue Dolphin Exploration provided the MMS
surety bonds in the amount of $4.2 million. The rules and regulations of the MMS
require that the Company complete the plugging and abandonment within one year
after termination of the lease. In the first quarter of 2001, the Company
plugged and abandoned the remaining wells at a cost of approximately $1.4
million. Work to remove the two platform facilities began in August 2001 with
costs of $443,000 incurred as of December 31, 2001. The Company used all of its
escrowed funds of approximately $1.5 million to pay for plugging and abandonment
operations in 2001.
During the removal of the platform complexes in October 2001, the
Company initiated discussions with the Texas Parks and Wildlife ("TP&W") in an
effort to leave certain under water portions of the platform complexes in place
4
as artificial reefs. In December 2001, operations to remove the platform
complexes were suspended while the Company continues its discussions with the
TP&W. The Company expects that the TP&W will make a decision to leave either
one, two or neither of the Buccaneer Field platform complexes in place as
artificial reefs in the second quarter 2002. If the TP&W allows the Company to
leave one or both of the platform complexes as an artificial reef, certain site
clearance costs would be eliminated. The Company requested and has received an
extension from the MMS until October 1, 2002 to complete the removal and site
clearance of the platform complexes. The Company believes that its provision for
abandonment costs of $4.6 million at December 31, 2001 is adequate.
Until abandonment operations were suspended in December 2001,
significant progress was made. Both platform complexes include a production
platform with a bridge connected quarters platform. At the complex located in GA
Block 288, the decks on both the production and quarters platforms and the
bridge have been removed. At the complex located in GA Block 296, the deck on
the quarters platform, a portion of the deck on the production platform and the
bridge have been removed. If the TP&W does not allow the Company to leave either
of the platform complexes in place, the Company will have to remove the
remaining portion of the GA Block 296 production platform deck and the under
water platform structures and conduct site clearance.
American Resources. The oil and gas properties held by American
Resources represent more than 99% of the discounted present value of estimated
future net revenues from proved reserves of the Company as of December 31, 2001.
Sales of production from the these properties accounted for 100% of oil and gas
sales revenues and 83% of total revenues of the Company for the year ended
December 31, 2001.
The following table provides information regarding the Company's proved
reserves, all of which are held through American Resources, as of December 31,
2001:
Proved Reserves
From American Resources Offshore, Inc.
Gas
Oil Gas Equivalent
(Bbl) (MMcf) (Mmcfe)
---------- ---------- ----------
South Timbalier 148 33,543 1,153 1,354
Ship Shoal 150 91,022 169 715
West Cameron 172 1,710 546 556
South Timbalier 211 2,262 399 413
West Cameron 368 2,129 342 365
Other 169 355 356
---------- ---------- ----------
Total net proved reserves 130,835 2,964 3,749
========== ========== ==========
Significant Fields. As of December 31, 2001, all of American Resources
oil and gas properties were located on the outer continental shelf of the Gulf
of Mexico and consisted of interests in 17 leases. American Resources' working
interest in these leases ranges from 10% to 1%, with an average working interest
of approximately 5.5%. Of these leases, 10 are offshore Louisiana and 7 are
offshore Texas. Eleven of the leases are currently producing, and 6 are held for
future development. Those leases that are not producing are in their primary
term. The expiration of the primary terms of the undeveloped leases occurs as
follows: 5 in 2002 and 1 in 2003.
5
South Timbalier 148. South Timbalier Block 148 is located 30 miles
offshore Louisiana in an average water depth of 100 feet and is operated by
Newfield Exploration Company. American Resources owns a working interest in the
lease on the west half of the block that covers approximately 2,500 acres and
working interests in seven producing wells on three production platforms.
American Resources' working interest in the wells ranges from 9% to 1%.
Ship Shoal 150. Ship Shoal Block 150 is located 31 miles offshore
Louisiana in an average water depth of 53 feet. American Resources owns a 10%
working interest in 4,297 acres in the block, and working interests in two
producing wells on the lease operated by Century Exploration Company
("Century"). American Resources also owns an overriding royalty interest in one
producing well on the lease.
West Cameron 172. West Cameron Block 172 is located 25 miles offshore
Louisiana in an average water depth of 40 feet. American Resources owns a 5.4%
working interest that covers approximately 5,000 acres and working interests in
four producing wells on this lease, which are operated by Pure Resources, Inc.
("Pure").
South Timbalier 211. South Timbalier Block 211 is located 42 miles
offshore Louisiana in an average water depth of 140 feet. American Resources
owns a 6.0% working interest in this lease that covers approximately 5,000 acres
and working interests in two producing wells on the lease, which are operated by
The William G. Helis Company. American Resources owns an overriding royalty
interest in one well on the lease that was drilled under a farmout by Spinnaker
Exploration Company, L.L.C. ("Spinnaker"), during 1999 and commenced production
in the first quarter of 2000.
West Cameron 368. West Cameron Block 368 is located 63 miles offshore
Louisiana in an average depth of 69 feet and is operated by Century. American
Resources owns a 6% working interest in 5,000 acres and four producing wells.
Other. Other leases that contain proved reserves are High Island Block
37, offshore Texas, accounting for 33 Mmcfe; and Galveston Block 418, offshore
Texas, accounting for 323 Mmcfe.
Offshore Oil and Gas Prospect Generation Activities. The Company has
developed oil and gas exploration prospects in the Gulf of Mexico for sale to
third parties. The Company has seismic and other data to evaluate and develop
prospects. The Company owns a non-exclusive license to 200 blocks of 3-D seismic
data covering 1,152,000 acres in the western Gulf of Mexico and a substantial
inventory of close grid 2-D seismic data. In addition to recovering prospect
development costs, the Company seeks to retain a reversionary working interest
in each drillable prospect it sells.
In 1999, the Company had an agreement with Fidelity Oil, whereby in
exchange for certain participation rights in prospects generated by the Company,
Fidelity Oil paid $100,000 per month of the Company's costs associated with the
prospect generation program. Program costs were reimbursed to the Company as
prospects were developed and leases acquired. When leases were acquired, a
portion of the costs that were previously paid by Fidelity Oil were reimbursed
to it based on the level of interest Fidelity retained in each prospect. In
April 2000, the Company amended the agreement with Fidelity Oil whereby in
exchange for the right to acquire up to 100% of the working interest in
prospects generated by the Company, Fidelity Oil paid, on a monthly basis, the
costs associated with the program, which totaled $1.1 million during 2000.
Fidelity Oil also reimbursed the Company for the cost of additional seismic data
acquired. The available interests in the prospect inventory are held for sale on
an individual prospect basis.
6
Effective December 31, 2000, Fidelity Oil withdrew from the program and
the Company suspended the program.
As a result of Fidelity Oil's withdrawal, in January 2001, the Company
entered into a consulting agreement with Cheyenne Petroleum Co., whereby the
Company's remaining prospect generation staff provided technical consulting
services to Cheyenne in the evaluation of prospects for the March 2001 central
Gulf of Mexico federal lease sale. In exchange, Cheyenne reimbursed the Company
for personnel costs and allowed the Company to participate in prospects
generated with a 5% working interest in four undeveloped offshore blocks. This
agreement terminated April 30, 2001.
The Company's leased prospect inventory, which it continues to market,
consists of prospects on the following offshore leases:
o Mustang Island Area Block 817
o Mustang Island Area Block 839
The Company has reversionary working interests in several offshore
leases. Generally, the Company is entitled to its reversionary interest when the
other working interest owners receive a return of their investment in operations
calculated on a lease wide basis, rather than a well-by-well basis. These leases
are:
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
High Island Block A-7. A gas discovery was made in High Island Area
Block A-7, in the Gulf of Mexico, in April 2000. The Company owns an 8.9%
reversionary working interest in this field that is operated by Spinnaker. The
Company will begin to receive revenues from its reversionary interest after
"payout" occurs. Payout will occur after all of the working interest owners have
recovered their costs and expenses associated with developing the field from
sales of production from the field. At December 31, 2001, there was one well
producing in this field at a rate of approximately 23 Mmcf of natural gas per
day. During 2001, production from two producing wells ceased with no plans for
these wells to be reworked, and two unsuccessful exploratory wells were drilled.
Currently, there is one well producing from this field at a rate of
approximately 14 Mmcf of natural gas per day. As a result of these occurrences,
the Company now expects to begin to receive revenues from its reversionary
working interest in this field in 2005.
Other. In connection with Blue Dolphin Exploration's acquisition of a
controlling interest in American Resources in December 1999, Blue Dolphin
Exploration arranged for Fidelity Oil to acquire an 80% interest in American
Resources oil and gas assets located in the Gulf of Mexico for approximately
$24.2 million. For the right to participate in the acquisition of these assets,
Fidelity Oil agreed to assign Blue Dolphin Exploration 10% of its working
interest in the proved properties of American Resources after it recovered its
investment in these properties. In addition, Fidelity Oil agreed to assign Blue
Dolphin Exploration 15% of its working interest in each exploratory property
after Fidelity has recovered its investment in these exploratory properties on a
property by property basis.
7
In the fourth quarter 2001, Fidelity Oil recovered its investment in
the proved properties. However, instead of assigning 10% of its interest in the
proved properties, Fidelity paid Blue Dolphin $1.4 million in December 2001, for
the property interest owed to Blue Dolphin.
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, 2001, by Ryder
Scott Company, an independent petroleum engineering consulting firm. Proved gas
reserves were 79% of total proved reserves at December 31, 2001.
The following table presents the estimates of Proved Reserves, Proved
Developed Reserves, and Proved Undeveloped Reserves (as hereinafter defined),
future net revenues and the discounted present value of future net revenues from
Proved Reserves before income taxes to the net interest of the Company in oil
and gas properties as of December 31, 2001. The discounted present value of
future net revenues and future net revenues are calculated using the SEC Method
(defined below) and are not intended to represent the current market value of
the oil and gas reserves the Company owns.
PROVED RESERVES
As of December 31, 2001
Discounted
Net Oil Net Gas Future Present Value of Future
Reserves Reserves Net Revenues Net Revenues (1)
(Mbbls) (Mmcf) (in thousands) (in thousands)
-------------- -------------- -------------- --------------
Total Proved:
American Resources (2) 130.8 2,964 $ 7,395 $ 6,004
High Island A-7 0.1 46 28 24
-------------- -------------- -------------- --------------
Total Proved Reserves 130.9 3,010 $ 7,423 $ 6,028
============== ============== ============== ==============
Total Proved Developed Reserves:
American Resources (2) 128.7 2,613 $ 6,810 $ 5,507
High Island A-7 0 0 (13) (8)
-------------- ------- ------- -------------- --------------
Total Proved Developed
Reserves 128.7 2,613 $ 6,797 $ 5,499
============== ============== ============== ==============
Total Proved Undeveloped Reserves:
American Resources (2) 2.1 351 $ 585 $ 497
High Island A-7 0.1 46 41 32
-------------- -------------- -------------- --------------
Total Proved Undeveloped
Reserves 2.2 397 $ 626 $ 529
============== ============== ============== ==============
(1) The estimated discounted present value of future net revenues before
deductions for income taxes from the Company's Proved Reserves have
been determined by using prices of $17.70 per barrel of oil and $2.78
per Mcf of gas, representing the December 31, 2001 prices for oil and
gas and discounted at a 10% annual rate in accordance with requirements
for reporting oil and gas reserves pursuant to regulations promulgated
by the United States Securities and Exchange Commission (the "SEC
Method").
8
(2) As of December 31, 2001 the Company's ownership in American Resources
was 77%. The above reflects 100% of American Resources' reserves and
future net revenues. 23% of estimated discounted present value of
future net revenues associated with total proved reserves, total proved
developed reserves and total proved undeveloped reserves of American
Resources' properties is $1,380,931, $1,266,641 and $114,290,
respectively. Effective February 19, 2002, American Resources became a
wholly-owned subsidiary of the Company.
The quantities of proved gas and 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 at prices and costs, and under regulatory practices and
technology existing at the time of the estimate. Accordingly, changes in oil and
gas prices, operation and development costs, regulations, technology, future
production and other factors, many of which are beyond the Company's control,
could significantly affect the estimates of proved reserves and the discounted
present value of future net revenues attributable thereto.
Estimates of production and future net revenues cannot be expected to
represent accurately the actual production or revenues that may be recognized
with respect to oil and gas properties or the actual present market value of
such properties. For further information concerning the Company's Proved
Reserves, changes in Proved Reserves, estimated future net revenues and costs
incurred in the Company's oil and gas activities and the discounted present
value of estimated future net revenues from the Company's Proved Reserves, see
Note 12 - Supplemental Oil and Gas Information to Consolidated Financial
Statements included in Item 7.
Capital Expenditures for Proved Reserves. The following table presents
information regarding the costs the Company expects to incur in development
activities associated with its proved reserves. These expenditures include
recompletion costs, workover costs and the cost of drilling additional wells
required to recover proved reserves. The information regarding proved reserves
summarized in the preceding table assumes the following estimated capital
expenditures in the years indicated.
Estimated Capital Expenditures For Proved Reserves
For the years ending December 31,
(in thousands)
----------------------------------------------------
2002 2003 2004 2005 2006
-------- -------- -------- -------- --------
American Resources $ 150 $ 328 $ 81 $ 104 $ 212
High Island Block A-7 0 0 0 7 13
-------- -------- -------- -------- --------
Total $ 150 $ 328 $ 81 $ 111 $ 225
======== ======== ======== ======== ========
Management will continue to evaluate its capital expenditure program
based on, among other things, demand and prices obtainable for the Company's
production. The availability of capital resources and the willingness of other
working interest owners to participate in development operations may affect the
Company's timing for further development, and there can be no assurance that the
timing of the development of such reserves will be as currently planned.
9
Productive Wells and Acreage. The following table sets forth the number
of productive oil and gas wells in which the Company owned an interest and the
developed and undeveloped acreage as of December 31, 2001. "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.
ACREAGE AND WELLS
Productive Wells (1) Acres
------------------------------ -------------------------------------
Gross Net Developed (2) Undeveloped (3)
------------- --------------- ----------------- -----------------
Oil Gas Oil Gas Gross Net Gross Net
--- --- --- --- ----- --- ----- ---
American
Resources (4) 5 18 0.30 0.83 32,848 1,754 42,275 2,364
(1) "Productive wells" are producing wells and wells capable of production,
and include gas wells awaiting pipeline connections to commence
deliveries and oil wells awaiting connection to production facilities.
Wells that are completed in more than one producing horizon are counted
as one well.
(2) "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.
(3) "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.
(4) As of December 31, 2001 the Company's ownership interest in American
Resources was 77%. The above reflects 100% of American Resources'
acreage and wells.
Production, Price and Cost Data. The following table presents
information regarding production volumes and revenues, average sales prices and
costs (after deduction of royalties and interests of others) with respect to
crude oil, condensate, and gas attributable to the interest of the Company for
each of the periods indicated.
10
NET PRODUCTION, PRICE AND COST DATA
Year Ended December 31,
----------------------------------
2001 2000 1999
---------- ---------- --------
Gas:
Production (Mcf) 815,184 911,671 169,329
Revenue $3,607,910 $3,674,192 $393,125
Average Production (Mcf) per day 2,233.4 2 ,490.9 463.9
Average Sales Price
Per Mcf $ 4.43 $ 4.03 $ 2.32
Oil:
Production (Bbls) 40,769 64,707 6,338
Revenue $1,086,292 $1,844,948 $151,974
Average Production (Bbls) per day 111.7 176.8 17.4
Average Sales Price
Per Bbl $ 26.65 $ 28.51 $ 23.98
Production Costs (1):
Per Mcfe: $ 1.06 $ 1.05 $ 4.14
(1) Production costs, exclusive of workover costs, are costs incurred to
operate and maintain wells and equipment and to pay production taxes.
Drilling Activity. The following table shows the Company's drilling
activity for the last two years. During fiscal 1999 there was no drilling
activity. "Gross" as it applies to wells refers to the number of wells in which
a working interest is owned, while "net" applies to the sum of the fractional
working interests in gross wells.
Exploratory Wells Drilled Developmental Wells Drilled
--------------------------------- ---------------------------------
Productive Dry Productive Dry
--------------- --------------- --------------- ---------------
Gross Net Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----- ----- -----
2001
American Resources - - 1 0.06 1 0.1 - -
Other - - - - - - - -
2000
American Resources 3 0.091 0.07 4 0.19 1 0.05
Other - - - - - - - -
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.
Drillmar Project
In 2000, the Company, together with other partners, formed Drillmar,
Inc., and owned a 37.5% interest. Drillmar has developed mooring solutions which
allow a semi-submersible tender unit to be placed next to a deepwater floating
production platform to assist the drilling and completion of oil and gas wells.
Mono hull drilling tender barges were first utilized in the Gulf of Mexico in
11
the 1950's, whereby derrick equipment sets were placed on an offshore platform
and operated from the tender barge. Due to significant weather down time, mono
hull tender barges were eventually replaced in the Gulf of Mexico by new designs
including self-erecting platform rigs and jack-up rigs. In the mid 1990's the
first purpose built semi-tender was introduced in Malaysia. The performance in
the South China Sea of semi-tender units was the basis for Drillmar's plan to
utilize semi-tenders as a means to significantly reduce the cost of deepwater
oil and gas development. Drillmar has developed a proprietary mooring solution
and has patents pending to protect this technology. The semi-tender solution can
also be applied to shallower water projects by providing customers high
efficiency through its ability to mobilize or demobilize in less than
twenty-four hours.
In 2000, Drillmar acquired a 1% general partner interest in Zephyr
Drilling, Ltd., a Texas limited partnership ("Zephyr"). Zephyr owns a
semi-submersible drilling rig that it acquired for approximately $7.6 million.
At December 31, 2000, the Company's investment in Drillmar and the partnership
consisted of $25,000 cash and the contribution of management and administrative
services, estimated at $50,000.
In May 2001, the Company increased its ownership in Drillmar from 37.5%
to 64%. Consideration paid by the Company included cash of approximately
$131,000, and contribution of services in the amount of $434,000.
Effective January 2001, the Company entered into an agreement with
Drillmar whereby it agreed to provide office space and certain management and
administrative services to Drillmar for approximately $40,000 per month. The
Company used the payments it is entitled to receive under this agreement to fund
its investment in Drillmar. The funding of the Company's investment in Drillmar
was completed in October 2001.
In September 2001, Drillmar entered into a merger agreement and merged
with Zephyr. As a result of the merger, the Company's interest in Drillmar
decreased from 64% to 12.8%.
Ivar Siem, Chairman of the Company, and Harris A. Kaffie, a director of
the Company were limited partners of Zephyr. After the merger between Drillmar
and Zephyr, Messrs Siem and Kaffie were owners of 30.3% and 30.6%, respectively,
of Drillmar's common stock. During 2001, Messrs. Siem and Kaffie provided
funding to Drillmar of $525,000 and $425,000, respectively, and were issued
unsecured promissory notes from Drillmar. The promissory notes are due June 30,
2002 and bear interest at the rate of 10% per annum. Along with the promissory
notes, Drillmar issued detachable warrants to Messrs. Siem and Kaffie of 52,500
and 42,500, respectively. Each warrant provides for the purchase of one share of
Drillmar's common stock at $5 per share and are exercisable through January 31,
2005.
The Company records its investment in Drillmar using the equity method
of accounting due to the Company providing management services to Drillmar.
Under the equity method, investments are recorded at cost plus the Company's
equity in undistributed earnings and losses after acquisition. Intercompany
gains and losses are eliminated.
Pipeline Operations and Activities
The Company's pipeline assets are held and operations conducted by Blue
Dolphin Pipe Line Company. Effective January 1, 2002, Mission Energy and
Buccaneer Pipe Line, who held pipeline assets, were merged into Blue Dolphin
Pipe Line Company, where all of the Company's pipeline assets are now held.
Blue Dolphin Pipeline System. As of December 31, 2001 the Company,
through Blue Dolphin Pipe Line Company, owned a 50% undivided interest in the
Blue Dolphin Pipeline System (the "Blue Dolphin System"), which, as a result of
a recent acquisition, increased to an 83% interest in 2002. The Blue Dolphin
12
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 gas and condensate from
various offshore fields in the Galveston Area in the Gulf of Mexico to shore
facilities located in Freeport, Texas. After processing, the gas is transported
to an end user and a major intrastate pipeline system with further downstream
tie-ins to other intrastate and interstate pipeline systems and end users. The
Buccaneer Pipeline, an 8" condensate pipeline, transports condensate from the
storage tanks to the Company's barge loading terminal on the Intracoastal
Waterway near Freeport, Texas for sale to third parties.
The Blue Dolphin Pipeline consists of two segments. The offshore
segment transports both gas and condensate and is comprised of approximately 34
miles of 20-inch pipeline from a platform in Galveston Area Block 288 to shore.
An additional 4 miles of 20 inch pipeline connect the offshore segment to the
shore facility at Freeport, Texas. In 2001, Blue Dolphin Pipe Line Company
installed a platform in Galveston Area Block 288 to operate and maintain the
Blue Dolphin Pipeline System as a result of the Company's decision to abandon
and remove the Buccaneer Field platforms in Galveston Area Blocks 288 and 296,
which were previously used to operate and maintain the Blue Dolphin Pipeline
System. The installation of the platform and its connection to the Blue Dolphin
Pipeline System cost approximately $1.7 million net to the Company's 50%
interest. Additionally, the offshore segment includes 5 field gathering lines
totaling approximately 27 miles, connected to the main 20-inch line. This
system's onshore segment consists of approximately 2 miles of 16-inch pipeline
for transportation of gas from the shore facility to a sales point at a
Freeport, Texas chemical plants' complex and intrastate pipeline system tie-in.
Various fees are charged to producer/shippers for provision of
transportation and shore facility services. Blue Dolphin System gas throughput
averaged approximately 16% of capacity during 2001. Current system capacity is
approximately 160 MMcf per day of gas and 7,000 Bbls per day of condensate.
During 2001, 100% of gas and condensate volumes transported were attributable to
production from third party producer/shippers. See Note 12 to Consolidated
Financial Statements included in Item 7.
Black Marlin Pipeline System. In January 2001, the Company and its
partners, MCNIC and WBI Holdings, Inc. ("WBI") sold the Black Marlin Pipeline
System and the High Island Block A-5 pipeline to Williams Field Services for
$9.3 million. The Company through wholly-owned subsidiaries owned a 50% interest
in these assets and received $4.6 million for its interest. The Black Marlin
Pipeline System included the Black Marlin Pipeline, onshore facilities for
condensate and gas separation and dehydration, 3,000 Bbls of above ground
tankage for storage of condensate, a truck loading facility for oil and
condensate, and five acres of land in Galveston County, Texas where the Black
Marlin Pipeline comes ashore and on which are located the pipeline system's
shore facilities.
Various fees were charged during 2000 to producer/shippers for
provision of transportation and shore facility services. Black Marlin Pipeline
System gas throughput averaged approximately 46% and 28% of capacity during 2000
and 1999, respectively. Black Marlin Pipeline System capacity is approximately
200 MMcf per day of gas and 1,500 Bbls per day of condensate. During 2000 and
1999, all gas and condensate volumes were attributable to production from third
party producer/shippers.
In July 2000, the Company reached an agreement to provide
transportation services for Vastar Resources, Inc. in High Island Area Block
A-5, offshore Texas in the Gulf of Mexico. To accommodate this production, the
13
Company constructed a 3.4 mile 12" diameter pipeline from the production
platform in High Island Area Block A-5 to the Black Marlin Pipeline. The cost to
construct the pipeline was approximately $1.9 million, $.9 million net to the
Company's 50% interest in the pipeline. The pipeline was completed in September
2000.
Other. In July 2000, the Company acquired an 83% ownership interest in
an 8-inch, 12.78 mile pipeline extending from Galveston Area Block 350 to an
interconnect to a transmission pipeline in Galveston Area Block 391 (the "GA350
Pipeline"), approximately 14 miles south of the Company's Blue Dolphin Pipeline
for $224,000. The pipeline currently transports approximately 3,000 Mcf of gas
per day. WBI acquired the remaining 17% interest in this pipeline.
The Company also holds an 83% undivided interest in the currently
inactive Omega Pipeline. WBI holds a 17% interest. The Omega Pipeline originates
in West Cameron Block 342 and extends to High Island Area, East Addition Block
A-173, where it was previously connected to the High Island Offshore System
("HIOS"). The line could either be reconnected to HIOS, or a lateral pipeline
could be constructed connecting into the Black Marlin Pipeline, approximately 14
miles to the west. Reactivation of the Omega Pipeline will be dependent upon
future drilling activity in the vicinity and successfully attracting reserves to
the system.
The economic return to the Company on its pipeline system investments
is solely dependent upon the amounts of gas and condensate gathered and
transported through the pipeline systems. Competition for provision of gathering
and transportation services, similar to those provided by the Company, is
intense in the market areas served by the Company. See Competition below. Since
contracts for provision of such services between the Company and third party
producer/shippers are generally for a specified time period, there can be no
assurance that current or future producer/shippers will not subsequently tie-in
to alternative transportation systems or that current rates charged by the
Company will be maintained in the future. The Company actively markets gathering
and transportation services to prospective third party producer/shippers in the
vicinity of its pipeline systems. Future utilization of the pipelines and
related facilities will depend upon the success of drilling programs around the
pipelines, and attraction, and retention, of producer/shippers to the systems.
Midstream Development Projects
Offshore Crude Oil Terminalling
The Company's investment in and development of offshore crude oil
terminals is through Petroport, Inc. Petroport, Inc. holds proprietary
technology, represented by certain patents issued and or pending, associated
with the development and operation of a deepwater crude oil and products
terminal and offshore storage facility.
The Company's efforts have focused on two prospective market areas for
locating such a facility: the Greater Houston area, including the Freeport,
Texas and Houston Ship Channel market (the "Petroport" project); and the
Beaumont - Port Arthur, Texas and Westlake - Lake Charles, Louisiana market (the
"Sabine Seaport" project).
The Company's efforts to advance its Petroport and Sabine Seaport
projects has centered on development of market support, evidenced by firm
throughput commitments to use the facilities when completed, and attracting
partners to participate in and bear the development costs of these projects. The
Company has actively been soliciting major oil companies that import large
volumes of crude oil, and various other entities to participate in the ownership
and further costs of project development. Uncertainties associated with recent
and anticipated industry consolidations, the extent of displacement of long haul
14
imported barrels by future deepwater Gulf of Mexico production, and onshore
logistics considerations, have resulted in the deferring of throughput
commitment decisions by refiners from whom the Company has sought long term
commitments for these projects.
Given the current lack of market support for the projects, which
support is not expected over the next twelve months, the Company has elected to
record a full impairment of $1.9 million of its investment in both the Petroport
and Sabine Seaport projects. The Company, however, will continue market
surveillance activities and seek prospective partners to jointly develop an
offshore terminal project, if market conditions warrant such development in the
future.
Avoca Gas Storage Project
In November 1999, the Company and WBI formed New Avoca Gas Storage, LLC
("New Avoca"), 25% owned and managed by the Company and 75% owned by WBI, and
acquired the assets of Avoca Gas Storage, Inc. The Company records its
investment in New Avoca by using the equity method of accounting.
The Avoca salt cavern gas storage project was conceived as a 5 Bcf
working gas storage facility located south of Rochester near the town of Avoca,
New York. Its design provides for 250 Mmcf per day injection and 500 Mmcf per
day withdrawal capacities, with deliveries into the Tennessee Gas Pipeline HC400
24" line and other area transmission lines.
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"). In November 1999, the Company and WBI
acquired the Avoca gas storage assets for $400,000 ($100,000 net to the
Company's interest) from Northeastern. Additionally, a contingent payment of $.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 if
Northeastern successfully settled 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 $40,000 previously
paid by New Avoca. New Avoca can elect to liquidate the project at any time.
The existing New Avoca assets include:
o Approximately 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 9 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 gas, fresh water is injected
from the surface to dissolve the salt formations below. The brine solution
produced by this process must be continuously brought to the surface and then
injected into underground disposal wells or disposed of in some other manner.
The disposal wells must have sufficient porosity and permeability to accept the
injected brine at a rate at least consistent with the rate at which brine is
being produced during the creation of the salt caverns. The original owners of
15
the Avoca gas storage assets conducted tests to determine the rate that the
disposal wells would accept brine. New Avoca believes that the testing
procedures used by the original owners of the project to analyze the rate at
which the disposal wells could accept brine may have been flawed as a result of
the accelerated pace at which the tests were conducted, and therefore yielded
test results that were uncertain and did not conclusively support an acceptable
rate of brine disposal. The original owners of the Avoca gas storage assets
encountered technical and other difficulties as a result of the uncertainty of
their test results. New Avoca is reviewing additional brine disposal options
that could be used to accelerate the creation of the salt caverns.
During 2000, New Avoca completed an analysis of the project. Based on
this analysis and recent technological advances, New Avoca believes the disposal
wells will be capable of handling the more moderate rates of brine injection
expected to be produced under its proposed construction schedule. From October
2000 through February 10, 2001, New Avoca tested the disposal wells to determine
the rate that these wells will accept brine. On February 12, 2001, as a result
of mild seismic activity in the area surrounding Avoca, the New York State
Department of Environmental Conservation requested that New Avoca stop testing
the disposal wells. New Avoca stopped testing the wells, and does not plan on
further testing at this time. As a viable solution to the brine disposal, New
Avoca has studied the construction of a brine pipeline to deliver brine to a
salt plant. New Avoca believes that a combination of the use of disposal wells
and brine deliveries by pipeline appears to be the most feasible means of brine
disposal. Efforts are underway to negotiate agreements with area salt plants to
take the brine. Simultaneously, efforts to attract an additional equity partner
are also being pursued. If a partner is obtained to acquire an equity interest
in the project, New Avoca will proceed with permitting and preliminary
engineering. New Avoca estimates that it will take between 9 months to 15 months
for approval of its permit, and between 21 months to 2 years after approval of
its permit to contract and begin operations at partial capacity, with another 2
years needed to complete construction and reach the full 5 BCF capacity. If New
Avoca can not attract an equity partner, other financing must be obtained to
proceed with the project. There can be no assurance that New Avoca will be able
to attract new investors or obtain additional financing necessary to proceed
with the project.
Customers
The Company generates revenues from both of its primary business
segments. Revenues from major customers exceeding 10% of revenues were as
follows for 2001. In 2000, no customer accounted for more than 10% of the
Company's total revenues.
Oil and gas
sales and Pipeline
operating fees operations Total
-------------- ---------- -------
Year ended December 31, 2001:
Houston Exploration $ -- 639,975 639,975
Competition
The oil and gas industry is highly competitive in all segments.
Increasingly vigorous competition occurs among oil, gas and other energy
sources, and between producers, transporters, and distributors of oil and gas.
Competition is particularly intense with respect to the acquisition of desirable
producing properties and the marketing of oil and gas production. There is also
competition for the acquisition of oil and gas leases suitable for exploration
and for the hiring of experienced personnel to manage and operate the Company's
assets. Several highly competitive alternative transportation and delivery
options exist for current and potential customers of the Company's traditional
gas and oil gathering and transportation business as well as for refiners,
16
shippers, marketers and producers of crude oil whom the Company's proposed
Petroport and Sabine Seaport facilities would serve. Gas storage customers who
would use the proposed Avoca Gas Storage system have alternatives, including
depleted reservoir and other salt cavern storage systems. Competition also
exists with other industries in supplying the energy and fuel needs of
consumers.
Markets
The availability of a ready market for gas and oil, and the prices of
such gas and oil, depends upon a number of factors, which are beyond the control
of the Company. These include, among other things, the level of domestic
production, actions taken by foreign oil and gas producing nations, the
availability of pipelines with adequate capacity, the availability of vessels
for direct shipment, lightering and transshipment and other means of
transportation, the availability and marketing of other competitive fuels,
fluctuating and seasonal demand for oil, gas and refined products, and the
extent of governmental regulation and taxation (under both present and future
legislation) of the production, importation, refining, transportation, pricing,
use and allocation of oil, gas, refined products and alternative fuels.
Accordingly, in view of the many uncertainties affecting the supply and
demand for crude oil, gas and refined petroleum products, it is not possible to
predict accurately the prices or marketability of the gas and oil produced for
sale or prices chargeable for transportation, terminalling and storage services,
which the Company provides or may provide in the future.
Governmental Regulation
The production, processing, marketing, and transportation of oil and
gas, and the development of terminalling and storage of crude oil and gas by the
Company are subject to federal, state and local regulations which can have a
significant impact upon the Company's overall operations.
Federal Regulation of Natural Gas Transportation. The transportation
and resale of gas in interstate commerce have been regulated by the Natural Gas
Act, the Natural Gas Policy Act and the rules and regulations promulgated by
FERC. In the past, the federal government has regulated the prices at which gas
could be sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act,
which removed all remaining Natural Gas Act and Natural Gas Policy Act price and
non-price controls affecting producer sales of gas, effective January 1, 1993.
Congress could, however, reenact price controls in the future.
The price and terms for access to pipeline transportation is subject to
extensive federal regulation. In April 1992, the FERC issued Order No. 636,
beginning a series of related orders, which required interstate pipelines to
provide open-access transportation on a basis that is equal for all gas
suppliers. The FERC has stated that it intends Order No. 636 to foster increased
competition within all phases of the gas industry. Order No. 636 affects how
buyers and sellers gain access to the necessary transportation facilities and
how gas is sold in the marketplace. In 2000, the FERC issued Order No. 637
which, among other things, will permit pipelines to file for peak/off-peak and
term differentiated rate structures and changed existing regulations relating to
scheduling procedures, capacity segmentation, pipeline imbalance processes and
penalties, and pipeline reporting requirements.
The Company cannot predict whether the FERC's actions will achieve the
goal of increasing competition in the gas markets or how these, or future
regulations will affect its operations or competitive position. However, the
Company does not believe that any action taken will affect it in any way that
materially differs from the way that such action affects the Company's
competitors.
17
Of the gas pipelines owned by the Company in 2001, only the Black
Marlin Pipeline (sold in January 2001) was subject to rules and regulations of
the Natural Gas Act. As a result, its gas transportation service and pricing
service were subject to the regulatory jurisdiction of the FERC.
All of the Company's pipelines located offshore in federal waters are
subject to the requirements of the Outer Continental Shelf Lands Act ("OCSLA").
FERC has stated that nonjurisdictional gathering lines, as well as interstate
pipelines, are fully subject to the open access and nondiscrimination
requirements of OCSLA's Section 5, which generally authorizes the FERC to insure
that gas pipelines on the Outer Continental Shelf will transport for non-owner
shippers in a nondiscriminatory manner and will be operated in accordance with
certain pro-competitive principles. More recently, the FERC has undertaken
several investigations into the nature and extent of its regulatory powers on
the Outer Continental Shelf. It issued a policy statement on Outer Continental
Shelf pipelines reaffirming the requirement that all pipelines provide
nondiscriminatory service. In 2000, FERC issued Order 639, formally imposing new
OCSLA regulations on offshore pipelines not otherwise subject to its Natural Gas
Act jurisdiction. Order 639's requirements, which largely entail reporting and
disclosure obligations to FERC, contain certain exemptions for, among other
things, an offshore pipeline system that "feeds into a facility where gas is
first collected or a facility where gas is first separated, dehydrated, or
otherwise processed."
Further FERC initiatives concerning possibly diminished Natural Gas Act
regulation of pipelines on the OCS and/or broader regulation under the OCSLA
remain possible and could cause increased regulatory compliance costs. Since all
of the Companies' offshore pipelines fall within the exemption for feeder
facilities and already operate on the basis required under OCSLA, the Company
does not anticipate significant changes directly resulting from requirements
concerning nondiscriminatory open access transportation. Moreover, if an
offshore pipeline's throughput increases to the extent that the pipeline's
capacity is completely utilized, under OCSLA, the FERC may be petitioned to
direct capacity allocation on the pipeline. Accordingly, the Company cannot
predict how application of the OCSLA to its pipelines may ultimately affect
Company operations.
Aside from the OCSLA requirements and federal safety and operational
regulations, regulation of gas gathering activities is primarily a matter of
state oversight. Regulation of gathering activities in Texas includes various
transportation, safety, environmental and non-discriminatory purchase/transport
requirements.
Federal Regulation of Oil Pipelines. The Company's operation of the
Buccaneer Pipeline is subject to a variety of regulations promulgated by the
FERC and imposed on all oil pipelines pursuant to federal law. In particular,
the rates chargeable by the Company are subject to prior approval by the FERC,
as are operating conditions and related matters contained in the Company's
transportation tariffs which are on file with the FERC. In 1993, the FERC issued
Order No. 561, which was intended to simplify oil pipeline ratemaking, largely
through use of a ceiling based on an indexing system. At the end of 2000, the
Commission issued an order based on a five-year review of the indexing system,
affirming this approach to oil pipeline ratemaking. Because Buccaneer Pipeline
has not taken action to become subject to Order No. 561 or Order No. 572
concerning market-based rates for oil pipelines, the Company cannot predict
whether or how an indexed or market-based rate system will affect the Buccaneer
Pipeline's rates.
Safety and Operational Regulations. The operations of the Company are
generally subject to safety and operational regulations administered primarily
by the MMS, the U.S. Department of Transportation, the U.S. Coast Guard, the
FERC and/or various state agencies. Currently, the Company believes that it is
18
in material compliance with the various safety and operational regulations that
it is subject to. However, as safety and operational regulations are frequently
changed, the Company is unable to predict the future effect changes in these
regulations will have on its operations, if any.
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 and Sabine Seaport
facilities, 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, 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 and Sabine Seaport facilities 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 would be issued a Deepwater
Port license and other necessary permits, if such are sought.
19
Federal Oil and Gas Leases. The Company's operations on offshore
federal 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.
The Company's leases in the OCS provide for royalty payments on gas
production calculated at some fraction of the value of the gas produced. OCS
lessees have challenged the Department of Interior's rules and regulations which
prohibit the natural gas producer from subtracting downstream marketing costs
from royalties owed to the Federal government. The U.S. Court of Appeals for the
District of Columbia on February 8, 2002 reversed the U.S. District Court for
the District of Columbia and upheld the Department of Interior's rule that
producers may not deduct costs such as downstream marketing costs, including
aggregator/marketing fees or intra-hub transfer fees charged by pipelines to
track paper transactions at a pipeline junction (not for physical transfers).
With respect to any Company operations conducted on offshore federal
leases, liability may generally be imposed under OCSLA for costs of clean-up and
damages caused by pollution resulting from such operations, other than damages
caused by acts of war or the negligence of third parties. Under certain
circumstances, including but not limited to conditions deemed a threat or harm
to the environment, the MMS may also require any Company operations on federal
leases to be suspended or terminated in the affected area. Furthermore, the MMS
generally requires that offshore facilities be dismantled and removed within one
year after production ceases or the lease expires.
Environmental Regulation. The Company's activities with respect to (1)
exploration, development and production of oil and natural gas and (2) the
operation and construction of pipelines, plants, and other facilities for the
transportation and processing, and storage of crude oil, natural gas and natural
gas liquids are subject to stringent environmental regulation by local, state
and federal authorities, including the U.S. Environmental Protection Agency
("EPA"). Such regulation has increased the cost of planning, designing,
drilling, operating and in some instances, abandoning wells and related
equipment. Similarly, such regulation has also increased the cost of design,
construction, and operation of crude oil and natural gas pipelines and
processing facilities. Although the Company believes that compliance with
existing environmental regulations will not have a material adverse affect on
operations or earnings, there can be no assurance that significant costs and
liabilities, including civil and criminal penalties, will not be incurred.
Moreover, future developments, such as stricter environmental laws and
regulations or claims for personal injury or property damage resulting from the
Company's operations, could result in substantial costs and liabilities. It is
not anticipated that, in response to such regulation, the Company will be
required in the near future to expend amounts that are material relative to its
total capital structure. However, it is possible that the costs of compliance
with environmental and health and safety laws and regulations will continue to
increase. Given the frequent changes made to environmental and health and safety
regulations and laws, the Company is unable to predict the ultimate cost of
compliance.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") imposes liability, without regard to fault or the legality of the
original conduct, on responsible parties with respect to the release or
threatened release of a "hazardous substance" into the environment. Responsible
parties, which include the owner or operator of a site where the release
occurred and persons that disposed or arranged for the disposal of a hazardous
substance at the site, are liable for response and remediation costs and for
damages to natural resources. Petroleum and natural gas are excluded from the
definition of "hazardous substances;" however, this exclusion does not apply to
all materials associated with the production of petroleum or natural gas. At
this time, neither the Company nor any of its predecessors has been designated
as a potentially responsible party under CERCLA.
The federal Resource Conservation and Recovery Act ("RCRA") and its
state counterparts regulate solid and hazardous wastes and impose civil and
criminal penalties for improper handling and disposal of such wastes. EPA and
20
various state agencies have promulgated regulations that limit the disposal
options for such wastes. Certain wastes generated by the Company's oil and gas
operations are currently exempt from regulation as "hazardous wastes," but in
the future could be designated as "hazardous wastes" under RCRA or other
applicable statutes and therefore may become subject to more rigorous and costly
requirements.
The Company currently owns or leases, or has in the past owned or
leased, numerous properties used for the exploration and production of oil and
gas or used to store and maintain equipment regularly used in these operations.
Although the Company's past operating and disposal practices at these properties
were standard for the industry at the time, hydrocarbons or other substances may
have been disposed of or released on or under these properties or on or under
other locations. In addition, many of these properties have been operated by
third parties whose waste handling activities were not under the Company's
control. These properties and any waste disposed thereon may be subject to
CERCLA, RCRA, and analogous state laws which could require the Company to remove
or remediate wastes and other contamination or to perform remedial plugging
operations to prevent future contamination.
The Oil Pollution Act of 1990 ("OPA") and regulations promulgated
thereunder include a variety of requirements related to the prevention of oil
spills and impose liability for damages resulting from such spills. OPA imposes
liability on owners and operators of onshore and offshore facilities and
pipelines for removal costs and certain public and private damages arising from
a spill. OPA establishes a liability limit for onshore facilities of $350
million and for offshore facilities of all removal costs plus $75 million, and
lesser liability limits for vessels depending upon their size. In August 1995,
the DOT issued a Rulemaking under OPA providing that the Secretary of
Transportation can set the liability limit and associated Certificate of
Financial Responsibility requirement for Deepwater Ports from between $350.0
million and $50.0 million concurrent with the overall processing of the DWPA
license application. Development of the liability limit would be based upon
engineering and environmental analysis provided during the licensing process. A
party cannot take advantage of the liability limits if the spill is caused by
gross negligence or willful misconduct or resulted from a violation of federal
safety, construction, or operating regulations. If a party fails to report a
spill or cooperate in the cleanup, liability limits likewise do not apply. OPA
imposes ongoing requirements on responsible parties, including proof of
financial responsibility for potential spills. The amount of financial
responsibility required depends upon a variety of factors including the type of
facility or vessel, its size, storage capacity, oil throughput, proximity to
sensitive areas, type of oil handled, history of discharges, worst-case spill
potential and other factors. The Company believes it has established adequate
financial responsibility. While the financial responsibility requirements under
OPA may be amended to impose additional costs on the Company, the impact of such
a change is not expected to be any more burdensome on the Company than on others
similarly situated.
The Clean Air Act and state air quality laws and regulations contain
provisions that impose pollution control requirements on emissions to the air
and require permits for construction and operation of certain emissions sources,
including sources located offshore. The Company may be required to incur capital
expenditures for air pollution control equipment in connection with maintaining
or obtaining operating permits and approvals addressing emission-related issues,
although the Company does not expect to be materially adversely affected by such
expenditures.
The Clean Water Act ("CWA") regulates the discharge of pollutants to
waters of the United States and imposes permit requirements on such discharges,
including discharges to wetlands. Federal regulations under the CWA and OPA
require certain owners or operators of facilities that store or otherwise handle
oil, to prepare and implement spill prevention, control and countermeasure plans
21
and facility response plans relating to the possible discharge of oil into
surface waters. With respect to certain of the Company's operations, it is
required to prepare and comply with such plans and to obtain and comply with
permits. The CWA also prohibits spills of oil and hazardous substances to waters
of the United States in excess of levels set by regulations and imposes
liability in the event of a spill. State laws further provide varying civil and
criminal penalties and liabilities for the spills to both surface and
groundwaters. The Company believes it is in substantial compliance with the
requirements of the CWA, OPA, and state laws, and that any non-compliance would
not have a material adverse effect on the Company.
Legislation and Rulemaking. In October 1996 the U.S. Congress enacted
the Coast Guard Authorization Act of 1996 (P.L. 104-324) which amended the OPA
to establish requirements for evidence of financial responsibility for certain
offshore facilities, other than Deepwater Ports. The amount required is $35.0
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.
Federal and state legislative rules and regulations are pending that,
if enacted, could significantly affect the oil and gas industry. It is
impossible to predict which of those federal and state proposals and rules, if
any, will be adopted and what effect, if any, they would have on the operations
of the Company.
In addition, various federal, state and local laws and regulations
covering the discharge of materials into the environment, occupational health
and safety issues, or otherwise relating to the protection of public health and
the environment, may affect the Company's operations, expenses and costs. The
trend in such regulation has been to place more restrictions and limitations on
activities that may impact the general or work environment, such as emissions of
pollutants, generation and disposal of wastes, and use and handling of chemical
substances. It is not anticipated that, in response to such regulation, the
Company will be required in the near future to expend amounts that are material
relative to its total capital structure. However, it is possible that the costs
of compliance with environmental and health and safety laws and regulations will
continue to increase. Given the frequent changes made to environmental and
health and safety regulations and laws, the Company is unable to predict the
ultimate cost of compliance.
RISK FACTORS
Oil and gas prices are volatile and a substantial and extended decline
in the price of oil and gas would have a material adverse effect on the Company.
The Company's revenues, profitability, operating cash flow, the
carrying value of its oil and gas properties and its potential for growth are
largely dependent on prevailing oil and gas prices. Prices for oil and gas are
subject to large fluctuations in response to relatively minor changes in the
supply and demand for oil and gas, uncertainties within the market and a variety
of other factors beyond the Company's control. These factors include:
o weather conditions in the United States;
o the condition of the United States economy;
o the actions of the Organization of Petroleum Exporting
Countries;
o governmental regulation;
22
o political stability in the Middle East and elsewhere;
o the foreign supply of oil and gas;
o the price of foreign imports; and
o the availability of alternate fuel sources.
In addition to decreasing the Company's revenue and operating cash
flow, low or declining oil and gas prices could have collateral effects that
could adversely affect the Company, including the following:
o reducing the overall volumes of oil and gas that the Company
can produce from its oil and gas reserves economically;
o resulting in an impairment to the historical carrying value of
the Company's oil and gas properties, which could compel the
Company, under generally accepted accounting principles, to
recognize a significant write down of the carrying value of
its oil and gas assets on its balance sheet and an associated
charge to its income;
o increasing the Company's dependence on external sources of
capital to meet its cash needs; and
o impairing the Company's ability to obtain needed equity.
Volatile oil and gas prices also make it difficult to estimate the
value of producing properties the Company may acquire and also make it difficult
for the Company to budget for and project the return on acquisitions and
development and exploitation projects.
An adverse result from the H&N Gas litigation could effect the
Company's financial condition.
If American Resources experiences an adverse outcome with respect to
the H&N Gas litigation, American Resources' ability to contribute to the
Company's consolidated financial operating results would be adversely affected.
An adverse outcome could require the Company to fund the on-going operations and
cash-flow needs of American Resources. Furthermore, if the H&N Gas litigation
continues for a prolonged period the Company would incur significant legal
expenses, which could have a material adverse effect on the Company's financial
condition.
The Company may be subject to contractual penalties if it is unable to
pay its share of drilling costs.
If the Company lacks and is unable to obtain cash sufficient to pay its
proportionate share of the estimated costs to drill any well in which it owns
less than 100% of the working interest, the Company may be subject to
contractual "non-consent" and other penalties. These penalties may include, for
example, full or partial forfeiture of the Company's interest in the well or a
relinquishment of the Company's interest in production from the well in favor of
the participating working interest owners until the participating working
interest owners have recovered a multiple of the costs which would have been
borne by the Company if it had elected to participate, which often ranges from
400% to 600% of such costs.
23
The Company faces strong competition from larger oil and gas companies
that may negatively affect its ability to carry on operations.
The Company operates in a highly competitive industry. The Company's
competitors include major integrated oil companies, substantial independent
energy companies, affiliates of major interstate and intrastate pipelines and
national and local gas gatherers, many of which possess greater financial and
other resources than the Company. The Company's ability to successfully compete
in the marketplace is affected by many factors.
o Most of the Company's competitors have greater financial
resources than it does, which gives them better access to
sources of capital to acquire and develop oil and gas
properties.
o Most of the Company's competitors have longer operating
histories and have more data generally available to them,
including information relating to oil and gas properties.
o The Company often establishes a higher standard for the
minimum projected rate of return on an investment than some of
its competitors since it cannot afford to absorb certain
risks. The Company believes this puts it at a competitive
disadvantage in acquiring oil and gas properties.
The Company's future success depends, in part, upon its ability to
find, develop and acquire additional oil and gas reserves that are economically
recoverable.
The Company's proved reserves will decline as they are produced unless
it conducts successful exploration or development activities or acquires
properties containing proved reserves. The Company must attempt to increase its
proved reserves even during periods of low oil and gas prices when it is
difficult to raise the capital necessary to finance these activities. There can
be no assurance that the Company's planned development projects and acquisition
activities will result in significant increases in its reserves or that the
Company will drill or participate in the drilling of productive wells at
economic returns. The drilling of oil and gas wells involves a high degree of
risk, especially the risk of dry holes or of wells that are not sufficiently
productive to provide an economic return on the capital expended to drill the
wells. The cost of drilling, completing and operating a well is uncertain, and
the Company's drilling or production may be curtailed or delayed as a result of
many factors.
Undue reliance should not be placed on reserve information because
reserve information represents estimates.
This annual report includes estimates of the Company's oil and gas
reserves and the future net revenues from those reserves which the Company and
its independent petroleum consultants have prepared. Reserve engineering is a
subjective process of estimating the Company's recovery from underground
accumulations of oil and gas that cannot be measured in an exact manner. The
accuracy of the Company's reserve estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Estimates of the Company's economically recoverable oil and gas reserves and of
future net cash flows necessarily depend upon a number of variable factors and
assumptions, such as:
o historical production from the area compared with production
from other producing areas;
o the assumed effects of regulations by governmental agencies;
and
24
o assumptions concerning future oil and gas prices, future operating
costs, severance and excise taxes, development costs and costs to
restore or increase production on a producing well.
In addition, different reserve engineers may make different estimates
of reserve quantities and cash flows based upon the same available data. The
Company's reserve estimates are to some degree speculative. As a result there
may be material variances between the Company's actual results and costs, and
its estimates of:
o the quantities of oil and gas that the Company ultimately
recovers;
o the Company's production and operating costs;
o the amount and timing of the Company's future development
expenditures; and
o the Company's future oil and gas sales prices.
Any significant variance in these assumptions could materially affect the
estimated quantity and value of the Company's reserves reported in this annual
report.
The Company cannot control the activities on properties it does not
operate.
Other companies operate many of the properties in which the Company has
an interest. As a result, the Company will depend on the operator of the wells
to properly conduct lease acquisition, drilling, completion and production
operations. The failure of an operator, or the drilling contractors and other
service providers selected by the operator to properly perform services, could
adversely affect the Company, including the amount and timing of revenues it
receives from its interest.
The Company has and generally anticipates that it will typically own
substantially less than a 50% working interest in its prospects and will
therefore engage in joint operations with other working interest owners. In
instances in which the Company owns or controls less than a majority of the
working interest in a prospect, decisions affecting the prospect could be made
by the owners of more than a majority of the working interest. For instance, if
the Company is unwilling or unable to participate in the costs of operations
approved by a majority of the working interests in a well, the Company's working
interest in the well (and possibly other wells on the prospect) will likely be
subject to contractual "non-consent penalties" such as those described under the
caption "The Company may be subject to contractual penalties if it is unable to
pay its share of drilling costs."
The Company has pursued, and intends to continue to pursue,
acquisitions. The Company's business may be adversely affected if it cannot
effectively integrate acquired operations.
One of the Company's business strategies has been to acquire operations
and assets that are complementary to its existing businesses. Acquiring
operations and assets involves financial, operational and legal risks. These
risks include:
o inadvertently becoming subject to liabilities of the acquired
company that were unknown to the Company when it was acquired,
such as later asserted litigation matters or tax liabilities,
o the difficulty of assimilating operations, systems and
personnel of the acquired businesses, and
25
o maintaining uniform standards, controls, procedures and
policies.
Any future acquisitions would likely result in an increase in expenses. In
addition, competition from other potential buyers could cause the Company to pay
a higher price than it otherwise might have to pay and reduce its acquisition
opportunities. The Company is often out-bid by larger, more capitalized
companies for acquisition opportunities it pursues. Moreover, the Company's past
success in making acquisitions and in integrating acquired businesses does not
necessarily mean it will be successful in making acquisitions and integrating
businesses in the future.
Operating hazards including those peculiar to the marine environment
may adversely affect the Company's ability to conduct business.
The Company's operations are subject to risks inherent in the oil and
gas industry, such as:
o sudden violent expulsions of oil, gas and mud while drilling a
well, commonly referred to as a blowout;
o a cave in and collapse of the earth's structure surrounding a
well, commonly referred to as cratering;
o explosions;
o fires;
o pollution; and
o other environmental risks.
These risks could result in substantial losses to the Company from injury and
loss of life, damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. The Company's offshore
operations are also subject to a variety of operating risks peculiar to the
marine environment, such as hurricanes or other adverse weather conditions and
more extensive governmental regulation. These regulations may, in certain
circumstances, impose strict liability for pollution damage or result in the
interruption or termination of operations.
Losses and liabilities from uninsured or underinsured drilling and
operating activities could have a material adverse effect on the Company's
financial condition and operations.
The Company maintains several types of insurance to cover its
operations, including maritime employer's liability and comprehensive general
liability. Amounts over base coverages are provided by primary and excess
umbrella liability policies with maximum limits of $50.0 million. The Company
also maintains operator's extra expense coverage, which covers the control of
drilled or producing wells as well as redrilling expenses and pollution coverage
for wells out of control.
The Company may not be able to maintain adequate insurance in the
future at rates it considers reasonable or losses may exceed the maximum limits
under the Company's insurance policies. If a significant event that is not fully
insured or indemnified occurs, it could materially and adversely affect the
Company's financial condition and results of operations.
26
Compliance with environmental and other government regulations could be
costly and could negatively impact production and pipeline operations.
The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. These laws and regulations may:
o require the acquisition of a permit before drilling commences;
o restrict the types, quantities and concentration of various
substances that can be released into the environment from
drilling and production activities;
o limit or prohibit drilling and pipeline activities on certain
lands lying within wilderness, wetlands and other protected
areas;
o require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells and abandoning
pipelines; and
o impose substantial liabilities for pollution resulting from
the Company's operations.
The recent trend toward stricter standards in environmental legislation
and regulation is likely to continue. The enactment of stricter legislation or
the adoption of stricter regulation could have a significant impact on the
Company's operating costs, as well as on the oil and gas industry in general.
The Company's operations could result in liability for personal
injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. The Company
could also be liable for environmental damages caused by previous property
owners. As a result, substantial liabilities to third parties or governmental
entities may be incurred which could have a material adverse effect on the
Company's financial condition and results of operations. The Company maintains
insurance coverage for its operations, including limited coverage for sudden and
accidental environmental damages, but the Company does not believe that
insurance coverage for environmental damages that occur over time or complete
coverage for sudden and accidental environmental damages is available at a
reasonable cost. Accordingly, the Company may be subject to liability or may
lose the privilege to continue exploration or production activities upon
substantial portions of its properties if certain environmental damages occur.
The OPA imposes a variety of regulations on "responsible parties"
related to the prevention of oil spills. The implementation of new, or the
modification of existing, environmental laws or regulations, including
regulations promulgated pursuant to the OPA, could have a material adverse
impact on the Company.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used
in the oil and gas industry.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of gas.
27
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Condensate. Liquid hydrocarbons associated with the production of a
primarily gas reserve.
Development well. A well drilled within the proved area of a gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find and produce gas or oil in an
unproved area, to find a new reservoir in a field previously found to be
productive of gas or oil in another reservoir or to extend a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Leasehold interest. The interest of a lessee under an oil and gas
lease.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of gas to one barrel of oil, condensate or gas liquids.
Mmbtu. One million British Thermal Units.
Mmcf. One million cubic feet of gas.
Mmcfe. One million cubic feet equivalent, determined using the ratio of
six Mcf of gas to one Bbl of oil, condensate or gas liquids.
Net revenue interest. The percentage of production to which the owner
of a working interest is entitled.
Nonoperating working interest. A working interest, or a fraction of a
working interest, in a tract where the owner is not the operator of the tract.
Overriding royalty. An interest in oil and gas produced at the surface,
free of the expense of production that is in addition to the usual royalty
interest reserved to the lessor in an oil and gas lease.
Prospect. A specific geographic area which, based on supporting
geological, geophysical or other data and also preliminary economic analysis
using reasonably anticipated prices and costs, is deemed to have potential for
the discovery of oil, gas or both.
Proved developed reserves. Reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved developed reserves are further categorized into two sub-categories,
proved developed producing reserves and proved developed non-producing reserves.
28
Proved developed producing. Reserves sub-categorized as producing are
expected to be recovered from completion intervals which are open and producing
at the time of the estimate.
Proved developed non-producing. Reserves sub-categorized as
non-producing include shut-in and behind pipe reserves. Shut-in reserves are
expected to be recovered from (1) completion intervals which are open at the
time of the estimate but which have not started producing, (2) wells which were
shut-in awaiting pipeline connections or as a result of a market interruption,
or (3) wells not capable of producing for mechanical reasons.
Proved reserves. The estimated quantities of oil, gas and condensate
that geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions.
Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells or from existing wells where a relatively major expenditure is
required for recompletion.
Reversionary interest. A form of ownership interest in property that
reverts back to the transferor after expiration of an intervening income
interest or the occurrence of another triggering event.
Royalty interest. An interest in a gas and oil property entitling the
owner to a share of gas and oil production free of costs of production.
Undivided Interest. A form of ownership interest in which more than one
person concurrently owns an interest in the same oil and gas lease or pipeline.
Working interest. The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and receive a
share of production.
Item 2. Properties
Information appearing in Item 1 describing the Company's oil and gas
properties under the caption "Business 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 expiring April 30, 2002, a division office in New Orleans,
Louisiana. The New Orleans office was closed in January 2002. The Company's
aggregate annual lease payment obligations under these leases are $186,485.
Item 3. Legal Proceedings
On May 8, 2000, American Resources 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, Limited
Partnership, et al. v. Richard Hale, 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 gas purchase options and 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 gas to perform. H&N
further alleges that American Resources and Hale colluded with respect to swap
29
transactions that were designed to benefit American Resources at the expense of
H&N Gas. H&N further alleges civil conspiracy against all the defendants. H&N is
seeking approximately $6.2 million in actual damages plus treble damages,
punitive damages and prejudgment interest against ARO directly. As a result of
its conspiracy allegation, H&N also contends that all defendants are jointly and
severally liable for over $40.0 million dollars in actual damages plus treble
damages, punitive damages and prejudgment interest. American Resources intends
to vigorously defend this claim.
Item 4. Submission of Matters to a Vote of Security Holders
The Company's annual meeting of shareholders was held on December 13,
2001. The matters that were voted upon at the meeting, and the number of votes
cast for, against or withheld, as well as the number of abstentions and broker
non-votes, as to such matters, where applicable, are set forth below.
Votes Votes Votes Broker
For Against Withheld Abstentions Non-Votes
----------- ----------- ----------- ----------- -----------
Election of Directors
Ivar Siem 3,051,097 16 1,883,819 0 1,080,796
Robert L. Barbanell 3,051,097 16 1,883,819 0 1,080,796
Michael S. Chadwick 3,051,097 16 1,883,819 0 1,080,796
Harris A. Kaffie 3,051,097 16 1,883,819 0 1,080,796
Robert D. Wagner 3,051,097 16 1,883,819 0 1,080,796
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters
The Company's common stock trades in the over-the-counter market and is
quoted on the NASDAQ Small Cap Market under the symbol "BDCO". As of March 22,
2002, there were an estimated 678 stockholders of record and the Company
estimates there are more than 1,000 beneficial owners of its common stock.
NASDAQ quotations reflect inter-dealer prices, without adjustment for retail
mark-ups, markdowns or commissions and may not represent actual transactions.
The following table sets forth, for the periods indicated, the high and low bid
price for the common stock as reported by the NASDAQ.
High Low
---- ---
Quarter Ended March 31, 2000 ............. $ 6.38 $ 5.00
Quarter Ended June 30, 2000 ............. $ 6.13 $ 4.50
Quarter Ended September 30, 2000............. $ 5.56 $ 2.75
Quarter Ended December 31, 2000 ............. $ 5.56 $ 2.50
Quarter Ended March 31, 2001 ............. $ 5.19 $ 3.25
Quarter Ended June 30, 2001 ............. $ 4.95 $ 3.80
Quarter Ended September 30, 2001............. $ 4.31 $ 2.81
Quarter Ended December 31, 2001 ............. $ 3.40 $ 1.60
The Company has not declared or paid any dividends on the Common Stock
since its incorporation. The Company currently intends to retain earnings for
its capital needs and expansion of its business and does not anticipate paying
cash dividends on the Common Stock in the foreseeable future. Previously, the
Company was restricted, pursuant to its loan agreement from paying dividends on
the Common Stock if there was an outstanding balance under the loan agreement.
Any loan agreements which the Company may enter into in the future will likely
contain restrictions on the payment of dividends on its' Common Stock. Future
30
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.
Item 6. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following is a review of certain aspects of the financial condition
and results of operations of the Company and should be read in conjunction with
the Consolidated Financial Statements included in Item 7 and Item 1. Business.
Anticipated Cash Requirements
Historically, the Company has relied on the proceeds from the sale of
assets and capital raised from the issuance of debt and equity securities to
individual investors and related parties to sustain its operations. The Company
incurred net losses of $2,649,142 and $10,135,120 during the years ended
December 31, 2001 and 2000, respectively. Recent losses have resulted in an
accumulative deficit of $21,021,859 at December 31, 2001. The Company also has a
working capital deficiency of approximately $1.2 million. These factors combined
with the cash requirements inherent in the Company's businesses raise
substantial doubt about its ability to continue as a going concern. The
Company's long-term viability as a going concern is dependent upon the following
key factors as follows:
o Its ability to raise capital to meet current commitments and
fund the continuation of our business operations; and
o Its ability to ultimately achieve profitability and cash flows
from operations in amounts that will sustain its operations.
The following are summaries of certain of the Company's contractual
cash obligations and other commercial cash commitments at December 31, 2001
(amounts in thousands).
31
Payments Due by Period
----------------------
Contractual Less than After
Obligations Total 1 year 1-3 years 4-5 years 5 years
----------- ----------- ----------- ----------- ----------- -----------
Long-Term Debt $ -- -- -- -- --
Other Contractual
Obligations 5,059 2,986 1,877 196 --
----------- ----------- ----------- ----------- -----------
Total Contractual
Cash Obligations $ 5,059 2,986 1,877 196 --
=========== =========== =========== =========== ===========
Amount of Commitment Expiration Per Period
------------------------------------------
Other Commercial Less than After
Commitments Total 1 year 1-3years 4-5 years 5 years
----------- ----------- ----------- ----------- ----------- -----------
Long-Term Debt $ -- -- -- -- --
Other Commercial
Obligations 2,000 2,000 -- -- --
----------- ----------- ----------- ----------- -----------
Total Commercial
Cash Obligations $ 2,000 2,000 -- -- --
=========== =========== =========== =========== ===========
Prior to the decrease in production in the High Island A-7 field and
the corresponding delay in the Company's receipt of revenues from its
reversionary working interest in this field, the Company believed that it would
have adequate capital to meet its obligations and operating needs for 2002.
However, due to the occurrence of these events, the Company believes that it
will need to raise between $2.0 and $3.0 million of capital to meet its
obligations and working capital requirements in fiscal 2002. The Company will
have to either:
o sell assets;
o seek external financing by issuing equity or debt securities;
or,
o a combination of the above.
There can be no assurance that the Company will be able to raise
additional capital or that it will be able to raise additional capital on
commercially acceptable terms. The Company's inability to raise additional
capital may cause it to reduce the level of its operations and would have a
material adverse effect on its financial condition, ability to meet its
obligations and operating needs and results of operations. As a result of
potential liquidity problems, its auditors, Mann Frankfort Stein & Lipp CPAs,
L.L.P. added an explanatory paragraph in their opinion on the Company's
financial statements for the years ended December 31, 2001 and 2000, indicating
that substantial doubt exists about its ability to continue as a going concern.
See Note 2 of the Consolidated Financial Statements.
32
FINANCIAL CONDITION: LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes the Company's financial position for the
periods indicated:
December 31,
(amounts in thousands)
----------------------
2001 2000
---- ----
Amount % Amount %
------ ------ ------ ------
Working Capital $ -- -- $1,388 15
Property and equipment, net 5,980 85 5,345 58
Other noncurrent assets 1,043 15 2,476 27
------ ------ ------ ------
Total $7,023 100 $9,209 100
====== ====== ====== ======
Working Capital $1,197 17 $ -- --
Other non-current liabilities -- -- 550 6
Minority Interest 1,065 15 1,196 13
Stockholders' equity 4,761 68 7,463 81
------ ------ ------ ------
Total $7,023 100 $9,209 100
====== ====== ====== ======
The change in the Company's financial position from December 31, 2000
to December 31, 2001, was primarily due to the sale of its' 50% interest in the
Black Marlin Pipeline System for approximately $4.6 million, the installation of
a platform to operate and maintain the Blue Dolphin Pipeline System for
approximately $1.7 million net to the Company's interest, the sale to Fidelity
Oil of its reversionary interest in proved properties acquired from American
Resources of approximately $1.4 million and the impairment recorded for the
Petroport and Sabine Seaport projects of approximately $1.9 million.
Historically, the Company has relied on the proceeds from financing
activities and the sale of assets to supplement its capital requirements. In
2001, the Company financed its activities through the sale of assets and from
revenue generated from its operating activities.
The Company's future cash flows are subject to a number of variables,
including the level of gas and oil production, utilization of its pipeline
systems, utilization of its services by third parties and commodity prices among
others. The Company believes that it will have sufficient cash flow from
operations, private equity or debt financing activities and the sale of assets
to meet its obligations and operating needs for the year ending December 31,
2002. However, there can be no assurance 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 operating, investing
and financing activities is summarized below:
Years Ended December 31
(amounts in thousands)
2001 2000
---------- ----------
Net cash provided by (used in):
Operating activities $ 1,447 $ 3,691
Investing activities 2,412 (3,548)
Financing activities (2,587) 762
---------- ----------
Net increase in cash $ 1,272 $ 905
========== ==========
33
The Company's cash flow from operating activities decreased by $2.2
million in 2001 from 2000, due primarily to lower revenues from oil and gas
sales of approximately $.8 million and pipeline transportation of approximately
$1.2 million, and higher general and administrative expenses of approximately
$0.7 million.
Cash flow provided by investing activities during 2001 included the
proceeds from the sale of the Company's interest in the Black Marlin Pipeline
System of approximately $4.6 million and the sale of its reversionary interest
to Fidelity Oil of proved properties that Fidelity Oil acquired from American
Resources of approximately $1.4 million. Cash flow used in investing activities
included the construction of a new offshore platform installed to operate and
maintain the Blue Dolphin Pipeline of approximately $1.7 million, and
exploration and development costs associated with oil and gas properties owned
by American Resources of approximately $1.0 million.
Cash flow used in financing activities during the current period
consisted primarily of the payment of convertible promissory notes and related
party notes in the principal amount of approximately $2.2 million.
The Company previously announced a gas discovery in High Island Area
Block A-7, in the Gulf of Mexico. The Company owns an 8.9% reversionary working
interest in this field and it will begin to receive revenues from its
reversionary interest after "payout" occurs. Payout is scheduled to occur after
all of the other working interest owners have recovered their costs and expenses
associated with developing the field from sales of gas and oil production from
the field. In mid 2001, there were three wells producing in this field at a
combined rate of approximately 60 Mmcf of natural gas per day. However, two of
the three wells stopped producing and the remaining well is currently producing
approximately 14 Mmcf of natural gas per day. Additionally, two unsuccessful
exploratory wells were drilled in late 2001. The Company had expected to begin
to receive revenues from its reversionary working interest in this field in late
2001, however, as a result of the above mentioned occurrences the Company does
not expect to receive revenues until 2005.
In January 2001, the Company and its partners sold the Black Marlin
Pipeline System for $7.3 million and the High Island Block A-5 pipeline for $2.0
million to Williams Field Services; $3.6 million and $1.0 million, respectively,
net to the Company's interest. The Black Marlin System accounted for 1.0% and
30% of the Company's revenues for the years ended December 31, 2001 and 2000,
respectively.
In November 2000, the Company elected to abandon the Buccaneer field
due to adverse developments in the field. See Item 1 Business "Oil and Gas
Exploration and Production Activities - Buccaneer Field." The Company reached an
agreement with Tetra Applied Technologies, Inc. ("Tetra"), to plug and abandon
the wells located in the Buccaneer Field which was completed in the first
quarter of 2001 for approximately $1.4 million. In addition, Maritech Resources,
Inc. ("Maritech") an affiliate of Tetra purchased an adjacent lease from Apache
Corporation on which the Company provided production operating services. 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. The Company installed a new platform in 2001 at a cost of $1.7
million net to its interest, to operate and maintain the Blue Dolphin Pipeline
System, as well as handle the production from Maritech's lease. The Blue Dolphin
System was previously tied into and operated from the Buccaneer Field platforms.
In August 2001, the Company reached an agreement with Tetra to remove
the Buccaneer Field platforms for a cost of approximately $2.6 million. See Item
1 Business "Oil and Gas Exploration and Production Activities - Buccaneer
Field". Pursuant to the agreement, Tetra and the Company agreed to extended
payment terms, whereby the Company will pay 20% upon completion and 5% per month
34
for twelve months, with the remaining balance due in the thirteenth month. To
provide security for the extended payment terms, the Company provided Tetra with
a first lien on its 50% interest in the Blue Dolphin Pipeline System. Operations
to remove the platforms commenced in August 2001 and were suspended in December
2001, while the Company continues its discussions with the Texas Parks and
Wildlife to leave the under water portion of the platforms in place as
artificial reefs. The Company expects that the Texas Parks and Wildlife will
make a decision as to whether the Company will be able to leave any of the
Buccaneer Field platforms in place as artificial reefs, in the second quarter
2002. The Company requested and has received an extension from the MMS until
October 1, 2002, to complete the removal and site clearance of the platform
complexes. After the decision is made by the Texas Parks and Wildlife, Tetra
will resume its removal operations. If a platform complex is left in place as an
artificial reef, certain site clearance operations would be eliminated. The
Company believes that its provision for abandonment costs of $4.6 million at
December 31, 2001 is adequate.
The Company used $1.5 million of escrowed funds for abandonment costs
in 2001 to pay for plugging and abandonment costs incurred. The Company expects
to finance the remaining abandonment costs from working capital, the private
placement of debt or equity securities, or the sale of assets.
In December 1999, the Company entered into an agreement with Fidelity
Oil to manage their interest in the oil and gas properties acquired from
American Resources for $40,000 per month. This amount was intended to reimburse
the Company for the cost of the services provided. Fidelity Oil terminated this
agreement effective January 31, 2001. During the years ended December 31, 2001
and 2000, the Company received $40,000 and $480,000, respectively, in management
fees pursuant to this agreement.
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 total cost to construct the
pipeline was $1.9 million, $.9 million net to the Company's 50% interest in the
pipeline. The pipeline was completed in September 2000. The Company sold this
pipeline with the Black Marlin System in January 2001, as previously discussed.
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
$224,000, net to its' interest. 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 Company
believes it is well positioned to attract production from future discoveries in
the area.
The reserves and future net revenues presented in Item 1 "Business -
Oil and Gas Exploration and Production Activities," reflect capital expenditures
totaling $150,000, $328,000, $81,000, $111,000 and $225,000 in the years ending
December 31, 2002, 2003, 2004, 2005 and 2006, 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 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 funded $1.1 million of the costs associated
35
with the program during 2000. Fidelity Oil also reimbursed the Company for
seismic data acquired in connection with the prospect generation program.
Fidelity Oil withdrew from the prospect generation program effective December
31, 2000. In 2001, the Company suspended its prospect generation program until
it is able to obtain funding necessary to continue the program.
In December 1999, American Resources was paid approximately $4.5
million by Blue Dolphin Exploration for approximately 39.5 million shares of
American Resources common stock, representing a 75% ownership interest, and
$24.2 million by Fidelity Oil for an 80% interest in its' Gulf of Mexico assets.
The proceeds were used by American Resources to retire certain indebtedness. The
indebtedness included American Resources senior secured debt totaling
approximately $51.2 million to Den norske bank ("Den norske"). Den norske sold
the senior debt for $27.0 million and a contingent future payment if the
cumulative net revenues received by American Resources and Fidelity Oil
attributable to American Resources proved oil and gas reserves in the Gulf of
Mexico as of January 1, 1999, exceed $30.0 million during the period January 1,
1999, through December 31, 2001, whereby Den norske will be entitled to receive
an amount equal to 50% of the net revenues in excess of $30.0 million during
that three-year period. The amount payable to Den norske will be paid 80% by
Fidelity Oil and 20% by American Resources. A payment of approximately $.8
million was due on March 15, 2002, however, Den norske granted an extension of
this payment until April 30, 2002. The Company has provided for a liability to
Den norske in the amount of $.8 million at December 31, 2001.
In February 2002, the Company acquired a 1/3 interest in the Blue
Dolphin Pipeline System and the inactive Omega Pipeline from MCNIC. Pursuant to
the terms of the purchase and sales agreement, Blue Dolphin issued MCNIC a
$750,000 promissory note due December 31, 2006, with required monthly payments
to be made out of 90% of the net revenues of the interest acquired. The note
bears interest at the rate of 6% per annum and is secured by the interest
acquired. Additionally, contingent payments of up to $750,000 will be made, if
the promissory note is retired before its maturity date, payable annually after
the promissory note is retired until December 31, 2006, out of 50% of the net
revenues from the interest acquired. The termination date, December 31, 2006,
will be extended by one additional year, up to a maximum of two years, for years
in which non-recurring, extraordinary expenditures, attributable to the interest
acquired, exceeds $200,000, in the aggregate, during any year.
RESULTS OF OPERATIONS
For the year ended December 31, 2001, the Company reported a net loss
of $2,649,142, compared to a net loss of $10,135,120 for the year ended December
31, 2000. The 2001 loss was primarily due to the impairment recorded for the
Company's Petroport and Sabine Seaport projects of $1.9 million, and the 2000
loss was due to an impairment of oil and gas properties of $10.8 million.
2001 compared to 2000
---------------------
Revenue from oil and gas sales. Revenues from oil and gas sales
decreased by $824,938 in 2001, from those of 2000. The decrease was primarily
due to an 18% reduction in production volumes due to normal production declines,
resulting in a decrease in revenues of approximately $572,000. Oil and gas sales
recorded in 2000 included revenues of approximately $286,000 from production
from the Buccaneer Field prior to termination of production operations in July
2000.
Revenue from pipeline operations. Revenues from pipeline operations
decreased by $1,220,473 or 55% in 2001 to $991,823. The decrease was due
primarily to the sale of the Black Marlin Pipeline System in January 2001. The
Black Marlin Pipeline System provided revenues of approximately $1.0 million for
the previous period compared to approximately $50,000 for the current period.
Additionally, revenues from pipeline operations decreased due to a decline in
gas and oil volumes transported by the Blue Dolphin System, resulting in a
decrease of revenues from this system of approximately $.2 million.
36
Operating Fees. The Company did not have current period revenues from
operating fees due to the termination of its operating agreement with Maritech
in December 2000.
Lease Operating Expenses. Lease operating expenses for 2001 decreased
by $213,387 from 2000 due to the elimination of certain costs in 2001 associated
with the Buccaneer Field of approximately $.3 million, offset in part by
increased costs from the American Resources properties.
Pipeline operating expenses. Pipeline operating expenses in 2001
decreased by $459,945 or 47% from 2000. The decrease was primarily due to the
sale of the Black Marlin Pipeline System in January 2001. Black Marlin Pipeline
System operating expenses were approximately $.5 million for 2000 compared to
approximately $33,000 for 2001.
Depletion, depreciation and amortization expense. Current period
depletion, depreciation and amortization decreased $179,140 from the previous
period. The decrease was primarily due to a $.1 million decrease in depreciation
related to the Black Marlin Pipeline System that was sold in January 2001.
Impairment of assets. The Company recorded an impairment of its
investment in the Petroport and Sabine Seaport projects of approximately $1.9
million, and increased the impairment of the Buccaneer Field by $1.0 million in
2001 due to revised plugging and abandonment estimates. In 2000, the Company
recorded an impairment of oil and gas properties of $10.7 million, comprised of
a non-cash write-off of proved reserves from the Buccaneer Field of $5.3 million
and the recognition of associated plugging and abandonment costs estimated to be
$5.4 million.
General and administrative expenses. General and administrative
expenses for the current period increased $751,619 from the previous period. The
increase was due in part to an increase in legal defense expenses of
approximately $.2 million (See Item 3. "Legal Proceedings"), and the termination
of the Management Services Agreement between the Company and Fidelity Oil,
whereby the Company managed Fidelity Oil's interest in the oil and gas assets it
acquired from American Resources in December 1999. Management fees of
approximately $.5 million received from Fidelity Oil were recorded as a
reduction to general and administrative expenses during the previous period.
Interest and other expense. Interest and other expense decreased
$517,987 in the current period. In the current period, the Company increased the
provision for the contingent payment to Den norske by $250,000, compared to the
$550,000 recorded in 2000. In addition, the Company retired $2.2 million of
promissory notes in January 2001, resulting in a decrease in interest expense
from 2000 of approximately $129,000.
Gain on sale of assets. The Company recorded a gain on the sale of the
Black Marlin Pipeline System of $1.4 million in January 2001.
Equity losses of affiliates. In the current period, the Company
recorded losses from it's equity interest in Drillmar and New Avoca of $245,201.
Recently Issued Accounting Pronouncements
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"), was issued in June 1998 by the
Financial Accounting Standards Board. SFAS 133 establishes new accounting and
reporting standards for derivative instruments and for hedging activities. This
statement requires an entity to establish at the inception of a hedge, the
method it will use for assessing the effectiveness of the hedging derivative and
the measurement approach for determining the ineffective aspect of the hedge.
Those methods must be consistent with the entity's approach to managing risk.
37
Certain provisions of SFAS 133 were amended by SFAS 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - an amendment of
Statement 133", SFAS 133, as amended, is effective for all fiscal quarters of
fiscal years beginning after June 15, 2000. SFAS 133, as amended, did not have a
material effect on the Company's consolidated financial position or the results
of operations.
In July 2001, the FASB issued Statement No. 141 ("SFAS 141"), "Business
Combinations," and Statement No. 142, "Goodwill and Other Intangible Assets"
("SFAS 142"). SFAS 141 requires that the purchase method of accounting be used
for all business combinations initiated after June 30, 2001. SFAS 141 also
specifies criteria intangible assets acquired in a purchase method business
combination must meet to be recognized and reported apart from goodwill. SFAS
142 will require that goodwill and intangible assets with indefinite useful
lives no longer be amortized, but instead tested for impairment at least
annually in accordance with the provisions of SFAS 142. SFAS 142 will also
require that intangible assets with definite useful lives be amortized over
their respective estimated useful lives to their estimated residual values, and
reviewed for impairment in accordance with SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of".
The Company does not expect to have unamortized goodwill, unamortized
identifiable assets, or unamortized negative goodwill upon adoption of SFAS 142
on January 1, 2002.
In August 2001, the FASB issued Statement No. 143 ("SFAS 143"), "Accounting for
Asset Retirement Obligations," which addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. The standard applies to legal
obligations associated with the retirement of long-lived assets that result from
the acquisition, construction, development and/or normal use of the asset.
SFAS 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset and this additional carrying amount
is depreciated over the life of the asset. If the obligation is settled for
other than the carrying amount of the liability, the Company will recognize a
gain or loss on settlement.
The Company is required and plans to adopt the provisions of SFAS 143 for the
quarter ending March 31, 2003. To accomplish this, the Company must identify all
legal obligations for asset retirement obligations and determine the fair value
of these obligations on the date of adoption. The determination of fair value is
complex and will require the Company to gather market information and develop
cash flow models. Additionally, the Company will be required to develop
processes to track and monitor these obligations. Because of the effort
necessary to comply with the adoption of SFAS 143, it is not practicable for
management to estimate the impact of adopting this Statement at the date of this
report.
In October 2001, the FASB issued Statement No. 144 ("SFAS 144"), "Accounting for
the Impairment or Disposal of Long-Lived Assets". SFAS 144 provides that
long-lived assets to be disposed of by sale be measured at the lower of carrying
amount or fair value less cost to sell, whether reported in continuing
operations or in discontinued operations, and broadens the reporting of
discontinued operations to include all components of an entity with operations
that can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal transaction.
SFAS 144 is effective for fiscal years beginning after December 15, 2001.
The Company is currently assessing the impact of SFAS 144 on its financial
condition and results of operations.
38
Item 7. Financial Statements and Supplementary Data
Index to Financial Statements: Page
----
Independent Auditors' Report................................... 40
Consolidated Balance Sheet, at December 31, 2001............... 41
Consolidated Statements of Operations, for the years
ended December 31, 2001 and 2000........................ 43
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 2001 and 2000.................. 44
Consolidated Statements of Cash Flows, for the years
ended December 31, 2001 and 2000........................ 45
Notes to Consolidated Financial Statements..................... 47
39
Independent Auditors' Report
The Board of Directors
Blue Dolphin Energy Company
We have audited the accompanying consolidated balance sheet of Blue Dolphin
Energy Company and subsidiaries as of December 31, 2001, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the years in the two-year period ended December 31, 2001. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Blue Dolphin Energy
Company and subsidiaries as of December 31, 2001, and the results of their
operations and their cash flows for each of the years in the two-year period
ended December 31, 2001 in conformity with accounting principles generally
accepted in the United States.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As shown in the consolidated
financial statements, the Company has a working capital deficiency, has incurred
net losses in recent years, and has a significant accumulated deficit. Those
conditions raise substantial doubt about the Company's ability to continue as a
going concern. Management's plans in regard to those matters are described in
Note 2. The consolidated financial statements do not include any adjustments
that might result from the outcome of this uncertainty.
/s/ Mann Frankfort Stein & Lipp CPAs, LLP
-----------------------------------------
Houston, Texas
March 18, 2002
40
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet
December 31, 2001
Assets
------
Current assets:
Cash and cash equivalents $ 3,343,560
Trade accounts receivable 1,123,905
Accounts receivable - related party 134,334
Prepaid expenses and other assets 163,825
------------
Total current assets 4,765,624
Property and equipment, at cost:
Oil and gas properties, including $221,832
of unproved leasehold cost (full-cost method) 27,570,342
Onshore separation and handling facilities 1,583,428
Land 850,000
Pipelines 2,920,135
Other property and equipment 283,192
------------
33,207,097
Less accumulated depletion, depreciation,
amortization and impairment 27,227,024
------------
5,980,073
Deferred federal income tax 244,444
Other assets 798,871
------------
$ 11,789,012
============
See accompanying notes to consolidated financial statements.
41
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet, continued
December 31, 2001
Liabilities and Stockholders' Equity
------------------------------------
Current liabilities:
Trade accounts payable $ 1,039,820
Accrued expenses and other liabilities 4,923,085
------------
Total current liabilities 5,962,905
Minority interest 1,064,991
Stockholders' equity:
Common stock, $.01 par value, 10,000,000 shares
authorized and 6,091,449 shares issued
and outstanding 60,915
Additional paid-in 25,722,060
capital
Accumulated (deficit) (21,021,859)
------------
Total stockholders' 4,761,116
equity
------------
$ 11,789,012
============
See accompanying notes to consolidated financial statements.
42
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
Years ended December 31, 2001 and 2000
2001 2000
----------- -----------
Revenue from operations:
Oil and gas sales $ 4,694,202 5,519,140
Pipeline operations 991,823 2,212,296
Operating fees -- 210,534
----------- -----------
Revenue from operations 5,686,025 7,941,970
Cost of operations:
Lease operating expenses 1,155,549 1,368,936
Pipeline operating expenses 517,054 976,999
Depletion, depreciation and amortization 1,817,770 1,996,910
Impairment of assets 2,940,464 10,754,976
General and administrative expenses 2,845,459 2,093,840
----------- -----------
Cost of operations 9,276,296 17,191,661
----------- -----------
Loss from operations (3,590,271) (9,249,691)
Other income (expense):
Interest and other expense (243,591) (761,578)
Gain on sale of assets 1,417,626 --
Interest and other income 116,417 114,107
Equity in losses of affiliates (245,201) --
----------- -----------
Loss before minority interest and income (2,545,020) (9,897,162)
taxes
Minority (104,122) (237,958)
interest
Income tax expense -- --
----------- -----------
Net loss $(2,649,142) (10,135,120)
=========== ===========
Loss per common share-basic and diluted $ (0.44) (1.70)
=========== ===========
Weighted average number of common shares
outstanding - basic and diluted 6,004,019 5,963,318
=========== ===========
See accompanying notes to consolidated financial statements.
43
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
Years ended December 31, 2001 and 2000
Additional Total
Common paid-in Accumulated stockholders'
stock capital (deficit) equity
------------- ------------- ------------- -------------
Balance at December 31, 1999 $ 59,509 25,823,817 (8,237,597) 17,645,729
Exercise of 33,665 stock options 336 109,843 -- 110,179
Issuance of shares to 401K plan 300 89,700 -- 90,000
Stock registration costs and other 22 (247,943) -- (247,921)
Net loss (10,135,120) (10,135,120)
============= ============= ============= =============
Balance at December 31, 2000 60,167 25,775,417 (18,372,717) 7,462,867
Exercise of 3,333 stock options 33 12,715 -- 12,748
Issuance of shares to 401K plan 500 79,500 -- 80,000
Stock registration costs and other 215 (145,572) -- (145,357)
Net loss (2,649,142) (2,649,142)
------------- ------------- ------------- -------------
Balance at December 31, 2001 $ 60,915 25,722,060 (21,021,859) 4,761,116
============= ============= ============= =============
See accompanying notes to consolidated financial statements.
44
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended December 31, 2001 and 2000
2001 2000
----------- ----------
Operating
activities:
Net $(2,649,142) (10,135,120)
loss
Adjustments to reconcile net loss to
net cash
provided by operating activities:
Depletion, depreciation and 1,817,770 1,996,910
amortization
Minority 104,122 237,958
interest
Gain on sale of property and (1,417,626) --
equipment
Impairment of 2,940,464 10,754,976
assets
Increase in other liabilities 250,000 550,000
Equity in losses of affiliates 245,201 --
Issuance of shares to 401K plan 80,000 90,000
Changes in operating assets
and liabilities:
Trade accounts receivable 1,148,512 (864,423)
Prepaid expenses and (35,912) 190,226
other assets
Abandonment costs incurred (442,984) --
Other assets 28,389 --
Trade accounts payable,
accrued expenses and other
liabilities (622,292) 870,276
----------- -----------
Net cash provided
by
operating 1,446,502 3,690,803
activities
Investing
activities:
Exploration and development costs (1,022,843) (1,620,564)
Purchases of property and equipment (1,764,245) (1,269,924)
Net proceeds from sale 5,985,000 --
of assets
Development costs - (59,305) (155,576)
Petroport
Development costs - New (234,140) (184,248)
Avoca
Acquisition and development costs - (492,460) --
Drillmar
Funds escrowed for abandonment costs -- (317,164)
----------- -----------
Net cash provided by (used in)
investing activities 2,412,007 (3,547,476)
See accompanying notes to consolidated financial statements.
45
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows, Continued
Years ended December 31, 2001 and 2000
2001 2000
----------- -----------
Financing
activities:
Proceeds from borrowings, related party -- 1,000,000
Payments on borrowings, preferred stockholders (218,412) (100,633)
Payments on borrowings, related parties (2,000,000) --
Payments of offering costs and other (145,357) (247,921)
Dividends paid by subsidiary (235,610) --
Net proceeds from the exercise of stock options 12,748 110,179
----------- -----------
Net cash provided by
(used in)
financing (2,586,631) 761,625
activities
----------- -----------
Increase in cash and cash 1,271,878 904,952
equivalents
Cash and cash equivalents at beginning of year 2,071,682 1,166,730
----------- -----------
Cash and cash equivalents at end of year $ 3,343,560 2,071,682
=========== ===========
Supplementary cash flow information:
Interest paid $ 98,500 86,316
=========== ===========
Taxes paid $ 6,530 8,498
=========== ===========
See accompanying notes to consolidated financial statements.
46
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2001 and 2000
(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
(American Resources). All significant intercompany balances and
transactions have been eliminated in consolidation.
Accounting Estimates
Management has made a number of estimates and assumptions relating to
the reporting of assets and liabilities and to the disclosure of
contingent assets and liabilities including reserve information which
affects the depletion calculation as well as the computation of the
full cost ceiling limitation to prepare these financial statements in
conformity with accounting principles generally accepted in the United
States. Actual results could differ from those estimates.
Cash Equivalents
Cash equivalents include liquid investments with an original maturity
of three months or less. Cash balances are maintained in depository and
overnight investment accounts with a financial institution which at
times, exceed insured limits. The Company monitors the financial
condition of the financial institution and has experienced no losses
associated with these accounts.
Oil and Gas Properties
Oil and gas properties are accounted for using the full-cost method of
accounting, whereby all costs associated with acquisition, exploration,
and development of oil and gas properties, including directly related
internal costs, are capitalized on a country-by-country cost center
basis. Due to the difference in the expected life of the reserves of
47
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
the properties, the Company used two separate cost centers, one for its
Buccaneer Field property and one for its other properties. With the
write off of the Buccaneer Field during the year ended December 31,
2000, the Company is now utilizing one cost center for all of its
properties. Amortization of such costs and estimated future development
costs are determined using the unit-of-production method. Provision for
the estimated costs of offshore platform and well abandonment, net of
salvage value, is computed on the units of production method and is
included in depletion, depreciation and amortization. Costs directly
associated with the acquisition and evaluation of unproved properties
are excluded from the amortization computation until it is determined
whether or not proved reserves can be assigned to the properties or
impairment has occurred. Estimated proved oil and gas reserves are
based upon reports of independent petroleum engineers. The net carrying
value of oil and gas properties, less related deferred income taxes, is
limited to the lower of unamortized cost or the cost center ceiling,
defined as the sum of the present value (10% discount rate applied) of
estimated future net revenues from proved reserves, after giving effect
to income taxes, and the lower of cost or estimated fair value of
unproved properties. Disposition of oil and gas properties are recorded
as adjustments to capitalized costs, with no gain or loss recognized
unless such adjustments would significantly alter the relationship
between capitalized costs and proved reserves.
The following table reflects the depletion expense incurred from oil
and gas properties during the periods indicated:
Year Ended December 31,
2001 2000
---------- ------------
Depletion expense per Mcf
equivalent produced $1.53 $1.18
========== ============
At December 31, 2001, oil and gas properties included $221,832 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
July 2002 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.
The following table reflects the periods when costs were incurred for
unproved leasehold costs:
48
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31,
--------------------------
Total 2001 2000 Prior Years
----------- ----------- ----------- -----------
Property acquisition costs $ 177,518 (102,920) -- 280,438
Exploration costs 44,314 (106,030) -- 150,344
----------- ----------- ----------- -----------
$ 221,832 (208,950) -- 430,782
=========== =========== =========== ===========
The Company capitalizes interest on expenditures made in connection
with significant exploration and production projects that are not
subject to current amortization. Interest is capitalized only for the
period that activities are in progress to bring these projects to their
intended use. No interest has been capitalized for the periods
reflected herein.
Pipelines and Facilities
Pipelines and facilities are recorded at cost. Depreciation is computed
using the straight-line method over estimated useful lives of 10-22
years. Provision for the estimated cost of pipeline and facilities
abandonment, net of salvage value, is computed on a straight line basis
over the estimated useful life of such assets and is included in
Depletion, Depreciation and Amortization.
Other Property and Equipment
Depreciation of furniture, fixtures and other equipment, including
assets held under capital leases, is computed using the straight-line
method over estimated useful lives of 3-10 years.
In accordance with Statement of Financial Accounting Standards ("SFAS")
No. 121, Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to Be Disposed Of, assets are grouped and evaluated
for impairment based on the ability to identify separate cash flows
generated therefrom. For the year ended December 31, 2001, the Company
recorded a full impairment of $1.9 million of its investment in both
the Petroport and Sabine Seaport projects.
Abandonment
A provision for the abandonment, dismantlement and site clearance of
offshore production platforms and existing wells is made using the
unit-of-production method applied to estimates based on current costs.
A provision for pipeline and pipeline facilities abandonment costs is
also provided using the straight-line method over the estimated useful
lives of the pipeline and pipeline facilities. Until such time that the
liability becomes current, the provisions are included in accumulated
depletion, depreciation, amortization and impairment, and are
undiscounted. Aggregate abandonment liability is estimated to be
approximately $4,866,000 at December 31, 2001, of which $1,556,000 is
included in accumulated depletion, depreciation, amortization, and
impairment and $3,300,000 is included in accrued expenses and other
liabilities.
49
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
New Avoca and Drillmar
The Company records its investment in New Avoca (25% owned and managed
by the Company) and Drillmar using the equity method of accounting.
Under the equity method, investments are recorded at cost plus the
Company's equity in undistributed earnings and losses after
acquisition.
Stock-Based Compensation
The Company applies SFAS No. 123, Accounting for Stock-Based
Compensation, which allows a company to adopt a fair value based method
of accounting for a stock-based employee compensation plan or to
continue to use the intrinsic value based method of accounting
prescribed by Accounting Principles Board Opinion No. 25, Accounting
for Stock Issued to Employees. The Company chose 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 Oil and Gas Revenue
Sales from producing wells are recognized on the entitlement method of
accounting which defers recognition of sales when, and to the extent
that, deliveries to customers exceed the Company's net revenue interest
in production. Similarly, when deliveries are below the Company's net
revenue interest in production, sales are recorded to reflect the full
net revenue interest. The Company's imbalance liability at December 31,
2001 and 2000 was not material.
Recognition of Pipeline Transportation Revenue
Revenue from the transportation of gas, condensate and crude oil is
recognized on the accrual basis as products are transported.
Operation of Oil and Gas Properties
Until December 2000, the Company operated, for a monthly fee, oil and
gas properties in which it did 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.
50
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Income Taxes
The Company provides for income taxes using the asset and liability
method pursuant to SFAS No. 109, Accounting for Income Taxes
("Statement 109"). Under the asset and liability method of Statement
109, deferred tax assets and liabilities are recognized for the future
tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases and operating loss and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The
effect on deferred tax assets and liabilities of a change in tax rates
is recognized in income in the period that includes the enactment date.
Earnings Per Share
The Company follows SFAS No. 128 ("Statement 128"), "Earnings per
Share", for computing and presenting earnings per share and requires,
among other things, dual presentation of basic and diluted earnings per
share on the face of the statement of operations.
The employee stock options at December 31, 2001 and 2000, 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.
Environmental
The Company is subject to extensive Federal, state and local
environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and
may require the Company to remove or mitigate the environmental effects
of the disposal or release of petroleum or chemical substances at
various sites. Environmental expenditures are expensed or capitalized
depending on their future economic benefit. Expenditures that relate to
an existing condition caused by past operations and that have no future
economic benefits are expensed. Liabilities for expenditures of a
noncapital nature are recorded when environmental assessment and/or
remediation is probable, and the costs can be reasonably estimated.
Such liabilities are generally recorded at their undiscounted amounts
unless the amount and timing of payments is fixed or reliably
determinable.
51
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Recently Issued Accounting Pronouncements
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"), was issued
in June 1998 by the Financial Accounting Standards Board. SFAS 133
establishes new accounting and reporting standards for derivative
instruments and for hedging activities. This statement requires an
entity to establish at the inception of a hedge, the method it will use
for assessing the effectiveness of the hedging derivative and the
measurement approach for determining the ineffective aspect of the
hedge. Those methods must be consistent with the entity's approach to
managing risk. Certain provisions of SFAS 133 were amended by SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities - an amendment of Statement 133", SFAS 133, as amended, is
effective for all fiscal quarters of fiscal years beginning after June
15, 2000. SFAS 133, as amended, did not have a material effect on the
Company's consolidated financial position or the results of operations.
In July 2001, the FASB issued Statement No. 141 ("SFAS 141"), "Business
Combinations," and Statement No. 142, "Goodwill and Other Intangible
Assets" ("SFAS 142"). SFAS 141 requires that the purchase method of
accounting be used for all business combinations initiated after June
30, 2001. SFAS 141 also specifies criteria intangible assets acquired
in a purchase method business combination must meet to be recognized
and reported apart from goodwill. SFAS 142 will require that goodwill
and intangible assets with indefinite useful lives no longer be
amortized, but instead tested for impairment at least annually in
accordance with the provisions of SFAS 142. SFAS 142 will also require
that intangible assets with definite useful lives be amortized over
their respective estimated useful lives to their estimated residual
values, and reviewed for impairment in accordance with SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of". The Company does not expect to have
unamortized goodwill, unamortized identifiable assets, or unamortized
negative goodwill upon adoption of SFAS 142 on January 1, 2002.
In August 2001, the FASB issued Statement No. 143 ("SFAS 143"),
"Accounting for Asset Retirement Obligations," which addresses
financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs. The standard applies to legal obligations associated
with the retirement of long-lived assets that result from the
acquisition, construction, development and/or normal use of the asset.
SFAS 143 requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made. The fair
value of the liability is added to the carrying amount of the
associated asset and this additional carrying amount is depreciated
over the life of the asset. If the obligation is settled for other than
the carrying amount of the liability, the Company will recognize a gain
or loss on settlement.
52
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The Company is required and plans to adopt the provisions of SFAS 143
for the quarter ending March 31, 2003. To accomplish this, the Company
must identify all legal obligations for asset retirement obligations
and determine the fair value of these obligations on the date of
adoption. The determination of fair value is complex and will require
the Company to gather market information and develop cash flow models.
Additionally, the Company will be required to develop processes to
track and monitor these obligations. Because of the effort necessary to
comply with the adoption of SFAS 143, it is not practicable for
management to estimate the impact of adopting this Statement at the
date of this report.
In October 2001, the FASB issued Statement No. 144 ("SFAS 144"),
"Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS
144 provides that long-lived assets to be disposed of by sale be
measured at the lower of carrying amount or fair value less cost to
sell, whether reported in continuing operations or in discontinued
operations, and broadens the reporting of discontinued operations to
include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated
from the ongoing operations of the entity in a disposal transaction.
SFAS 144 is effective for fiscal years beginning after December 15,
2001.
The Company is currently assessing the impact of SFAS 144 on its
financial condition and results of operations.
Reclassifications
Certain 2000 balances have been reclassified to conform with the 2001
financial statement presentation. There is no effect on net loss due to
the reclassifications.
(2) Liquidity and Going Concern
At December 31, 2001 the Company's working capital deficit was
approximately $1.2 million. In order to satisfy its working capital and
capital expenditure requirements in 2002, the Company believes that it
will need to raise between $2.0 to $3.0 million of capital. The Company
will need to seek external financing and/or sell assets to raise the
necessary capital. There can be no assurance that the Company will be
able to obtain financing or sell assets on commercially reasonable
terms. The Company's inability to raise capital may have a material
adverse effect on its financial condition, ability to meet its
obligations and operating needs and results of operations. The
consolidated financial statements do not include any adjustments that
might result from the outcome of this uncertainty.
53
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(3) Fair Value of Financial Instruments
The carrying values of cash and cash equivalents, receivables and
accounts payable approximate fair value due to the short-term
maturities of these instruments.
(4) Income Taxes
Income tax expense for both 2001 and 2000 was $0.
The income tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities at December 31, 2001 are presented below:
Deferred tax assets:
Net operating loss carryforwards $ 10,739,000
Alternative minimum tax credit 244,444
Basis differences in property and
equipment 1,524,000
------------
Total gross deferred tax assets 12,507,444
Deferred tax liabilities-state tax (34,000)
------------
Net deferred tax asset 12,473,444
Less valuation allowance (12,229,000)
------------
Deferred tax asset $ 244,444
============
In 1999, the Company acquired a 75% interest in American Resources,
which had deferred tax assets of approximately $8.5 million made up of
basis differences in oil and gas properties and net operating losses. A
full valuation allowance was recorded to reduce the corresponding
deferred assets, since it is more likely than not that they will not be
realized, due to the limitation of the use of the net operating loss
carryforwards resulting from the ownership change in December 1999.
In assessing the realizability of deferred tax assets, the Company
applies SFAS No. 109 to determine whether it is more likely than not
that some portion or all of the deferred tax assets will not be
realized. As a result, the Company's valuation allowance at December
31, 2001 reduces the deferred tax assets to $244,444.
The Company's effective tax rate applicable to continuing operations in
2001 and 2000 is as follows:
54
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
2001 2000
------ ------
Expected tax rate (34%) (34%)
State taxes, net of federal benefit -- --
Expenses not deductible for tax purposes -- --
Increase in valuation allowance recognized
in earnings 34% 34%
Other -- --
------ ------
0% 0%
====== =======
For federal tax purposes, the company had a net operating loss
carryforward ("NOL") of approximately $31.6 million and $28.3 million
for the years ended December 31, 2001 and 2000, respectively. These
NOLs must be utilized prior to their expiration, which is between 2002
and 2021. Of the $31.6 million of NOLs as of December 31, 2001, $17.5
million relate to American Resources.
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.
(5) Long-term Debt
The Company retired $218,412 principal amount of promissory notes in
January 2001. The promissory notes were originally issued in December
1996, to holders of the Company's Preferred Stock as full payment of
the cumulative preferred stock dividends. The promissory notes were
unsecured and bore interest at the rate of 10.25% per annum. Interest
only was payable semi-annually with the principal due on December 31,
2000.
In December 1999, the Company issued a $1.0 million unsecured
convertible promissory note to Harris A. Kaffie, a director of the
Company. This convertible promissory note originally due June 1, 2000
was extended to March 31, 2001, bore interest at 10% per annum, and was
convertible into Common Stock at $6.00 per share. This convertible
promissory note and accrued interest of $64,361 were paid in January
2001.
The Company issued three unsecured 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 $600,000 on November 30,
2000, issued to TI A/S, beneficially controlled by Ivar Siem. The
convertible promissory notes were due March 31, 2001, bore interest at
the rate of 10% per annum and were convertible into Common Stock at the
rate of $6.00 per share. These convertible promissory notes and accrued
interest of $32,790 were paid in January 2001.
55
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(6) Stockholders' Equity
In 2001, the Company incurred costs totaling $185,943 associated with
the registration of shares of its Common Stock. In addition, the
Company issued 17,867 shares of its Common Stock as a severance payment
to a former employee and recorded compensation expense of $28,586. The
Company also issued 2,824 shares to the board of directors and recorded
an expense of $12,000. In 2000, the Company incurred costs totaling
$263,458 associated with the registration of shares of Common Stock,
$.01 par value per share. In addition, the Company issued 2,785 shares
of its Common Stock as a severance payment to a former employee and
recorded compensation expense of $15,537.
(7) Stock Options
Effective April 14, 2000, the Company adopted, after approval by
stockholders, a stock incentive plan (the "2000 Plan"). The stock
subject to the options and other provisions of the 2000 Plan are shares
of the Company's Common Stock $.01 par value (the "Stock"). No more
than 500,000 shares of Stock will be available for incentive stock
options ("ISOs"). The 2000 Plan is administered by the Compensation
Committee of the Board of Directors. Options granted must be exercised
within 10 years from their grant date. The exercise price of ISOs
cannot be less than 100% of the fair market value of a share of Stock.
The 2000 Plan also provides for the granting of other incentive awards,
however only ISOs and non-statutory stock options have been issued
under the 2000 Plan.
The Company adopted a stock option plan in 1996 (the "1996 Plan"). The
stock subject to the options and other provisions of the 1996 Plan are
shares of the Company's Common Stock. The total amount of the Common
Stock with respect to which options may be granted shall not exceed in
the aggregate 10% of the number of issued and outstanding shares of
Common Stock of the Company. The stock options become exercisable from
time to time in part or as a whole, as the Compensation Committee,
appointed by the Board of Directors, or the Board of Directors in their
discretion may provide. However, the Committee shall not grant options
which may become exercisable in any one calendar year to purchase more
than one-third of the maximum amount granted. All options expire five
years after the date of grant. The price of options granted may not be
less than eighty-five percent of the fair market value of the Common
Stock on the date the option is granted. Optionees must continue their
association with the Company for six months after exercising the
options, or the underlying stock reverts to the Company.
At December 31, 2001 the Company has reserved a total of 153,173 shares
of Common Stock for issuance under the above mentioned stock option
plans. The outstanding stock options granted to key employees, officers
and directors, for the purchase of shares of the Company's Common
Stock, are as follows:
56
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Exercise
price per share
------------------
Shares From To
------- ------- -------
Balance, December 31, 1999 177,104 2.789 5.000
======= ======= =======
Granted 55,300 6.000 6.000
Expired (47,503) 2.789 6.000
Exercised (33,665) 2.789 3.984
------- ------- -------
Balance, December 31, 2000 151,236 2.789 6.000
======= ======= =======
Granted 42,104 1.900 1.900
Expired (36,834) 3.125 6.000
Exercised (3,333) 3.825 3.825
------- ----- -------
Balance, December 31, 2001 153,173 1.900 6.000
======= ======= =======
The weighted average exercise price per share was $3.825 and $3.365 in
2001 and 2000, respectively.
As of December 31, 2001, options for 122,506 shares of Common Stock
were immediately exercisable. There where 42,104 and 55,300 options
granted in 2001 and 2000, respectively. Pursuant to the requirements of
FASB No. 123, the weighted average fair market value of options granted
during 2001 and 2000 was $0.24 per share and $1.30 per share,
respectively. The weighted average closing bid prices for the Company's
stock at the date the options were granted during 2001 and 2000 are
$1.90 per share and $5.25 per share, respectively. The fair market
value pursuant to FASB No. 123 of each option granted is estimated on
the date of grant using the Black-Scholes options-pricing model. The
model assumed expected volatility of 29% and 70%, risk-free interest
rate of 2.22% and 6.39% for grants in 2001 and 2000, respectively, and
an expected life of 1 year. As the Company has not declared dividends
on its Common Stock since it became a public entity, no dividend yield
was used. Actual value realized, if any, is dependent on the future
performance of the Company's Common Stock and overall stock market
conditions. There is no assurance the value realized by an optionee
will be at or near the value estimated by the Black-Scholes model.
No compensation expense was recorded in 2001 and 2000 for stock options
granted. Had compensation cost for the Company's stock option plans
been determined based on the fair market value at the grant dates for
awards made, the Company's net loss and loss per share would have been
adjusted to the pro forma amounts indicated below:
57
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Year ended December 31,
-----------------------
2001 2000
-------------- ---------------
Net (loss) as reported $ (2,649,142) $ (10,135,120)
Pro Forma $ (2,759,436) $ (10,271,293)
Basic and diluted (loss)
Per share as reported (0.44) (1.70)
Pro Forma (0.46) 1.72)
Outstanding options at December 31, 2001 expire between December 25,
2002 and December 17, 2011.
(8) Related Party Transactions
Related party transactions which are not disclosed elsewhere in these
consolidated financial statements are discussed in the following
paragraphs:
In September 2001, Drillmar, a 12.8% owned affiliate of the Company,
entered into a merger agreement and merged with Zephyr Drilling Ltd.
("Zephyr"). Prior to the merger, Zephyr was a limited partnership in
which Drillmar was the general partner. Zephyr owned a semi-submersible
drilling rig that has been prepared for reconfiguration into a
semi-tender. As a result of the merger, the Company's interest in
Drillmar decreased from 64% to 12.8%.
Ivar Siem, Chairman of the Company, and Harris A. Kaffie, a Director of
the Company, were limited partners of Zephyr. After the merger between
Drillmar and Zephyr, Messers. Siem and Kaffie were owners of 30.3% and
30.6%, respectively, of Drillmar's common stock. During 2001, Messrs.
Siem and Kaffie provided funding to Drillmar of $525,000 and $425,000,
respectively, and were issued unsecured promissory notes from Drillmar.
The promissory notes are due June 30, 2002 and bear interest at the
rate of 10% per annum. Along with the promissory notes, Drillmar issued
detachable warrants to Messrs. Siem and Kaffie of 52,500 and 42,500,
respectively. Each warrant provides for the purchase of one share of
Drillmar common stock at $5 per share and are exercisable through
January 31, 2005. The promissory notes issued by Drillmar are
nonrecourse to the Company.
In January 2001, the Company entered into an agreement with Drillmar
whereby it agreed to provide office space and certain management and
administrative services to Drillmar for approximately $40,000 per
month. This agreement can be terminated at any time by the mutual
agreement of the parties. Through October 2001, the Company used the
monthly payments it was entitled to receive to fund its investment in
Drillmar.
58
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(9) 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,
2001:
Year ending
December 31,
------------
2002 $ 186,498
2003 185,521
2004 195,617
2005 195,617
2006 195,617
----------
$ 958,870
==========
Rental expense under operating leases for the years indicated are as
follows:
Year ended
December 31,
------------
2001 $ 198,548
2000 190,211
(10) Commitments and Contingencies
As a result of the decision to cease operating activities in the
Buccaneer Field, the Company's leases in or on the Buccaneer Field
terminated in January 2001. The Company must plug and abandon all
remaining wells and remove platform facilities within one year from the
termination of the leases. In 2001, the Company plugged its remaining
wells at a cost of approximately $1.4 million. During the operations of
removing the Buccaneer Field platform complexes in 2001 at a cost of
approximately $0.4 million, discussions were initiated with the Texas
Parks and Wildlife ("TP&W") in an effort to leave certain of the under
water portions of the platform complexes in place as artificial reefs.
In December 2001, operations to remove the platform complexes were
suspended while the Company continues its discussions with the TP&W.
The Company expects that the TP&W will make a decision to leave either
one, both or neither of the Buccaneer Field platform complexes in place
as artificial reefs in the second quarter 2002. If one or both of the
platform complexes are left in place as an artificial reef, certain
site clearance costs would be eliminated. The Company requested and has
received an extension from the MMS until October 1, 2002 to complete
the removal and site clearance of the platform complexes. The Company
still believes that its provision for abandonment costs of $4.6 million
at December 31, 2001 is adequate.
59
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
In December 1999, American Resources received approximately $4.5
million from Blue Dolphin Exploration for American Resources common
stock representing a 75% ownership interest and $24.2 million from
Fidelity Oil for an 80% interest in its Gulf of Mexico assets. American
Resources senior secured debt was held by Den norske bank ("Den
norske"). Den norske sold the senior debt to the Company for the right
to receive a possible future payment if the cumulative net revenues
received by American Resources and Fidelity Oil attributable to
American Resources proved oil and gas reserves in the Gulf of Mexico as
of January 1, 1999, exceed $30.0 million during the period January 1,
1999, through December 31, 2001, whereby Den norske will be entitled to
receive an amount equal to 50% of those net revenues in excess of $30.0
million during that three-year period. The amount payable to Den norske
will be paid 80% by Fidelity Oil and 20% by American Resources. A
payment of approximately $.8 million was due on March 15, 2002;
however, Den norske granted an extension of this payment until April
30, 2002. The Company has provided for a liability to Den norske in the
amount of $.8 million at December 31, 2001.
On May 8, 2000, American Resources 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,
Limited Partnership, et al. v. Richard Hale, 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 gas purchase options
and 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 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. H&N further
alleges civil conspiracy against all the defendants. H&N is seeking
approximately $6.2 million in actual damages plus treble damages,
punitive damages and prejudgment interest against American Resources
directly. As a result of its conspiracy allegation, H&N also contends
that all defendants are jointly and severally liable for over $40.0
million in actual damages plus treble damages, punitive damages and
prejudgment interest. American Resources intends to vigorously defend
this claim.
The Company is involved in various other claims and legal actions
arising in the ordinary course of business. In the opinion of
management, the ultimate disposition of these matters will not have a
material effect on the Company's financial position, results of
operations or cash flows.
(11) Business Segment Information
The Company's income producing operations are conducted in two
principal business segments: oil and gas exploration and production,
which includes upstream projects, and pipeline operations, which
includes mid-stream projects. Intersegment revenues consist of
transportation, general processing and storage fees charged by certain
60
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
subsidiaries to another for gas and crude oil transported through the
Blue Dolphin Pipeline System. The intercompany revenues and expenses
are eliminated in consolidation. Information concerning these segments
for the years ended December 31, 2001and 2000 is as follows:
Depletion,
Depreciation,
Operating Amortization
Intersegment income Identifiable and
Revenues revenues (loss)(1) assets Impairment(2)
----------- ----------- ----------- ----------- -----------
Year ended December 31, 2001:
Oil and gas exploration and
production and
operating fees $ 4,694,202 (616,124) 5,125,652 2,627,626
Pipeline operations 991,823 (11,756) 4,433,200 163,858
Other -- (3,189,867) 2,230,160 1,966,750
----------- ----------- ----------- -----------
Consolidated 5,686,025 (3,817,747) 11,789,012 4,758,234
Other income 1,272,727
-----------
Loss before income taxes (2,545,020)
Year ended December 31, 2000:
Oil and gas exploration and
production and
operating fees $ 5,735,674 6,000 (8,577,943) 4,164,299 12,292,574
Pipeline operations 2,225,312 13,016 625,486 8,958,876 369,824
Other (19,016) (1,297,234) 789,780 89,488
----------- ----------- ----------- -----------
Consolidated 7,941,970 (9,249,691) 13,912,955 12,751,886
Other expense (647,471)
-----------
Loss before income taxes (9,897,162)
1. Consolidated income (loss) from operations includes $1,223,117 and
$1,188,721 in unallocated general and administrative expenses, and
unallocated depletion, depreciation and amortization of $1,966,750 and
$89,488 for the years ended December 31, 2001 and 2000, respectively.
2. Pipeline depletion, depreciation and amortization includes a provision
for pipeline abandonment of $19,740 for the years ended December 31,
2001 and 2000, respectively. Oil and gas depletion, depreciation and
amortization includes a provision for abandonment costs of platforms
and wells of $13,793 for the year ended December 31, 2001. In addition,
the Company recorded an expense of approximately $1.0 million for the
year ended December 31, 2001, as a result of a change in the estimated
costs associated with the Buccaneer Field abandonment.
3. See the supplemental disclosures for oil and gas producing activities
for discussion of capitalized costs incurred for oil and gas production
operations. Capital expenditures of $1,737,331 were incurred for
pipeline operations for the year ended December 31, 2001. Capitalized
expenditures of $59,305 were incurred for mid-stream projects for the
year ended December 31, 2001.
61
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
The Company's primary market area is the Texas and Louisiana Gulf Coast
region of the United States. The Company has a concentration of credit
risk with customers in the energy and petrochemical industries. The
Company's customers may be similarly affected by changes in economic,
regulatory or other factors. Trade receivables are generally not
collateralized; however, the Company's customers' historical and future
credit positions are thoroughly analyzed prior to extending credit. In
2000, no customer accounted for more than 10% of the Company's total
revenues. Revenues from major customers exceeding 10% of segment
revenues were as follows for the period indicated.
Oil and gas
sales and Pipeline
operating fees operations Total
-------------- -------------- --------------
Year Ended December 31, 2001:
Houston Exploration $ -- 639,975 639,975
(12) Supplemental Oil and Gas Information - Unaudited
The following supplemental information regarding the oil and gas
activities of the Company is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange Commission
("SEC") and SFAS No. 69, Disclosures About Oil and Gas Producing
Activities (`Statement 69").
In November 2000, the Company decided to abandon the Buccaneer Field as
a result of the occurrence of unforeseen adverse events. As a result of
this decision, the leases on the field terminated in January 2001
pursuant to their terms.
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. These reserves and future net revenues reflect capital
expenditures totaling $150,000, $328,000, $81,000, $111,000 and
$225,000 in the years ending December 31, 2002, 2003, 2004, 2005 and
2006, respectively.
Estimated Quantities of Proved Oil and Gas Reserves
Set forth below is a summary of the changes in the estimated quantities
of the Company's crude oil and condensate, and gas reserves for the
periods indicated, as estimated by Ryder Scott Company as of December
31, 2001. All of the Company's reserves are located within the United
States. Proved reserves cannot be measured exactly because the
estimation of reserves involves numerous judgmental determinations.
Accordingly, reserve estimates must be continually revised as a result
of new information obtained from drilling and production history, new
geological and geophysical data and changes in economic conditions.
62
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Proved reserves are estimated quantities of gas, crude oil, and
condensate which geological and engineering data demonstrate, with
reasonable certainty, to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved
developed reserves are proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
Oil Gas
Quantity of Oil and Gas Reserves (Bbls) (Mcf)
-------------------------------- ----------- -----------
Total proved reserves at December 31, 1999 256,224 22,217,942
----------- -----------
Revisions to previous estimates (10,175) (18,507,271)
New discoveries and extensions 3,793 1,868,000
Production (64,707) (911,671)
----------- -----------
Total proved reserves at December 31, 2000 185,135 4,667,000
----------- -----------
Revisions to previous estimates (13,476) (841,816)
Production (40,769) (815,184)
----------- -----------
Total proved reserves at December 31, 2001 130,890 3,010,000
=========== ===========
Proved developed reserves:
December 31, 2001 128,783 2,613,000
December 31, 2000 182,106 3,134,000
Capitalized Costs of Oil and Gas Producing Activities
The following table sets forth the aggregate amounts of capitalized
costs relating to the Company's oil and gas producing activities and
the aggregate amount of related accumulated depletion, depreciation and
amortization as of December 31, 2001:
Unproved properties and prospect generation
costs not being amortized $ 221,832
Proved properties being amortized 27,348,510
Less accumulated depletion, depreciation,
amortization and impairment (24,406,674)
------------
Net capitalized costs $ 3,163,668
============
During 2001, the Company recorded an impairment charge on its oil and
gas properties of $1.1 million. The impairment reflects the recognition
of additional Buccaneer Field plugging and abandonment costs.
63
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
During 2000, the Company recorded an impairment charge on its oil and
gas properties of $10,754,976. The impairment was comprised of a
non-cash write-off of proved reserves from the Buccaneer Field of $5.4
million and the recognition of associated plugging and abandonment
costs estimated to be $5.4 million.
Costs Incurred in Oil and
Gas Producing Activities
The following table reflects the costs incurred in oil and gas property
acquisition, exploration and development activities during the periods
indicated:
Year Ended
December 31,
-----------------------
2001 2000
---------- ----------
Property acquisition costs $ -- --
Exploration costs 143,829 467,256
Development costs 773,115 1,417,790
---------- ----------
$ 916,944 1,885,046
========== ==========
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,
----------------------------
2001 2000
------------ ------------
Future cash inflows $ 10,374,365 51,320,776
Future development costs (1,190,585) (2,397,403)
Future production costs (1,761,074) (2,477,723)
------------ ------------
Future net cash inflows
before income taxes 7,422,706 46,445,650
Future income taxes 10,473,236 (3,490,661)
------------ ------------
Future net cash flows 17,895,942 42,954,661
10% discount factor (920,497) (6,307,411)
------------ ------------
Standardized measure of discounted
future net cash inflow $ 16,975,445 36,647,578
============ ============
64
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Future net cash flows at each year end, as reported in the above
schedule, were determined by summing the estimated annual net cash
flows computed by: (1) multiplying estimated quantities of proved
reserves to be produced during each year by current prices and (2)
deducting estimated expenditures to be incurred during each year to
develop and produce the proved reserves (based on current costs).
Income taxes were computed by applying year-end statutory rates to
pretax net cash flows, reduced by the tax basis of the properties and
available net operating loss carryforwards. The annual future net cash
flows were discounted, using a prescribed 10% rate, and summed to
determine the standardized measure of discounted future net cash flow.
The Company cautions readers that the standardized measure information
which places a value on proved reserves is not indicative of either
fair market value or present value of future cash flows. Other logical
assumptions could have been used for this computation which would
likely have resulted in significantly different amounts. Such
information is disclosed solely in accordance with Statement 69 and the
requirements promulgated by the SEC to provide readers with a common
base for use in preparing their own estimates of future cash flows and
for comparing reserves among companies. Management of the Company does
not rely on these computations when making investment and operating
decisions. Principal changes in the Standardized Measure of Discounted
Future Net Cash Flows attributable to the Company's proved oil and gas
reserves for the periods indicated are as follows:
December 31,
----------------------------
2001 2000
------------ ------------
Sales and transfers, net of production costs* $ (3,538,653) (4,150,204)
Acquisition of reserves -- --
Net change in estimated future development
costs 980,063 (5,495,874)
Extensions and discoveries -- 14,431,684
Revisions in previous quantity estimates (1,663,095) 2,280,195
Net changes in sales and transfer prices,
net of production costs 27,307,388) 6,125,097
Accretion of discount 3,688,897 1,499,151
Net change in income taxes 13,719,714 (153,634)
Change in production rates (timing)
and other (5,551,671) 7,207,408
------------ ------------
Net change $(19,672,133) 21,743,823
============ ============
*47% of the Company's estimated proved oil reserves and 39% of its
estimated proved gas reserves were being produced at December 31, 2001.
65
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(13) Sales of Assets
On January 22, 2001, the Company sold its 50% interest in the Black
Marlin Pipeline System to affiliates of the Williams Companies, Inc.
for approximately $4.6 million. The Black Marlin Pipeline System
includes a 75-mile gas and condensate gathering line with related shore
facilities servicing the High Island Area, offshore Texas (the "Black
Marlin Pipeline") and a 3-mile lateral pipeline extending from High
Island Block A-5 to an interconnection to the Black Marlin Pipeline in
High Island Block A-6 (the "A-5 Lateral").
This disposition was consummated, in part, through a sale of all of the
outstanding capital stock of Black Marlin Pipeline Company (formerly an
indirect wholly owned subsidiary of the Company) the owner of a 50%
interest in the Black Marlin Pipeline, pursuant to a Purchase and Sale
Agreement dated January 12, 2001 (the "Stock Purchase Agreement") among
Black Marlin Energy Company, a wholly owned subsidiary of the Company,
MCNIC Pipeline & Processing Company ("MCNIC"), WBI Southern, Inc.
("WBI") and Williams Field Services Group, Inc. The Company received
$3.6 million for the outstanding capital stock of Black Marlin Pipeline
Company for a gain of $1,305,534.
The remaining part of this disposition was consummated through the sale
of the A-5 Lateral owned 50% by Blue Dolphin Pipe Line Company, a
wholly owned subsidiary of the Company ("BDPL"), pursuant to a Purchase
and Sale Agreement dated January 12, 2001, among BDPL, MCNIC, WBI and
Williams Field Services - Gulf Coast Company, L.P. The Company received
$1.0 million for its interest in the A-5 Lateral, for a gain of
$112,092.
In connection with Blue Dolphin Exploration's acquisition of American
Resources in December 1999, Blue Dolphin Exploration arranged for
Fidelity Oil to acquire an 80% interest in American Resources oil and
gas assets located in the Gulf of Mexico for approximately $24.2
million. For the right to participate in the acquisition of these
assets, Fidelity Oil agreed to assign Blue Dolphin Exploration 10% of
its working interest in the proved properties acquired from American
Resources after it has recovered its investment in these properties. In
the fourth quarter 2001, Fidelity Oil had recovered its investment in
the proved properties. However, instead of assigning 10% of its
interest in the proved properties, Fidelity Oil paid Blue Dolphin $1.4
million in cash in December 2001. The proceeds were accounted for as a
reduction to capitalized costs of oil and gas properties.
(14) Subsequent Event
In February 2002, the Company acquired a 1/3 interest in the Blue
Dolphin Pipeline System and the inactive Omega Pipeline from MCNIC.
Pursuant to the terms of the purchase and sales agreement, Blue Dolphin
issued MCNIC a $750,000 promissory note due December 31, 2006, with
required monthly payments to be made out of 90% of the net revenues of
the interest acquired. The note bears interest at the rate of 6% per
annum and is secured by the interest acquired. Additionally, a
contingent payment of up to $750,000 will be made, if the promissory
note is retired before its maturity date, payable annually after the
66
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
promissory note is retired until December 31, 2006 out of 50% of the
net revenues from the interest acquired. The termination date, December
31, 2006, will be extended by one additional year, up to a maximum of
two years, for years in which non-recurring, extraordinary expenditures
attributable to the interest acquired exceeds $200,000, in the
aggregate, during any year.
On December 2, 1999, the Company, through Blue Dolphin Exploration,
acquired a 75% ownership interest in American Resources by purchasing
approximately 39.5 million shares of American Resources common stock.
On February 19, 2002, the Company completed its acquisition of American
Resources, pursuant to the Amended and Restated Agreement and Plan of
Merger dated as of December 19, 2001 (the "Merger Agreement"). Pursuant
to the Merger Agreement, American Resources became a wholly owned
subsidiary of the Company and each outstanding share of (i) American
Resources common stock, par value $.00001 per share, was converted into
the right to receive, at the option of the holder, either $.06 per
share in cash or .0362 of a share of the Company's Common Stock, par
value $.01 per share (the "Common Stock"), and (ii) American Resources
Series 1993 Preferred Stock, par value $12.00 per share, was converted
into the right to receive, at the option of the holder, either $.07 in
cash or .0301 of a share of Common Stock.
As a result of elections made by American Resources' stockholders, the
Company will issue approximately 273,336 shares of Common Stock and
will pay approximately $255,000 in cash.
67
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures
Upon the recommendation of the Registrant's Audit Committee, on
February 15, 2002, the Registrant's Board of Directors decided not to renew the
engagement of KPMG LLP ("KPMG") as the Registrant's principal accountant and
selected Mann Frankfort Stein & Lipp CPAs, LLP ("Mann Frankfort") as KPMG's
replacement.
In connection with the audits of the Registrant's two fiscal years
ended December 31, 2000, and the subsequent interim period through February 15,
2002, there were no disagreements with KPMG on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedures, which disagreements if not resolved to their satisfaction would have
caused them to make reference in connection with their opinion to the subject
matter of the disagreement. The audit reports of KPMG on the consolidated
financial statements of the Registrant and subsidiaries as of and for the years
ended December 31, 2000 and 1999 did not contain any adverse opinion or
disclaimer of opinion, nor were they qualified or modified as to uncertainty,
audit scope, or accounting principles, except that KPMG's report on the
Registrant's consolidated financial statements for the years ended December 31,
2000 and 1999 contained a separate paragraph stating that "As discussed in Note
1 to the consolidated financial statements, effective January 1, 1999, the
Company changed its method of accounting for costs of start-up activities."
During the two fiscal years ended December 31, 2000 and the subsequent
interim period prior to engaging Mann Frankfort, neither the Registrant nor
anyone on its behalf consulted with Mann Frankfort regarding the application of
accounting principles to a specified transaction, either completed or proposed;
or the type of audit opinion that might be rendered on the Registrant's
financial statements, and neither a written report nor oral advice was provided
to the Registrant by Mann Frankfort that was an important factor considered by
the Registrant in reaching a decision as to any accounting, auditing or
financial reporting issue.
PART III
Item 13. Exhibits and Reports on Form 8-K
(a) 1. Exhibits
No. Description
--- -----------
3.1 (1) Certificate of Incorporation of the Company.
3.2 (2) Certificate of Correction to the Certificate of
Incorporation of the Company dated June 30, 1987.
3.3 (2) Certificate of Amendment to the Certificate of
Incorporation of the Company dated June 30, 1987.
3.4 (2) Certificate of Amendment to the Certificate of
Incorporation of the Company dated December 11, 1989.
68
3.5 (2) Certificate of Amendment to the Certificate of
Incorporation of the Company dated December 14, 1989.
3.6 (2) Bylaws of the Company.
3.7 (4) Certificate of Amendment to the Certificate of
Incorporation of the Company dated December 8, 1997.
4.1 (2) Specimen Certificate of Blue Dolphin Energy Company
Common Stock.
* 10.1 (3) Blue Dolphin Energy Company 1996 Employee Stock Option
Plan.
* 10.2 (7) Blue Dolphin Energy Company 2000 Stock Incentive Plan
10.12 (5) Asset Purchase Agreement between WBI Southern, Inc.,
Blue Dolphin Pipeline Company, Buccaneer Pipe Line
Co. and Mission Energy, Inc.
10.13 (5) Purchase and Sale Agreement between Enron Pipeline
Company, Black Marlin Energy Company and Blue Dolphin
Energy Company.
10.14 (5) Asset Purchase Agreement between WBI Southern, Inc.,
BlackMarlin Pipeline Company and Black Marlin Energy
Company.
10.15 (5) Asset Purchase Agreement between MCNIC Offshore Pipeline
& Processing Company, Black Marlin Pipeline Company
and Black Marlin Energy Company.
10.16 (6) Investment Agreement, as amended, by and between
American Resources Offshore, Inc. and Blue Dolphin
Exploration Company.
10.18 (8) Purchase and Sale Agreement by and between Williams
Field Services Group, Inc. and Black Marlin Energy
Company
10.19 (8) Purchase and Sale Agreement by and between Williams
Field Services - Gulf Coast Company, L.P. and Blue
Dolphin Pipeline Company
10.20 (9) Amended and Restated Agreement and Plan of Merger dated
as of December 19, 2001 (the "Merger Agreement")
among Blue Dolphin Energy Company, American Resources
Offshore, Inc. and BDCO Merger Sub, Inc.
10.21 (10) Amended and Restated Agreement and Plan of Merger,
as amended, among American Resources Offshore, Inc.,
Blue Dolphin Energy Company and BDCO Merger Sub,
Inc. and American Resources Offshore, Inc.
10.22 (9) Letter agreement between Blue Dolphin Exploration
Company and Fidelity Exploration & Production Company.
10.23 (9) Amendment No.1 to the Amended and Restated Agreement
and Plan of Merger.
69
16.1 (10) Letter from KPMG, L.L.P.
21.1** List of Subsidiaries of the Company.
23.1** Consent of Ryde r Scott Company, independent petroleum
engineers.
(1) Incorporated herein by reference to Exhibits filed in connection with
Registration Statement on Form S-4 of ZIM Energy Corp. filed under the
Securities Act of 1933 (Commission File No. 33-5559).
(2) Incorporated herein by reference to Exhibits filed in connection with
Form 10-K of Blue Dolphin Energy Company for the year ended December
31, 1989 under the Securities and Exchange Act of 1934, dated March 30,
1990 (Commission File No. 000-15905).
(3) Incorporated herein by reference to Exhibits filed in connection with
Form 10-K of Blue Dolphin Energy Company for the year ended December
31, 1995 under the Securities and Exchange Act of 1934, dated March 29,
1996 (Commission File No. 000-15905).
(4) Incorporated herein by reference to Exhibits filed in connection with
the definitive Information Statement on Schedule 14C of Blue Dolphin
Energy Company under the Securities and Exchange Act of 1934, dated
November 18, 1997 (Commission File No. 000-15905).
(5) Incorporated herein by reference to Exhibits filed in connection with
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).
(6) Incorporated herein by reference to Exhibits filed in connection with
Schedule 13D of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated October 22, 1999 (Commission File No.
000-15905).
(7) Incorporated herein by reference to Exhibits filed in connection with
the Proxy Statement of Blue Dolphin Energy Company under the Securities
and Exchange Act of 1934, dated May 18, 2000 (Commission File No.
000-15905).
(8) Incorporated herein by reference to Exhibits filed in connection with
Form 8-K of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated January 22, 2001 (Commission File No.
000-15905).
(9) Incorporated herein by reference to Exhibits filed in connection with
Form S-4 of Blue Dolphin Energy Company under the Securities Act of
1933 (Commission File No. 333-82186).
(10) Incorporated herein by reference to Exhibits filed in connection with
Form 8-K of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated February 25, 2002 (Commission File No.
000-15905).
70
* Management Compensation Plan.
** Filed herewith.
(b) Reports on Form 8-K
On December 20, 2001, the Company filed a current report on
Form 8-K dated December 20, 2001, reporting an Amended and
Restated Agreement and Plan of Merger with American Resources
Offshore, Inc. The items reported in such current report were
Item 5 (Other Events).
On February 25, 2002, the Company filed a current report on
Form 8-K dated February 15, 2002, reporting a change in
Certifying Accountant. The items reported in such current
report were Item 4 (Change in Registrant's Certifying
Accountant).
On March 1, 2002, the Company filed a current report on Form
8-K dated February 19, 2002, reporting it completed the
acquisition of American Resources Offshore, Inc. The items in
such current report were Item 2 (Acquisition or Disposition of
Assets).
On March 13, 2002, the Company filed a current report on Form
8-K dated February 28, 2002, reporting the acquisition of an
additional 1/3 interest in the Blue Dolphin Pipeline System
from MCNIC Pipeline & Processing Company. The items reported
in such current report were Item 5 (Other Events).
71
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BLUE DOLPHIN ENERGY COMPANY
(Registrant)
By: /s/ Michael J. Jacobson
------------------------------
Michael J. Jacobson, President
(principal executive officer)
Date: March 28, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Michael J. Jacobson President (principal March 28, 2002
------------------------- executive officer)
Michael J. Jacobson
/s/ G. Brian Lloyd Vice President, Treasurer March 28, 2002
------------------------- (principal accounting
G. Brian Lloyd and financial officer)
/s/ Ivar Siem Chairman March 28, 2002
-------------------------
Ivar Siem
/s/ Harris A. Kaffie Director March 28, 2002
-------------------------
Harris A. Kaffie
/s/ Michael S. Chadwick Director March 28, 2002
-------------------------
Michael S. Chadwick
/s/ Robert D. Wagner, Jr. Director March 28, 2002
-------------------------
Robert D. Wagner, Jr.
72