UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-KSB
[X] Annual Report Under Section 13 or 15(d) of the Securities Exchange Act of
1934
For the fiscal year ended December 31, 2005
[ ] Transition Report Under 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
incorporation or organization) Identification No.)
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, PAR VALUE $.01 PER SHARE
(Title of Class)
Check whether the issuer is not required to file reports pursuant to
Section 13 or 15 (d) of the Exchange Act. [ ]
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. [ ]
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act). Yes No X
--- ---
The issuer's revenues for the year ended December 31, 2005 were $4,511,183.
The aggregate market value of the common stock, par value $.01 per share,
held by non-affiliates of the registrant as of March 21, 2006, was approximately
$20,168,000.
As of March 30, 2006, there were outstanding 11,140,734 shares of common
stock, par value $.01 per share, of the issuer.
DOCUMENTS INCORPORATED BY REFERENCE
Certain sections of the registrant's definitive proxy statement for the
2006 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"), which is to be filed
with the Securities and Exchange Commission pursuant to Regulation 14A, under
the Securities and Exchange Act of 1934 within 120 days of the registrant's
fiscal year ended December 31, 2005, are incorporated by reference in Part III
of this report.
Transitional Small Business Disclosure Format. Yes No X
--- ---
TABLE OF CONTENTS
PAGE
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PART I
Item 1. Description of Business ........................................ 1
Item 2. Description of Property ........................................ 19
Item 3. Legal Proceedings .............................................. 20
PART II
Item 5. Market for Common Stock and Related Stockholder Matters ........ 20
Item 6. Management's Discussion and Analysis of Financial Condition
and Results of Operations ................................... 21
Item 7. Financial Statements ........................................... 30
Item 8. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosures.................................... 59
Item 8A. Controls and Procedures ........................................ 59
PART III
Item 9. Directors and Executive Officers of the Registrant; compliance
with Section 16(a) of the Exchange Act ...................... 60
Item 10. Executive Compensation.......................................... 60
Item 11. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters.............................. 60
Item 12. Certain Relationships and Related Transactions ................. 60
Item 13. Exhibits........................................................ 60
Item 14. Principal Accountant Fees and Services ......................... 62
Signatures .............................................................. 63
i
PART I
Forward Looking Statements. Certain of the statements included in this annual
report on Form 10-KSB, including those regarding future financial performance or
results or that are not historical facts, are "forward-looking" statements as
that term is defined in Section 21E of the Securities Exchange Act of 1934, as
amended, and Section 27A of the Securities Act of 1933, as amended. The words
"expect," "plan," "believe," "anticipate," "project," "estimate," and similar
expressions are intended to identify forward-looking statements. Blue Dolphin
Energy Company (referred to herein, with its predecessors and subsidiaries, as
"Blue Dolphin," "we," "us" and "our") cautions readers that these 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:
- the level of utilization of our pipelines;
- availability and cost of capital;
- actions or inactions of third party operators for properties where we
have an interest;
- the risks associated with exploration;
- the level of production from oil and gas properties that we have
interests in;
- gas and oil price volatility;
- uncertainties in the estimation of proved reserves and in the
projection of future rates of production and timing of development
expenditures;
- regulatory developments; and
- general economic conditions.
Additional factors that could cause actual results to differ materially from
those indicated in the forward-looking statements are discussed under the
caption "Risk Factors". Readers are cautioned not to place undue reliance on
these forward-looking statements which speak only as of the date hereof. We
undertake no duty to update these forward-looking statements. Readers are urged
to carefully review and consider the various disclosures made by us which
attempt to advise interested parties of the additional factors which may affect
our business, including the disclosures made under the caption "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
this report.
ITEM 1. DESCRIPTION OF BUSINESS
THE COMPANY
Blue Dolphin Energy Company, a Delaware corporation formed in 1986, is a holding
company and conducts substantially all of its operations through its
subsidiaries. We conduct our business activities in two primary business
segments: (i) pipeline transportation and related services for
producer/shippers, and (ii) oil and gas exploration and production.
Substantially all of our assets consist of equity interests in our subsidiaries.
Our operating subsidiaries are:
- Blue Dolphin Pipe Line Company, a Delaware corporation;
- Blue Dolphin Petroleum Company, a Delaware corporation;
- Blue Dolphin Exploration Company, a Delaware corporation; and
- Blue Dolphin Services Co., a Texas corporation.
Our principal executive office is located at 801 Travis, Suite 2100, Houston,
Texas, 77002, and our telephone number is (713) 227-7660. Our shore-based
facilities are maintained in Freeport, Texas, and serve our Gulf of Mexico
operations. We have 7 full-time employees. Our common stock is traded on the
National Association of Securities Dealers, Inc. Automated Quotation System
("NASDAQ") Small Cap
1
Market under the trading symbol "BDCO." Our home page address on the world wide
web is http://www.blue-dolphin.com.
Certain terms that are commonly used in the oil and gas industry, including
terms that define our rights and obligations with respect to our properties, are
defined in the "Glossary of Certain Oil and Gas Terms" of this Form 10-KSB.
RECENT DEVELOPMENTS
In March 2006, we entered into a stock purchase agreement with certain
accredited investors for the private placement of 1,171,432 shares of our common
stock at a purchase price of $1.75 per share. The net proceeds from the offering
after the payment of commissions and expenses were approximately $2,025,000. The
Company expects to use the proceeds for possible acquisitions and planned
expansions of its facilities, as well as for working capital needs and general
corporate purposes. In addition, in connection with the terms of the placement
agency agreement with Starlight Investments, LLC, we issued warrants to purchase
an aggregate of 8,572 shares of common stock. The warrants vest immediately upon
issuance and the exercise price per share varies based on the following
conditions: (i) until the later of the registration of the warrants or one year
from the issue date, 110% of the purchase price per share in the offering, (ii)
from the later of (x) the registration of the warrants and (y) one year, until
two years from the issue date, 120% of the purchase price per share in the
offering and (iii) after the expiration of two years from the issue date of the
warrants, 130% of the purchase price per share in the offering.
During the final two quarters of 2005, we entered into gas and condensate
transportation and handling agreements with three new shippers on the Blue
Dolphin Pipeline System. The first agreements were entered into with Manti
Operating Company ("Manti") on July 12, 2005 to deliver production into the Blue
Dolphin System in Galveston area state tract 348. We began providing
transportation and handling services to Manti when it commenced production in
August 2005. We entered into agreements with the second new shipper on September
28, 2005 to provide transportation and handling services for production
delivered into the Blue Dolphin Pipeline System at our Galveston Block 288C
platform. Agreements were signed with the third new shipper on October 12, 2005.
The second and third new shippers are expected to commence production around
mid-year 2006.
In September 2005, we began receiving payments for an approximate 2.8%
contractual after-payout working interest realized in High Island Block 37. We
received an initial payment of approximately $1.3 million on September 2, 2005,
representing our share of net revenues from the estimated payout date of July 1,
2004 through May 2005. Through December 31, 2005, we received four payments
totaling approximately $1,769,000 and recognized net revenues of $2,397,000 for
our working interest in the sale of gas and oil from two producing wells in the
block. The two wells are currently producing at a combined rate of approximately
23 MMcf per day.
Also in September 2005, High Island Block A-7 resumed production after the
successful recompletion of two wells. Prior to the recompletions, the block was
generating production from a single well. This well had generated significant
revenues for us in 2003 when our back-in interest initially paid out, and to a
lesser extent in 2004; however, production had declined naturally over time. The
well had averaged less than 1 MMcf per day for the first and second quarters of
2005, prior to recompletion. The two wells initially produced at a combined rate
of approximately 10 MMcf per day when production was resumed, however, the wells
were shut-in when Hurricane Rita struck in mid-September. Production was delayed
for a period of time while 3rd party transporters made repairs following
Hurricane Rita. Production was re-established for one well in late October and
in early November for the second well. Only one of the wells is currently
producing. Production from that well is currently approximately 7 MMcf per day.
On February 28, 2005 (effective as of January 1, 2005), we entered into an
amendment (the "Amendment") to the Asset Purchase Agreement dated February 1,
2002 (the "Purchase Agreement") with MCNIC Offshore Pipeline and Processing
Company ("MCNIC"). Under the terms of the original
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Purchase Agreement, we acquired MCNIC's one-third interests in both the Blue
Dolphin System (as described below in "Pipeline Operations and Activities") and
the inactive Omega Pipeline. Pursuant to the terms of the Amendment, the
promissory note that we originally issued to MCNIC in the principal amount of
$750,000 due December 31, 2006 (the "Original Promissory Note") was exchanged
for a new non-interest bearing promissory note in the principal amount of
$250,000 (the "New Promissory Note"), and all accrued interest on the Original
Promissory Note, $132,368 at December 31, 2004, was forgiven. In addition to the
New Promissory Note, MCNIC can receive additional payments of up to $500,000
from 50% of the net profits, if any, realized from the one-third interest in the
Blue Dolphin System through December 31, 2006. We made a principal payment on
the New Promissory Note of $30,000 upon the execution of the Amendment. Under
the terms of the New Promissory Note we will make monthly principal payments of
$10,000 through its maturity date of December 31, 2006. The principal amount of
the New Promissory Note may be increased by up to $500,000 if we sell 50% or
more of our 83% interest in the Blue Dolphin System before December 31, 2006.
The maximum amount of additional payments MCNIC could receive over the $250,000
New Promissory Note is $500,000.
PIPELINE OPERATIONS AND ACTIVITIES
Our pipeline assets are held in, and operations conducted by, Blue Dolphin Pipe
Line Company.
The economic return on our pipeline system investments is solely dependent upon
the amounts of gas and condensate gathered and transported through our pipeline
systems. Currently, the level of throughput on our pipeline systems is
significantly below full capacity. Competition for provision of gathering and
transportation services similar to ours is intense in the market areas we serve.
See "Competition" below. Since contracts for gathering and transportation
services with third party producer/shippers may be for specified time periods,
there can be no assurance that current or future producer/shippers will not
subsequently tie-in to alternative transportation systems or that current rates
charged will be maintained in the future. We actively market our gathering and
transportation services to producer/shippers operating in the vicinity of our
pipeline systems. Future utilization of the pipelines and related facilities
will depend upon the success of drilling programs around the pipelines, and the
attraction, and retention, of producer/shippers to the systems.
Blue Dolphin Pipeline System. The Blue Dolphin Pipeline System includes the Blue
Dolphin Pipeline, an offshore platform, the Buccaneer Pipeline, onshore
facilities for condensate and gas separation and dehydration, 85,000 Bbls of
above-ground tankage for storage of crude oil and condensate, a barge loading
terminal on the Intracoastal Waterway and 360 acres of land in Brazoria County,
Texas where the Blue Dolphin Pipeline comes ashore and where the pipeline system
shore facilities, pipeline easements and rights-of-way are located (the "Blue
Dolphin System"). We own an 83% undivided interest in the Blue Dolphin System.
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 Blue Dolphin Pipeline consists of two segments. The offshore segment
transports both gas and liquids (crude oil and condensate) and is comprised of
approximately 34 miles of 20-inch pipeline from a platform in Galveston Area
Block 288 to shore. The offshore segment includes a platform and 5 field
gathering lines totaling approximately 27 miles, connected to the main 20-inch
line. An additional 4 miles of 20-inch pipeline onshore connects the offshore
segment to the onshore facility at Freeport, Texas. The 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. The Buccaneer Pipeline, an 8-inch liquids
pipeline, transports crude oil and condensate from the storage tanks to our
barge-loading terminal on the Intracoastal Waterway near Freeport, Texas for
sale to third parties.
3
Various fees are charged to producer/shippers for provision of transportation
and shore facility services. The Blue Dolphin System has an aggregate capacity
of approximately 160 MMcf per day of gas and 7,000 Bbls per day of crude oil and
condensate. Gas throughput for the Blue Dolphin System averaged approximately 6%
and 4% of capacity during 2005 and 2004, respectively. Currently, the Blue
Dolphin System is transporting approximately 9 MMcf of gas per day. All gas and
liquids volumes transported in 2005 and 2004 were attributable to production
from third party producer/shippers. See Note 12 to the Consolidated Financial
Statements included in Item 7.
During late 2004, due to operating losses incurred by us on the Blue Dolphin
System, we renegotiated our gas transportation rates with our shippers,
effective October 1, 2004. As a result, 2005 gas transportation revenues from
the Blue Dolphin System totaled approximately $1,154,000. Without the increase
in rates, gas transportation revenues for 2005 would have been 56% less;
approximately $505,000.
Galveston Area Block 350 Pipeline. We own an 83% ownership interest in an
8-inch, 12.78 mile pipeline extending from Galveston Area Block 350 to an
interconnect with a transmission pipeline in Galveston Area Block 391 (the "GA
350 Pipeline"), approximately 14 miles south of the Blue Dolphin Pipeline.
Current system capacity on the GA 350 Pipeline is 65 MMcf of gas per day. Gas
throughput for the GA 350 Pipeline averaged approximately 18% and 26% of
capacity during 2005 and 2004, respectively. The pipeline currently transports
approximately 9 MMcf of gas per day. All gas and liquids volumes transported
were attributable to production from third party producer/ shippers.
Other. We also own an 83% undivided interest in the Omega Pipeline, which is
currently inactive. The Omega Pipeline originates in the High Island Area, East
Addition Block A-173 and extends to West Cameron Block 342 , where it was
previously connected to the High Island Offshore System ("HIOS"). Reactivation
of the Omega Pipeline will be dependent upon future drilling activity in the
vicinity and successfully attracting producer/shippers to the system.
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Although we sold substantially all of our producing oil and gas properties in
2002, we continue our oil and gas exploration and production activities, which
include the exploration, acquisition, development, operation and, when
appropriate, disposition of oil and gas properties. We focus our oil and gas
activities in the western Gulf of Mexico, off the coast of Texas. We currently
own seismic and other data that may be used to evaluate and develop prospects,
including a non-exclusive license to approximately 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. Our oil and gas assets are held by
Blue Dolphin Petroleum Company and Blue Dolphin Exploration Company.
The leasehold interests we hold in properties are subject to royalty, overriding
royalty and interests of others. In the future, our properties may become
subject to burdens and encumbrances typical to oil and gas operators, such as
liens incident to operating agreements and current taxes, development
obligations under oil and gas leases and other encumbrances.
The following is a description of our oil and gas exploration and production
assets and activities:
High Island Block 37. High Island Block 37 is located 15 miles south of Sabine
Pass, offshore Texas, in an average water depth of 36 feet. We own an
approximate 2.8% contractual working interest in this lease that covers
approximately 5,760 acres. The lease contains two producing wells which are
operated by Seneca Resources Corporation. For the year ended December 31, 2005,
we recorded gross revenues from sales of gas and oil in High Island Block 37 of
approximately $2,414,000.
High Island Block A-7. High Island Block A-7 is located 33 miles southeast of
Boliver Peninsula, offshore Texas, in an average water depth of 39 feet. We own
an 8.9% working interest in this lease that
4
covers approximately 5,760 acres. The lease contains one currently producing
well which is operated by Hydro Gulf of Mexico, LLC (formerly Spinnaker
Exploration Company). During the years ended December 31, 2005 and 2004, we
recorded gross revenues from gas and oil sales of approximately $722,000 and
$332,000, respectively, from this field.
Unproved Leasehold Interests. Our prospect inventory consists of one prospect on
the offshore lease for West Cameron Area Block 212. A prospect is a property in
which we own an interest or have operating rights and have what we believe,
based on available seismic and geological information, to be indications of oil
or natural gas.
In December 2004, we placed our interest in Galveston Area Blocks 287 and 297 in
the Gulf of Mexico with third parties. These blocks were part of a prospect we
generated which also included Galveston Area Block 298. A well was drilled in
Galveston Area Block 297, which was not successful. As a result of the placement
of our working interest in Galveston Area Blocks 287 and 297, we received
proceeds of approximately $160,000. The leases for Galveston Area Blocks 287 and
297 have now expired.
In November 2005, the leases covering our interests in Galveston Area Blocks 271
and 284 expired.
Abandonment of Buccaneer Field. We owned a 100% working interest in the
Buccaneer Field. In November 2000, we elected to abandon the Buccaneer Field due
to adverse developments in the field. In August 2001, we reached an agreement
with Tetra Applied Technologies, Inc. ("Tetra") to remove the Buccaneer Field
platforms for a cost of approximately $2.6 million on extended payment terms. To
provide security for the extended payment terms, we provided Tetra with a first
lien on a 50% interest in the Blue Dolphin System. Operations to remove the
platforms commenced in August 2001 and were completed in August 2003. Before the
removal operations were completed we commenced discussions with the Texas Parks
and Wildlife Department ("TPW"), and were granted permission to leave the
underwater portion of the platforms in place as artificial reefs. As a result of
TPW's approval, the scope of the work to be performed by Tetra was changed to
include reefing, instead of complete removal. Pursuant to the Deeds of Donation
with TPW, we agreed to pay TPW $390,000, of which $350,000 represented half of
the site clearance work that was eliminated and $40,000 represented the cost of
buoys to mark the reef sites. While the scope of work with Tetra was changed,
the contract price and payment terms remained unchanged. Our payments to Tetra
began in September 2003. In August 2004, we negotiated an extension of the
payment terms of our remaining indebtedness to Tetra in the amount of $668,000
originally due in September and October 2004. Under the new terms we agreed to
pay the outstanding balance to Tetra in twelve monthly installments of $55,667
beginning September 1, 2004, plus interest on the outstanding balance at the
rate of 6% per annum. On August 1, 2005, we made our final payment to Tetra.
Proved Oil and Gas Reserves. We have prepared estimates of proved reserves,
future net revenues, and discounted present value of future net revenues to our
net interest as of December 31, 2005.
The quantities of proved oil and gas reserves presented below include only those
amounts which we reasonably expect to recover in the future from known oil and
gas reservoirs under existing economic and operating conditions. Therefore,
proved reserves are limited to those quantities that are believed to be
recoverable at prices and costs, and under regulatory practices and technology
existing at the time of the estimate. Accordingly, changes in oil and gas
prices, operation and development costs, regulations, technology, future
production and other factors, many of which are beyond our control, could
significantly affect the estimates of proved reserves and the discounted present
value of future net revenues attributable thereto.
Estimates of production and future net revenues cannot be expected to represent
accurately the actual production or revenues that may be recognized with respect
to oil and gas properties or the actual present market value of such properties.
For further information concerning our proved reserves, changes in proved
reserves, estimated future net revenues and costs incurred in our oil and gas
activities and the
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discounted present value of estimated future net revenues from our proved
reserves, see Note 13, Supplemental Oil and Gas Information, to the Consolidated
Financial Statements included in Item 7.
The following table presents the estimates of proved reserves, proved developed
reserves, and proved undeveloped reserves (as hereinafter defined), future net
revenues and the discounted present value of future net revenues from proved
reserves after income taxes to our net interest in oil and gas properties as of
December 31, 2005. The discounted present value of future net revenues and
future net revenues are calculated using the SEC Method (defined below) and are
not intended to represent the current market value of the oil and gas reserves
we own.
PROVED RESERVES
As of December 31, 2005 (1)(2)
Present Value
of Future Net
Cash Inflows
Net Oil Net Gas After Income
Reserves Reserves Taxes (1)
(Mbbls) (MMcf) (in thousands)
-------- -------- ------------
Total Proved Reserves
High Island Block A-7 0.7 132 $ 794
High Island Block 37 0.2 209 1,311
--- --- ------
0.9 341 $2,105
Total Proved Developed
High Island Block A-7 0.7 132 $ 794
High Island Block 37 0.2 209 1,311
--- --- ------
0.9 341 $2,105
----------
(1) The estimated present value of future net cash outflows after income taxes
from our proved reserves has been determined by using prices of $56.00 per
barrel of oil and $11.00 per Mcf of gas, representing the December 31, 2005
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").
(2) As of December 31, 2005, we reported no proved undeveloped reserves.
Capital Expenditures for Proved Reserves. The following table presents
information regarding the costs we expect to incur in development activities
associated with our proved reserves. These expenditures include recompletion
costs, workover costs and the cost of drilling additional wells required to
recover proved reserves and the plugging and abandonment of wells. The
information regarding proved reserves summarized in the preceding table assumes
the following estimated undiscounted capital expenditures in the years
indicated.
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Estimated Undiscounted Capital Expenditures
To Develop Proved Reserves
For the years ending December 31,
(in thousands)
-------------------------------------------
2006 2007 2008 2009 2010
---- ---- ---- ---- ----
High Island Block A-7 -- -- 218 -- --
High Island Block 37 -- -- 50 -- --
We will continue to evaluate our capital expenditure program based on, among
other things, demand and prices obtainable for our production. The availability
of capital resources and the willingness of other working interest owners to
participate in development operations may affect the timing for further
development, and there can be no assurance that the timing of the development of
such reserves will be as currently planned.
Production, Price and Cost Data. The following table presents information
regarding production volumes and revenues, average sales prices and costs (after
deduction of royalties and interests of others) with respect to crude oil,
condensate, and gas attributable to our interest for each of the periods
indicated.
NET PRODUCTION, PRICE AND COST DATA
Year ended December 31,
----------------------------------
2005 2004 2003
---------- -------- ----------
Gas:
Production (Mcf) 378,791 66,491 274,268
Revenue $3,071,811 $367,611 $1,513,182
Average Production (Mcf) per day (*) 1,037.8 182.2 751.4
Average Sales Price Per Mcf $ 8.11 $ 5.53 $ 5.52
Oil:
Production (Bbls) 781 810 2,271
Revenue $ 40,481 $ 28,089 $ 68,872
Average Production (Bbls) per day (*) 2.1 2.2 6.2
Average Sales Price Per Bbl $ 51.83 $ 34.68 $ 30.33
Production Costs (**):
Per Mcfe: $ 0.40 $ 1.88 $ 0.65
----------
(*) Average production is based on a 365 day year. However, 2005 average
production per day contains 549 days of production from High Island Block
37 and 2003 contains 255 days of production.
(**) Production costs, exclusive of workover costs, are costs incurred to
operate and maintain wells and equipment and to pay production taxes.
Drilling Activity. During September 2005, two wells in High Island Block A-7
were successfully recompleted and resumed production at a significantly higher
rate than the single well that produced through the first and second quarters of
2005. The single well averaged less than 1 MMcf per day during the first and
second quarters. The two recompleted wells averaged 5.4 MMcf per day during the
fourth quarter, including the period of time that the wells were shut in.
Capital expenditures for the recompletions net to our interest totaled
approximately $71,000.
EMPLOYEES
We maintain a professional staff of seven full-time employees and two
consultants capable of supervising and coordinating the operation and
administration of our oil and gas properties and pipeline and other
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assets. From time to time, major maintenance, engineering and construction
projects are contracted to third-party engineering and service companies.
CUSTOMERS
We generated revenues from both of our primary business segments. Hydro Gulf,
LLC and Fidelity Exploration and Production Company accounted for approximately
16.0% and 53.5%, respectively, of our revenues in 2005. Revenues from customers
exceeding 10% of revenues were as follows for 2005 and 2004:
Oil and gas Pipeline
Sales Operations Total
----------- ---------- ----------
Year ended December 31, 2005:
Hydro Gulf, LLC (formerly Spinnaker $ 722,499 -- $ 722,499
Exploration Company)
Fidelity Exploration and Production
Company $2,413,511 -- $2,413,511
Year ended December 31, 2004:
Hydro Gulf, LLC (formerly Spinnaker
Exploration Company) $ 331,858 -- $ 331,858
Houston Exploration -- $239,444 $ 239,444
Apache Corporation -- $229,265 $ 229,265
Kerr McGee Oil & Gas -- $152,487 $ 152,487
COMPETITION
All segments of our business are highly competitive. Vigorous competition occurs
among oil, gas and other energy sources, and between producers, transporters,
and distributors of oil and gas. Our pipeline business faces competition from
other pipelines in the markets that we serve. The principal elements of
competition among pipelines are rates, terms of service, access to markets,
flexibility and reliability of service. Our oil and natural gas business
competes for the acquisition of oil and natural gas properties, primarily on the
basis of the price to be paid for such properties, with numerous entities,
including major oil companies, independent oil and natural gas concerns and
individual producers and operators. Many of these competitors are large,
well-established companies and have financial and other resources substantially
greater than ours, which give them an advantage over us in evaluating and
obtaining properties and prospects. Our ability to acquire additional oil and
natural gas properties and to discover reserves in the future will depend upon
our ability to evaluate and select suitable properties and consummate
transactions in a highly competitive environment. There is also competition for
the hiring of experienced personnel to manage and operate our assets. Several
highly competitive alternative transportation and delivery options exist for
current and potential customers of our traditional gas and oil gathering and
transportation business. Competition also exists with other industries in
supplying the energy and fuel needs of consumers.
MARKETS
The availability of a ready market for oil and gas, and the prices of such oil
and gas, depends upon a number of factors, which are beyond our control. These
include, among other things:
- the level of domestic production;
- actions taken by foreign oil and gas producing nations;
- the availability of pipelines with adequate capacity;
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- the availability of vessels for direct shipment;
- lightering, transshipment and other means of transportation;
- the availability and marketing of other competitive fuels;
- fluctuating and seasonal demand for oil, gas and refined products; and
- the extent of governmental regulation and taxation (under both present
and future legislation) of the production, importation, refining,
transportation, pricing, use and allocation of oil, gas, refined
products and alternative fuels.
In view of the many uncertainties affecting the supply and demand for crude oil,
gas and refined petroleum products, it is not possible to predict accurately the
prices or marketability of the gas and oil produced for sale or prices
chargeable for transportation and storage services, which we provide. Our sale
of natural gas is generally made at the market prices at the time of sale.
Therefore, even though we sell natural gas to major purchasers, we believe other
purchasers would be willing to buy our natural gas at comparable market prices.
GOVERNMENTAL REGULATION
The production, processing, marketing, and transportation of oil and gas by us
are subject to federal, state and local regulations which can have a significant
impact upon our overall operations.
Federal Regulation of Natural Gas Transportation. The transportation and resale
of gas in interstate commerce have been regulated by the Natural Gas Act
("NGA"), the Natural Gas Policy Act ("NGPA"), and the rules and regulations
promulgated by the Federal Energy Regulatory Commission ("FERC"). In the past,
the federal government has regulated the prices at which gas could be sold. In
1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all
remaining Natural Gas Act and Natural Gas Policy Act price and non-price
controls affecting producer sales of gas, effective January 1, 1993. The Energy
Policy Act of 2005 did not alter our non-FERC-jurisdictional status, but has
greatly expanded FERC's authority, including enforcement authority against
market manipulation "in connection with" FERC-jurisdictional transactions. The
nature and extent of FERC's implementation of its new authorities is not yet
known. Additionally, energy pricing has attracted renewed political interest.
Thus Congress could reenact price controls in the future. The rates, terms and
conditions applicable to interstate transportation of gas by pipelines are
regulated by the FERC under the NGA, as well as under Section 311 of the NGPA.
In the fall of 2005, FERC launched a Notice of Inquiry into potential additional
regulation of offshore gathering operations that, unlike Blue Dolphin Pipe Line
Company, are affiliated with interstate pipelines and have the potential to
engage in anticompetitive behavior, conditioning access to interstate pipeline
service upon use of the affiliated gathering line.
All of our pipelines located offshore in federal waters are subject to the
requirements of the Outer Continental Shelf Lands Act ("OCSLA"). The FERC has
stated that non-jurisdictional gathering lines, as well as interstate pipelines,
are fully subject to the open access and nondiscrimination requirements of
OCSLA's Section 5, which generally authorizes the FERC to insure that gas
pipelines on the Outer Continental Shelf ("OCS") will transport for non-owner
shippers in a nondiscriminatory manner and will be operated in accordance with
certain pro-competitive principles.
Further FERC initiatives concerning possibly diminished Natural Gas Act
regulation of pipelines on the OCS and/or broader regulation under the OCSLA
remain possible and could cause increased regulatory compliance costs. Since all
of our offshore pipelines fall within the exemption for feeder facilities and
already operate on the basis required under OCSLA, we do not anticipate
significant changes directly resulting from requirements concerning
nondiscriminatory open access transportation.
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
9
includes various transportation, safety, environmental and non-discriminatory
purchase/transport requirements.
Federal Regulation of Oil Pipelines. Our operation of the Buccaneer Pipeline has
been subject to a variety of regulations promulgated by the FERC and imposed on
all oil pipelines pursuant to federal law. Recently, however, oil pipelines have
been granted permanent exemptions from certain FERC filing requirements because
of rulings that oil pipeline transportation tariff movements of crude petroleum
occurring solely on or across the OCS, or across the OCS to onshore points where
transportation ends are not subject to FERC jurisdiction under the OCSLA or the
Interstate Commerce Act.
Safety and Operational Regulations. Our operations are generally subject to
safety and operational regulations administered primarily by the United States
Minerals Management Service ("MMS"), the U.S. Department of Transportation, the
U.S. Coast Guard, the FERC and/or various state agencies. In addition, the OCSLA
authorizes regulations relating to safety and environmental protection
applicable to leases and permittees operating on the OCS. Specific design and
operational standards may apply to OCS vessels, rigs, platforms and structures.
Violations of lease conditions or regulations issued pursuant to the OCSLA can
result in substantial civil and criminal penalties, as well as potential court
injunctions curtailing operations and the cancellation of leases. Such
enforcement liabilities can result from either governmental or private
prosecution. Currently, we believe that we are in material compliance with the
various safety and operational regulations that we are subject to. However, as
safety and operational regulations are frequently changed, we are unable to
predict the future effect changes in these regulations will have on our
operations, if any.
Federal Oil and Gas Leases. All of our exploration and production operations are
currently located on federal oil and gas leases in the OCS, which are
administered by the MMS. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the OCSLA that are subject to interpretation
and change by the MMS. For offshore operations, lessees must obtain MMS approval
for exploration plans and development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency, lessees must obtain a permit from the MMS prior
to the commencement of drilling. The MMS has promulgated regulations requiring
offshore production facilities located on the OCS to meet stringent engineering
and construction specifications. To cover the various obligations of lessees on
the OCS, the MMS generally requires that lessees have substantial net worth or
post bonds or other acceptable assurance that such obligations will be met. The
cost of these bonds or other surety can be substantial, and there is no
assurance that bonds or other surety can be obtained in all cases. We are
currently in compliance with the bonding requirements of the MMS. Under some
circumstances, the MMS may require any of our operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially
adversely affect our financial condition and results of operations.
With respect to our operations conducted on offshore federal leases, liability
may generally be imposed under OCSLA for costs of clean-up and damages caused by
pollution resulting from such operations, other than damages caused by acts of
war or the negligence of third parties. Under certain circumstances, including
but not limited to conditions deemed a threat or harm to the environment, the
MMS may also require any of our operations on federal leases to be suspended or
terminated in the affected area. Furthermore, the MMS generally requires that
offshore facilities be dismantled and removed within one year after production
ceases or the lease expires.
Environmental Regulation. Our activities with respect to (1) exploration,
development and production of oil and natural gas and (2) the operation and
construction of pipelines, plants, and other facilities for the transportation
and processing, and storage of oil and natural gas are subject to stringent
environmental regulation by local, state and federal authorities, including the
U.S. Environmental Protection Agency ("EPA"). Such regulation has increased the
cost of planning, designing, drilling, operating and in some
10
instances, abandoning wells and related equipment. Similarly, such regulation
has also increased the cost of design, construction, and operation of crude oil
and natural gas pipelines and processing facilities. Although we believe that
compliance with existing environmental regulations will not have a material
adverse affect on operations or earnings, there can be no assurance that
significant costs and liabilities, including civil and criminal penalties, will
not be incurred. Moreover, future developments, such as stricter environmental
laws and regulations or claims for personal injury or property damage resulting
from our operations, could result in substantial costs and liabilities. It is
not anticipated that, in response to such regulation, we will be required in the
near future to expend amounts that are material relative to our total capital
structure.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA") imposes liability, without regard to fault or the legality of the
original conduct, on responsible parties with respect to the release or
threatened release of a "hazardous substance" into the environment. Responsible
parties, which include the present owner or operator of a site where the release
occurred, the owner or operator of the site at the time of disposal of the
hazardous substance, and persons that disposed or arranged for the disposal of a
hazardous substance at the site, are liable for response and remediation costs
and for damages to natural resources. Petroleum and natural gas are excluded
from the definition of "hazardous substances"; however, this exclusion does not
apply to all materials used in our operations. At this time, neither we nor any
of our predecessors have been designated as a potentially responsible party
under CERCLA.
The federal Resource Conservation and Recovery Act ("RCRA") and its state
counterparts regulate solid and hazardous wastes and impose civil and criminal
penalties for improper handling and disposal of such wastes. EPA and various
state agencies have promulgated regulations that limit the disposal options for
such wastes. Certain wastes generated by our oil and gas operations are
currently exempt from regulation as "hazardous wastes," but in the future could
be designated as "hazardous wastes" under RCRA or other applicable statutes and
therefore may become subject to more rigorous and costly requirements.
We currently own or lease, or have in the past owned or leased, various
properties used for the exploration and production of oil and gas or used to
store and maintain equipment regularly used in these operations. Although our
past operating and disposal practices at these properties were standard for the
industry at the time, hydrocarbons or other substances may have been disposed of
or released on or under these properties or on or under other locations. In
addition, many of these properties have been operated by third parties whose
waste handling activities were not under our control. These properties and any
waste disposed thereon may be subject to CERCLA, RCRA, and state laws which
could require us to remove or remediate wastes and other contamination or to
perform remedial plugging operations to prevent future contamination.
The Oil Pollution Act of 1990 ("OPA") and regulations promulgated thereunder
include a variety of requirements related to the prevention of oil spills and
impose liability for damages resulting from such spills. OPA imposes liability
on owners and operators of onshore and offshore facilities and pipelines for
removal costs and certain public and private damages arising from a spill. OPA
establishes a liability limit for onshore facilities of $350 million and for
offshore facilities of all removal costs plus $75 million, and lesser liability
limits for vessels depending upon their size. A party cannot take advantage of
the liability limits if the spill is caused by gross negligence or willful
misconduct or resulted from a violation of federal safety, construction, or
operating regulations. If a party fails to report a spill or cooperate in the
cleanup, liability limits likewise do not apply. OPA imposes ongoing
requirements on responsible parties, including proof of financial responsibility
for potential spills. The amount of financial responsibility required depends
upon a variety of factors including the type of facility or vessel, its size,
storage capacity, oil throughput, proximity to sensitive areas, type of oil
handled, history of discharges, worst-case spill potential and other factors. We
believe we have established adequate financial responsibility. While the
financial responsibility requirements under OPA may be amended to impose
additional costs on us, the
11
impact of such a change is not expected to be any more burdensome on us than on
others similarly situated.
The Clean Air Act and state air quality laws and regulations contain provisions
that impose pollution control requirements on emissions to the air and require
permits for construction and operation of certain emissions sources, including
sources located offshore. We may be required to incur capital expenditures for
air pollution control equipment in connection with maintaining or obtaining
operating permits and approvals addressing emission-related issues, although we
do not expect to be materially adversely affected by such expenditures.
The Clean Water Act ("CWA") regulates the discharge of pollutants to waters of
the United States and imposes permit requirements on such discharges, including
discharges to wetlands. Federal regulations under the CWA and OPA require
certain owners or operators of facilities that store or otherwise handle oil, to
prepare and implement spill prevention, control and countermeasure plans and
facility response plans relating to the possible discharge of oil into surface
waters. With respect to certain of our operations, we are required to prepare
and comply with such plans and to obtain and comply with permits. The CWA also
prohibits spills of oil and hazardous substances to waters of the United States
in excess of levels set by regulations and imposes liability in the event of a
spill. State laws further provide varying civil and criminal penalties and
liabilities for the spills to both surface and groundwaters. We believe we are
in substantial compliance with the requirements of the CWA, OPA, and state laws,
and that any non-compliance would not have a material adverse effect on us.
Various federal and state programs regulate the conservation and development of
coastal resources. The federal Coastal Zone Management Act was passed to
preserve and, where possible, restore the natural resources of the coastal zone
of the United States of America and to provide for federal grants for state
management programs that regulate land use, water use and coastal development.
Under the Louisiana Coastal Zone Management Program, coastal use permits are
required for certain activities, even if the activity only partially infringes
on the coastal zone. Among other things, projects involving use of state lands
and water bottoms, dredge or fill activities that intersect with more than one
body of water, mineral activities, including the exploration and production of
oil and gas, and pipelines for the gathering, transportation or transmission of
oil, gas and other minerals require such permits. General permits, which entail
a reduced administrative burden, are available for a number of routine oil and
gas activities. The Texas Coastal Coordination Act ("CCA") establishes the Texas
Coastal Management Program that applies in the nineteen Texas counties that
border the Gulf of Mexico and its tidal bays. The CCA provides for the review of
state and federal agency rules and agency actions for consistency with the goals
and policies of the Coastal Management Plan. These coastal programs may affect
agency permitting of our facilities.
Legislation and Rulemaking. In October 1996 the U.S. Congress enacted the Coast
Guard Authorization Act of 1996 (P.L. 104-324) which amended the OPA to
establish requirements for evidence of financial responsibility for certain
offshore facilities. The amount required is $35 million for certain types of
offshore facilities located seaward of the seaward boundary of a state,
including properties used for oil transportation. We currently maintain this
statutory $35 million coverage.
Federal and state legislative rules and regulations are pending that, if
enacted, could significantly affect the oil and gas industry. It is impossible
to predict which of those federal and state proposals and rules, if any, will be
adopted and what effect, if any, they would have on our operations.
In addition, various federal, state and local laws and regulations covering the
discharge of materials into the environment, occupational health and safety
issues, or otherwise relating to the protection of public health and the
environment, may affect our operations, expenses and costs. The trend in such
regulation has been to place more restrictions and limitations on activities
that may impact the general or work environment, such as emissions of
pollutants, generation and disposal of wastes, and use and handling of chemical
substances. It is not anticipated that, in response to such regulation, we will
be required in the
12
near future to expend amounts that are material relative to our total capital
structure. However, it is possible that the costs of compliance with
environmental and health and safety laws and regulations will continue to
increase. Given the frequent changes made to environmental and health and safety
regulations and laws, we are unable to predict the ultimate cost of compliance.
RISK FACTORS
We are primarily dependent on revenues from our pipeline systems and our working
interests in two oil and gas producing properties.
Although revenues from oil and gas sales accounted for approximately 69.5% of
our total revenues in 2005, as a result of our sale of substantially all of our
proved oil and gas reserves in 2002 and the limited amount of reserves on
properties we own interests in, we expect that our future revenues will be
primarily dependent on the level of use of our pipeline systems. Various factors
will influence the level of use of our pipeline systems including the success of
drilling programs in the areas near our pipelines and our ability to attract new
producer/shippers. There are various pipelines in and around our pipeline
systems that we vigorously compete with to attract new producer/shippers to our
pipeline systems. There can be no assurance that we will be successful in
attracting new producer/shippers to our pipeline systems.
Furthermore, the rate of production from oil and gas properties generally
declines as reserves are depleted. Our working interests are in properties in
the Gulf of Mexico where, generally, the rate of production declines more
rapidly than in many other producing areas of the world. As the level of
production from these properties declines our revenue from these interests will
decrease. Unless we are able to replace this revenue, with revenue from
interests in other oil and gas properties, increase the level of utilization of
our pipelines or acquire other revenue generating assets at an acceptable cost,
our revenues and cash flow from operations will decrease.
The geographic concentration of our assets may have a greater effect on us as
compared to other companies.
All of our assets are located in the Gulf of Mexico and the onshore gulf coast
of Texas. Because our assets are not as diversified geographically as many of
our competitors, our business is subject to local conditions more than other,
more geographically diversified companies. Any regional events, including price
fluctuations, natural disasters, and restrictive regulations, that increase
costs, impacts the exploration and development of oil and gas in the Gulf of
Mexico, reduce availability of equipment or supplies, reduce demand for oil and
gas production may impact our business more than if our assets were
geographically diversified.
If we are not able to generate sufficient funds from our operations and other
financing sources, we may not be able to finance our operations.
We have historically needed substantial amounts of cash to fund our working
capital requirements. Because we have experienced a negative working capital
position in past years, we have been dependent on debt and equity financing to
meet our working capital requirements that were not funded from operations.
Low commodity prices, production problems, declines in production, disappointing
drilling results and other factors beyond our control could reduce our funds
from operations. As a result we may have to seek debt and equity financing to
meet our working capital requirements. Furthermore, we have incurred losses in
the past that may affect our ability to obtain financing. In addition, financing
may not be available to us
13
in the future on acceptable terms or at all. In the event additional capital is
not available, we may be forced to sell some of our assets on an untimely or
unfavorable basis.
We face strong competition from larger companies that may negatively affect our
ability to carry on operations.
We operate in a highly competitive industry. Our competitors include major
integrated oil companies, substantial independent energy companies, affiliates
of major interstate and intrastate pipelines and national and local gas
gatherers, many of which possess greater financial and other resources than we
do. Our ability to successfully compete in the marketplace is affected by many
factors including:
- most of our competitors have greater financial resources than we
do, which gives them better access to capital to acquire assets;
and
- we often establish a higher standard for the minimum projected
rate of return on invested capital than some of our competitors
since we cannot afford to absorb certain risks. We believe this
puts us at a competitive disadvantage in acquiring pipelines and
oil and gas properties.
Oil and gas prices are volatile and a substantial and extended decline in the
price of oil and gas would have a material adverse effect on us.
The tightening of natural gas supply and demand fundamentals has resulted in
higher, but extremely volatile, natural gas prices, and this volatility in
natural gas prices is expected to continue. Our revenues, profitability,
operating cash flow and our potential for growth are largely dependent on
prevailing oil and gas prices. Prices for oil and gas are subject to large
fluctuations in response to relatively minor changes in the supply and demand
for oil and gas, uncertainties within the market and a variety of other factors
beyond our control. These factors include:
- weather conditions in the United States;
- the condition of the United States economy;
- the actions of the Organization of Petroleum Exporting Countries;
- governmental regulation;
- political stability in the Middle East, South America and
elsewhere;
- the foreign supply of oil and gas;
- the price of foreign imports; and
- the availability of alternate fuel sources.
In addition, low or declining oil and gas prices could have collateral effects
that could adversely affect us, including the following:
- reducing the exploration for and development of oil and gas
reserves held by third party companies around our pipeline
systems;
- increasing our dependence on external sources of capital to meet
our cash needs; and
- generally impairing our ability to obtain needed capital.
14
Reserve estimates depend on many assumptions that may prove to be inaccurate.
Any material inaccuracies in our reserve estimates or underlying assumptions
could cause the quantities and net present value of our reserves to be
overstated.
Estimating reserves of oil and gas is complex. The process relies on
interpretations of available geologic, geophysics, engineering and production
data. The extent, quality and reliability of this data can vary. The process
also required certain economic assumptions, some of which are mandated by the
SEC, such as oil and gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The accuracy of a reserve
estimate is a function of:
- the quality and quantity of available data;
- the interpretation of that data;
- the accuracy of various mandated economic assumptions; and
- the judgment of the persons preparing the estimate.
The proved reserve information set forth in this report is based on estimates we
prepared. Estimates prepared by others might differ materially from our
estimates.
Actual quantities of recoverable oil and gas reserves, future production, oil
and gas prices, taxes, development expenditures and operating expenses most
likely will vary from our estimates. Any significant variance could materially
affect the quantities and net present value of our reserves. In addition, we may
adjust estimates of proved reserves to reflect production history, results of
exploration and development and prevailing oil and gas prices. Our reserves also
may be susceptible to drainage by operators on adjacent properties.
The present value of future net cash flows will most likely not equate to the
current market value of our estimated proved oil and gas reserves. In accordance
with SEC requirements, we base the estimated discounted future net cash flows
from proved reserves on prices and costs in effect at December 31. Actual future
prices and costs may be materially higher or lower than the prices and costs we
used.
We cannot control the activities on properties we do not operate.
Currently, other companies operate or control the development of the oil and gas
properties in which we have an interest. As a result, we depend on the operator
of the wells or leases 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, or an operator's failure to act in ways that are in
our best interest, could adversely affect us, including the amount and timing of
revenues, if any, we receive from our interests.
We own and generally anticipate that we will typically continue to own
substantially less than a 50% working interest in our prospects and will
therefore engage in joint operations with other working interest owners. Since
we own or control less than a majority of the working interest in a prospect,
decisions affecting the prospect could be made by the owners of a majority of
the working interest. For instance, if we are unwilling or unable to participate
in the costs of operations approved by a majority of the working interests in a
well, our working interest in the well (and possibly other wells on the
prospect) will likely be subject to contractual "non-consent penalties." These
penalties may include, for example, full or partial forfeiture of our interest
in the well or a relinquishment of our interest in production from the well in
favor of the participating working interest owners until the participating
working interest owners have recovered
15
a multiple of the costs which would have been borne by us if we had elected to
participate, which often ranges from 400% to 600% of such costs.
We have pursued, and intend to continue to pursue, acquisitions. Our business
may be adversely affected if we cannot effectively integrate acquired
operations.
One of our business strategies has been to acquire operations and assets that
are complementary to our existing businesses. Acquiring operations and assets
involves financial, operational and legal risks. These risks include:
- inadvertently becoming subject to liabilities of the acquired
company that were unknown to us at the time of the acquisition,
such as later asserted litigation matters or tax liabilities;
- the difficulty of assimilating operations, systems and personnel
of the acquired businesses; and
- maintaining uniform standards, controls, procedures and policies.
Competition from other potential buyers could cause us to pay a higher price
than we otherwise might have to pay and reduce our acquisition opportunities. We
are often out-bid by larger, better capitalized companies for acquisition
opportunities we pursue. Moreover, our past success in making acquisitions and
in integrating acquired businesses does not necessarily mean we will be
successful in making acquisitions and integrating businesses in the future.
Operating hazards, including those peculiar to the marine environment, may
adversely affect our ability to conduct business.
Our operations are subject to inherent risks normally associated with those
operations, such as:
- pipeline ruptures;
- sudden violent expulsions of oil, gas and mud while drilling a
well, commonly referred to as a blowout;
- a cave in and collapse of the earth's structure surrounding a
well, commonly referred to as cratering;
- explosions;
- fires;
- pollution; and
- other environmental risks.
If any of these events were to occur, we could suffer substantial losses from
injury and loss of life, damage to and destruction of property and equipment,
pollution and other environmental damage and suspension of operations. Our
offshore operations are also subject to a variety of operating risks peculiar to
the marine environment, such as hurricanes or other adverse weather conditions
and more extensive governmental regulation. These regulations may, in certain
circumstances, impose strict liability for pollution damage or result in the
interruption or termination of operations.
Losses and liabilities from uninsured or underinsured drilling and operating
activities could have a material adverse effect on our financial condition and
results of operations.
16
We maintain several types of insurance to cover our operations, including
maritime employer's liability and comprehensive general liability. Amounts over
base coverages are provided by primary and excess umbrella liability policies
with maximum limits of $25 million. We also maintain operator's extra expense
coverage, which covers the control of drilled or producing wells as well as
re-drilling expenses and pollution coverage for wells out of control.
We may not be able to maintain adequate insurance in the future at rates we
consider reasonable or losses may exceed the maximum limits under our insurance
policies. In 2004, in connection with the implementation of certain cost saving
measures, we cancelled the property insurance coverage on our pipelines. In
2005, we did not obtain property insurance coverage on our pipelines since we
were not able to acquire the coverage at what we believed to be reasonable
terms. If a significant event that is not fully insured or indemnified occurs,
it could materially and adversely affect our financial condition and results of
operations.
Compliance with environmental and other government regulations could be costly
and could negatively impact our operations.
Our operations are subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may:
- require the acquisition of a permit before operations can be
commenced;
- restrict the types, quantities and concentration of various
substances that can be released into the environment from
drilling and production activities;
- limit or prohibit drilling and pipeline activities on certain
lands lying within wilderness, wetlands and other protected
areas;
- require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells and abandoning
pipelines; and
- impose substantial liabilities for pollution resulting from our
operations.
The recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. The enactment of stricter legislation or the
adoption of stricter regulations could have a significant impact on our
operating costs, as well as on the oil and gas industry in general.
Our operations could result in liability for personal injuries, property damage,
oil spills, discharge of hazardous materials, remediation and clean-up costs and
other environmental damages. We could also be liable for environmental damages
caused by previous property owners. As a result, substantial liabilities to
third parties or governmental entities may be incurred which could have a
material adverse effect on our financial condition and results of operations. We
maintain insurance coverage for our operations, including limited coverage for
sudden and accidental environmental damages, but we do not believe that
insurance coverage for all environmental damages that occur over time or
complete coverage for sudden and accidental environmental damages is available
at a reasonable cost. Accordingly, we may be subject to liability or may lose
the privilege to continue exploration or production activities upon substantial
portions of our properties if certain environmental damages occur.
The OPA imposes a variety of regulations on "responsible parties" related to the
prevention of oil spills. The implementation of new, or the modification of
existing, environmental laws or regulations, including regulations promulgated
pursuant to the OPA, could have a material adverse impact on us.
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GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used
in the oil and gas industry.
BACK-IN AFTER PAYOUT INTEREST. A contractual right of a non-participating
partner to participate in a well or wells after the wells have produced enough
for the participating partners to recover their capital costs of drilling,
completing, and operating the wells.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference
to oil or other liquid hydrocarbons.
BCF. One billion cubic feet of gas.
BTU OR BRITISH THERMAL UNIT. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
CONDENSATE. Liquid hydrocarbons associated with the production of a primarily
gas reserve.
DEVELOPMENT WELL. A well drilled within the proved area of a gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
EXPLORATORY WELL. A well drilled to find and produce gas or oil in an unproved
area, to find a new reservoir in a field previously found to be productive of
gas or oil in another reservoir or to extend a known reservoir.
FIELD. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
LEASEHOLD INTEREST. The interest of a lessee under an oil and gas lease.
MBBLS. One thousand barrels of oil or other liquid hydrocarbons.
MCF. One thousand cubic feet of gas.
MCFE. One thousand cubic feet equivalent, determined using the ratio of six Mcf
of gas to one barrel of oil, condensate or gas liquids.
MMBTU. One million British Thermal Units.
MMCF. One million cubic feet of gas.
MMCFE. One million cubic feet equivalent, determined using the ratio of six Mcf
of gas to one Bbl of oil, condensate or gas liquids.
NET REVENUE INTEREST. The percentage of production to which the owner of a
working interest is entitled.
NONOPERATING WORKING INTEREST. A working interest, or a fraction of a working
interest, in a lease where the owner is not the operator of the lease.
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.
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PROSPECT. A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the
discovery of oil, gas or both.
PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved developed
reserves are further categorized into two sub-categories, proved developed
producing reserves and proved developed non-producing reserves.
PROVED DEVELOPED PRODUCING. Reserves sub-categorized as producing are expected
to be recovered from completion intervals which are open and producing at the
time of the estimate.
PROVED DEVELOPED NON-PRODUCING. Reserves sub-categorized as non-producing
include shut-in and behind pipe reserves. Shut-in reserves are expected to be
recovered from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were shut-in
awaiting pipeline connections or as a result of a market interruption, or (3)
wells not capable of producing for mechanical reasons.
PROVED RESERVES. The estimated quantities of oil, gas and condensate that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions.
PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered from new
wells or from existing wells where a relatively major expenditure is required
for recompletion.
REVERSIONARY INTEREST. A form of ownership interest in property that reverts
back to the transferor after expiration of an intervening income interest or the
occurrence of another triggering event.
ROYALTY INTEREST. An interest in a gas and oil property entitling the owner to a
share of gas and oil production free of costs of production.
UNDIVIDED INTEREST. A form of ownership interest in which more than one person
concurrently owns an interest in the same oil and gas lease or pipeline.
WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production.
ITEM 2. DESCRIPTION OF PROPERTY
Information appearing in Item 1 describing our oil and gas properties, pipelines
and other assets under the caption "Description of Business" is incorporated
herein by reference.
We lease our executive offices in Houston, Texas, under an operating lease
expiring December 31, 2006. Our aggregate annual lease payment obligation under
this lease is approximately $200,000.
In March 2003, we entered into a sublease agreement expiring December 31, 2006
for certain of our office space with TexCal Energy (GP) LLC (formerly Tri-Union
Development Corporation). Our annual receipts from this sublease are
approximately $78,500.
We have month to month contracts with several companies, including Drillmar,
Inc. (see Note 9, Related Party Transactions, to the Consolidated Financial
Statements in Item 7) to use our extra office space. Monthly proceeds from these
contracts is approximately $6,000.
19
ITEM 3. LEGAL PROCEEDINGS
We are presently only a party to litigation that is incidental to our business
and neither we nor any of our property is subject to any material pending legal
proceedings.
PART II
ITEM 5. MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS
MARKET PRICE FOR COMMON STOCK
Our common stock is quoted on the NASDAQ Small Cap Market under the symbol
"BDCO". As of March 21, 2006, there were an estimated 500 stockholders of record
and we estimate there are more than 1,000 beneficial owners of our common stock.
NASDAQ quotations reflect inter-dealer prices, without adjustment for retail
mark-ups, markdowns or commissions and may not represent actual transactions.
The following table sets forth, for the periods indicated, the high and low bid
price for the common stock as reported by the NASDAQ.
High Low
----- -----
Quarter Ended March 31, 2004 ...... $2.60 $1.26
Quarter Ended June 30, 2004 ....... $1.37 $1.00
Quarter Ended September 30, 2004 .. $1.66 $0.90
Quarter Ended December 31, 2004 ... $1.98 $0.97
Quarter Ended March 31, 2005 ...... $4.15 $0.76
Quarter Ended June 30, 2005 ....... $4.26 $1.35
Quarter Ended September 30, 2005 .. $3.52 $2.04
Quarter Ended December 31, 2005 ... $3.06 $1.95
On February 16, 2005, we received a notice from NASDAQ that because our common
stock traded below the minimum $1.00 bid price for 30 consecutive trading days
the common stock would be delisted if our bid price did not close above $1.00
for 10 consecutive trading days by August 15, 2005. On March 17, 2005, we
received a notice from NASDAQ that we regained compliance with the listing
requirements as a result of the bid price of our common stock closing above
$1.00 for 10 consecutive trading days.
DIVIDEND POLICY
We have not declared or paid any dividends on our common stock since our
incorporation. We currently intend to retain earnings for our capital needs and
expansion of our business and do not anticipate paying cash dividends on the
common stock in the foreseeable future. Previously, a loan agreement of ours
restricted us from paying dividends on our common stock if there was an
outstanding balance under the loan agreement. Any loan agreements which we may
enter into in the future will likely contain restrictions on the payment of
dividends on our common stock. Future policy with respect to dividends will be
determined by our Board of Directors based upon our earnings and financial
condition, capital requirements and other considerations. We are a holding
company that conducts substantially all of our operations through our
subsidiaries. As a result, our ability to pay dividends on the common stock is
dependent on the cash flow of our subsidiaries.
RECENT SALES OF UNREGISTERED SECURITIES
In March 2006, we entered into a stock purchase agreement with certain
accredited investors for the private placement of 1,171,432 shares of our common
stock at a purchase price of $1.75 per share. The net proceeds from the offering
after the payment of commissions and expenses were approximately
20
$2,025,000. The Company expects to use the proceeds for possible acquisitions
and planned expansions of its facilities, as well as for working capital and
general corporate purposes. In addition, in connection with the terms of a
placement agency agreement, we issued warrants to purchase an aggregate of 8,572
shares of common stock. The warrants vest immediately upon issuance and the
exercise price per share varies based on the following conditions: (i) until the
later of the registration of the warrants or one year from the issue date, 110%
of the purchase price per share in the offering, (ii) from the later of (x) the
registration of the warrants and (y) one year, until two years from the issue
date, 120% of the purchase price per share in the offering and (iii) after the
expiration of two years from the issue date of the warrants, 130% of the
purchase price per share in the offering.
In September 2004, we entered into a Note and Warrant Purchase Agreement (the
"Purchase Agreement") with certain accredited investors and certain of our
directors for the purchase and sale of promissory notes in an aggregate
principal amount of $750,000 (the "Promissory Notes") and warrants to purchase
3,100,000 shares of common stock at a purchase price of $0.003 per warrant (the
"Warrants"). The sale of the Promissory Notes and the first tranche of 1,250,000
Warrants (the "Initial Warrants") closed on September 8, 2004, and the sale of
the second tranche of 1,550,000 Warrants (the "Additional Warrants") closed on
November 30, 2004, after we received stockholder approval at our November 11,
2004 special stockholders' meeting. We received net proceeds of $758,400 from
the sale of the Promissory Notes and the Warrants. An additional 300,000
Warrants were granted to certain of our directors pursuant to the Purchase
Agreement. During 2005, all warrants outstanding were exercised in a "cashless"
manner, resulting in 279,631 shares of common stock being surrendered and
2,820,369 shares of common stock issued to the warrant holders.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a review of certain aspects of our financial condition and
results of operations and should be read in conjunction with the Consolidated
Financial Statements included in Item 7 and the description of our business in
Item 1-Description of Business.
EXECUTIVE SUMMARY
We are engaged in two lines of business: (i) pipeline transportation and related
services for producer/shippers, and (ii) oil and gas exploration and production.
We conduct all of our operations through our subsidiaries. Our assets are
located offshore and onshore in the Texas Gulf Coast region. Our goal is to
create greater value for our stockholders by increasing the utilization of our
existing assets, acquiring strategic assets to increase the diversification of
our asset base, improving our competitive position in the markets we serve, and
continuing to manage our operating and overhead costs. Although we are primarily
focusing on acquisitions of pipeline assets, we will review and evaluate
opportunities to acquire producing oil and gas properties as well.
At the beginning of 2005, we faced a very serious working capital deficiency. We
expected that we would need to raise additional capital of approximately
$500,000 to be able to meet our obligations for the year. However, during 2005
and early 2006, several actions and events contributed to a significant
improvement in our financial condition:
- In February 2005, we renegotiated the terms of a $750,000 promissory
note, bearing interest at 6% per annum and due to MCNIC on December
31, 2006. Under the new terms, the principal amount of the note was
reduced to $250,000 and it is now non-interest bearing. In addition,
all previously accrued interest on the promissory note was forgiven.
21
- In April 2005, the holders of $450,000 of the $750,000 in promissory
notes issued in September 2004, agreed to extend the maturity date of
their promissory notes to June 30, 2006, and to defer the payment of
all unpaid and future interest on their promissory notes until
maturity.
- In July 2005, we entered into gas and condensate transportation and
handling agreements with Manti Operating Company. Delivery of
production into the Blue Dolphin System from Galveston area state
tract 348 commenced in August 2005 and we began providing services to
Manti for this production.
- In September 2005, we began receiving payments for our after-payout
working interest in two wells in High Island Block 37. We recorded net
revenues of approximately $2,397,000 from High Island Block 37 for
2005, representing our share of the sales of oil and gas from the
estimated payout in July 2004 through December 2005. The two wells
produced at a combined average rate of 23.1 MMcf per day during 2005.
- Also in September 2005, two wells in High Island Block A-7 were
successfully recompleted and production was reestablished at
significantly higher rates. The wells were shut in for a short period
of time awaiting resumption of transportation capacity following
Hurricane Rita. The wells produced at a combined average rate of 5.4
MMcf per day during the fourth quarter.
- In late September 2005, we entered into gas and condensate
transportation and handling agreements with a new shipper to deliver
production into the Blue Dolphin System at our Galveston Block 288C
platform. Production from this well is expected to commence late in
the second quarter of 2006.
- In early October 2005, we entered into gas and condensate
transportation and handling agreements with another new shipper to
deliver production into the Blue Dolphin System in Galveston Block
287. Production from this well is currently expected to commence in
the second quarter of 2006.
- In March 2006, we entered into a stock purchase agreement with certain
accredited investors for the private placement of 1,171,432 shares of
our common stock. Net proceeds from the offering after the payment of
commissions and expenses were approximately $2,025,000.
Although the rate of production generally declines as reserves are depleted, we
currently expect our working interests in High Island Block 37 and High Island
Block A-7 to continue to generate significant revenues during 2006. However,
there is the possibility that these wells could experience production problems
which could significantly decrease the level of production and have a material
adverse effect on our cash flows and liquidity. We also expect the throughput
from two new transportation customers on the Blue Dolphin System to increase
utilization of the pipeline in 2006. However, we cannot determine the throughput
volumes from these new customers, and as a result, cannot predict the impact the
volumes will have on our revenues.
Due to our small size, geographically concentrated asset base, and limited
capital resources, any negative event has the potential to cause significant
harm to our financial condition. In 2006, we will continue our efforts to raise
capital and acquire additional pipeline assets that will diversify this risk, be
accretive to earnings and increase our financial flexibility.
LIQUIDITY AND CAPITAL RESOURCES
We began 2005 with accumulated and continuing losses from operations. We also
had debt service and contractual obligations of approximately $1.5 million due
in 2005. This significant burden raised doubts about our viability as a going
concern. Our auditors, UHY Mann Frankfort Stein and Lipp CPAs, LLP
22
("UHY") added an explanatory paragraph to their opinion on our consolidated
financial statements for the year ended December 31, 2004, indicating that
substantial doubt existed about our ability to continue as a going concern.
However, our financial condition improved significantly as a result of the
revenues received from our non-operated working interests in High Island Block
37 and High Island Block A-7, and actions we have taken to restructure our
indebtedness and contract with a new shipper whose production commenced in
August 2005. The increase in gas transportation rates charged on the Blue
Dolphin System negotiated in 2004 also had a significant positive effect. We
ended 2005 with working capital of approximately $2.1 million and total
obligations were reduced from approximately $4.0 million at year-end 2004 to
approximately $3.0 million at year-end 2005. We believe we have sufficient
liquidity to satisfy our working capital requirements through December 31, 2006.
The following table summarizes our financial position for the years indicated
(amounts in thousands):
December 31, December 31,
2005 2004
------------ ------------
Amount % Amount %
------ --- ------ ---
Working Capital $2,053 29 $ 404 7
Property and equipment, net 4,980 71 5,324 93
Other noncurrent assets 11 -- 11 --
------ --- ------ ---
Total $7,044 100 $5,739 100
====== === ====== ===
Long-term Liabilities $2,256 32 $2,374 41
Stockholders' equity 4,788 68 3,365 59
------ --- ------ ---
Total $7,044 100 $5,739 100
====== === ====== ===
The net cash provided by or used in operating, investing and financing
activities is summarized below:
Years ended December 31
-----------------------
(amounts in thousands)
2005 2004
----- -------
Net cash provided by (used in):
Operating activities $ 50 $(2,603)
Investing activities 106 875
Financing activites (419) 586
----- -------
Net decrease in cash $(263) $(1,142)
===== =======
In September 2005, we began receiving payments for our contractual after-payout
working interest in High Island Block 37. The initial payment of approximately
$1.3 million was for production net of expenses from the estimated payout on
July 1, 2004, through May 2005. We expect to continue to receive monthly
payments for our share of revenues from the sales of gas and oil from this
block. We have recognized gross gas and oil sales revenues of approximately $2.4
million and lease operating expenses of approximately $16,000 associated with
High Island 37 in 2005, representing our interests from payout through December
2005. There are two wells in this block currently producing at a combined rate
of approximately 23 MMcf per day. We have a working interest of approximately
2.8% in both wells.
Also in September 2005, two wells in High Island Block A-7 were successfully
recompleted and resumed production at a significantly higher rate compared to
the single well that produced through the first and
23
second quarters of 2005. The wells were shut-in for a period of time while third
party transporters made repairs following Hurricane Rita. One well resumed
production in late October and the second well resumed production in early
November. We recognized gross gas and oil sales revenues of approximately
$722,000 and lease operating expenses of approximately $125,000 for High Island
Block A-7 for the year ended December 31, 2005. Approximately $630,000 of these
revenues are for production in the fourth quarter after the recompletions. Lease
operating expenses were spread relatively evenly throughout the year. Only one
of the two wells is currently producing. Production is currently approximately 7
MMcf per day. Our working interest is approximately 8.9 % in both wells.
Despite the significant revenues generated by sales of gas and oil from our
working interests in High Island 37 and High Island A-7, our financial condition
continues to be adversely affected by the poor utilization of our pipeline
assets. Without the revenues and resulting cash inflows we are receiving from
sales of gas and oil, we would not be generating sufficient cash from operations
to cover our operating and general and administrative expenses. Natural gas
throughput on our Blue Dolphin System is currently 9 MMcf per day, representing
approximately 6% of system capacity. Natural gas throughput on the GA 350
Pipeline is currently 9 MMcf per day, which is approximately 14% of pipeline
capacity.
Effective October 1, 2004, we renegotiated the gas transportation rates on the
Blue Dolphin System due to operating losses incurred. As a result, gas
transportation revenues from the Blue Dolphin System for the year ended December
31, 2005 were approximately $1,154,000. Without the increased rates, gas
transportation revenues would have been approximately $505,000 for this same
period.
We have significant available capacity on the Blue Dolphin System, the GA 350
Pipeline and the inactive Omega Pipeline and we believe all of the pipelines are
in geographic market areas that are experiencing an increased level of interest
by oil and gas operators. This assessment is based on recent leasing and
drilling activity in the lease blocks surrounding the pipelines, as well as
information obtained directly from the operators of properties near our
pipelines. There have been four new discoveries near the Blue Dolphin System in
2005. We have entered into contracts for transportation and handling services
with the operators of three of the properties and are currently in negotiations
with the fourth. One of the new shippers, Manti Operating Company, began
deliveries in 2005. We expect to begin providing transportation services to the
remaining two new contracted shippers in the second quarter of 2006. However,
drilling activity around our pipelines is currently being impeded by a shortage
of drilling equipment in the Gulf of Mexico due to infrastructure repairs
following Hurricanes Katrina and Rita. Ultimately, the future utilization of our
pipelines and related facilities will depend upon the success of drilling
programs around our pipelines, and attraction and retention of producer/shippers
to the pipelines.
The following table summarizes our contractual obligations and other commercial
commitments at December 31, 2005 (amounts in thousands):
Payments Due by Period
--------------------------------------------------
Contractual Obligations and Other 1 year After
Commercial Commitments Total or less 1-3 years 3-5 years 5 years
--------------------------------- ------ ------- --------- --------- -------
Notes Payable and Long-Term Debt $1,127 627 500 -- --
Operating Leases, net of sublease 144 123 12 9 --
Abandonment Costs 1,756 -- 236 -- 1,520
------ --- --- --- -----
Total Contractual Obligations
and Other Commercial
Commitments $3,027 750 748 9 1,520
====== === === === =====
In early 2005, we had obligations to Tetra of approximately $450,000 to be paid
during January through August 2005; $130,000 was due to MCNIC during February
through December; and our promissory notes
24
in the principal amount of $750,000 along with accrued interest of approximately
$60,000 were due in September. Unless we were able to raise capital of
approximately $500,000, we did not expect to be able to meet our obligations for
2005.
The monthly payments of $55,667 plus interest at 6% per annum due to Tetra were
made as scheduled. The approximately $450,000 in payments represented the final
obligations associated with the abandonment of the Buccaneer Field. On August 1,
2005, we made the final payment to Tetra.
On February 28, 2005, we entered into an amendment to our purchase agreement
with MCNIC to acquire MCNIC's one-third interest in the Blue Dolphin Pipeline
System and the inactive Omega Pipeline. Pursuant to the terms of the amendment,
the original promissory note of $750,000 was exchanged for a new promissory note
in the principal amount of $250,000, and all accrued interest on the original
promissory note was forgiven, approximately $132,000. We agreed to make a
principal payment of $30,000 upon execution of the amendment and to make monthly
principal payments of $10,000 through December 31, 2006. MCNIC may also receive
additional payments of up to $500,000 from 50% of the net profits, if any,
realized from the one-third interest through December 31, 2006. The principal
amount of the new promissory note may also be increased by up to $500,000 if 50%
or more of our 83% interest in the assets is sold before December 31, 2006.
However, in the event that both of these contingencies were triggered, the
principal of the promissory note cannot be increased by more than $500,000 in
aggregate. We paid $130,000 of this promissory note in 2005 and have $120,000
remaining to be paid in 2006.
In April 2005, the holders of $450,000 of the $750,000 aggregate principal
amount of promissory notes sold in September 2004, agreed to extend the maturity
date of their promissory notes to June 30, 2006, and to defer the payment of all
unpaid and future interest on their promissory notes until maturity. The
promissory notes were originally sold on September 8, 2004 pursuant to the Note
and Warrant Purchase Agreement we entered into with certain accredited investors
and certain of our directors. The remaining $300,000 aggregate principal amount
of promissory notes was retired at maturity on September 8, 2005.
In March 2006, we entered into a stock purchase agreement with certain
accredited investors for the private placement of 1,171,432 shares of our common
stock. We incurred commissions and expenses of approximately $25,000 associated
with the offering, and issued warrants to purchase an aggregate of 8,572 shares
of common stock. The net proceeds of approximately $2,025,000 will be used for
planned expansions of our existing facilities, possible acquisitions and general
corporate purposes. In addition to providing funds immediately available for
specific uses, the net proceeds of the private placement also provide additional
working capital, which aids our ability to withstand events that could have an
adverse effect on our operations.
RESULTS OF OPERATIONS
For the year ended December 31, 2005 ("2005"), we reported net income of
$541,386, compared to a net loss of $2,500,334 for the year ended December 31,
2004 ("2004").
2005 COMPARED TO 2004
Revenue from pipeline operations. Revenues from pipeline operations increased by
$361,036 or 35.6% in 2005 to $1,375,173. Revenues in 2005 from the Blue Dolphin
System totaled approximately $1,154,000 compared to approximately $663,000 in
2004 primarily as a result of an increase in our average gas transportation
rates on the Blue Dolphin System. The increased rates were negotiated due to net
operating losses sustained on the Blue Dolphin System and were effective as of
October 2004. The increased rates will decrease as our net operating results
from the Blue Dolphin System improve, but in any case, the rates will be no
lower than the rates that were in effect prior to the increase in October 2004.
The increased revenues on the Blue Dolphin System were partially offset by
decreased revenues on the GA 350 pipeline
25
of approximately $130,000 due to a decrease in average daily gas volumes
transported to approximately 12 MMcf per day in 2005 from approximately 17 MMcf
per day in 2004.
Revenue from oil and gas sales. Revenue from oil and gas sales increased by
$2,740,310 to $3,136,010 in 2005 from $395,700 in 2004 primarily due to
recognition of approximately $2,414,000 of gross revenue for sales of gas and
oil associated with a contractual after-payout working interest of approximately
2.8% in High Island Block 37. The revenue represents our interest in production
from the estimated payout date of July 1, 2004 through December 2005. High
Island Block A-7 ceased production in July 2005, and was recompleted in
September 2005 to a new reservoir. A second well was also recompleted in
September 2005. Both wells produced at a significantly higher combined rate for
a portion of September 2005, but were shut-in due to Hurricane Rita. Production
was re-established in October 2005. High Island Block A-7 provided gross revenue
of approximately $722,000 in 2005 compared to approximately $332,000 in 2004.
Approximately $630,000 of 2005 High Island Block A-7 revenue occurred in the
fourth quarter after production was re-established following repairs to the
onshore facilities of the third party transporter. Only one of the wells is
currently producing. We have a working interest of approximately 8.9% in both
wells.
Pipeline operating expenses. Pipeline operating expenses in 2005 increased by
$2,898 to $1,081,563 primarily due to increased legal costs of approximately
$38,000, increased consulting services costs of approximately $43,000, and
increased contract labor costs of approximately $48,000, partially offset by
lower repairs and maintenance costs of approximately $127,000. The decrease in
insurance costs is due to a refund received for having no claims in the previous
policy period and the elimination of property insurance coverage on our
pipelines. The increase in legal costs is associated with an ongoing action
against us, the outcome of which we do not believe will have a material impact.
However, as this litigation continues we will continue to incur significant
legal expenses which could have a material adverse effect on our financial
condition.
General and administrative. General and administrative expenses increased by
$220,910 to $2,608,511 in 2005. The increase was primarily due to recognition of
approximately $774,000 of non-cash compensation expense associated with
"cashless" exercises of 319,321 stock options by certain of our directors and
employees. In 2004, we recognized non-cash compensation expense of approximately
$694,000 associated with the issuance of warrants to certain of our directors.
The increase was also due to higher legal and consulting expenses primarily
associated with our efforts to raise capital, offset by lower personnel and
other costs as a result of our cost reduction plans implemented in 2003 and
2004. If our business activities expand, however, we will need to hire
additional employees, so our personnel and associated costs will increase.
Interest and other expense. Interest and other expense decreased by $302,679 to
$124,294 in 2005. Other expense in 2004 included approximately $200,000 in legal
and other fees associated with a proposed financing transaction that was
subsequently terminated, amortization of costs associated with the Purchase
Agreement of $120,000 and interest expense of approximately $85,000 on our
Promissory Notes issued in September 2004 and other debt. Interest expense in
2005 was approximately $82,000.
Gain on sale of assets. Gain on sale of assets decreased by $230,931 in 2005. We
recorded a gain in 2005 on the placement of our interests in the Galveston Area
Block 287/297 leases of approximately $140,000. In 2004, we recorded a gain of
approximately $344,000 associated with the sale of our 25% interest in New Avoca
and a gain of approximately $27,000 associated with the sale of our 5% interest
in two exploratory leases, East Cameron Blocks 90 and 94.
Interest and other income. Interest and other income increased by $30,310 in
2005 to $375,966. Other income in 2005 includes a gain on the elimination of
accrued interest as a result of the restructuring of the MCNIC promissory note
of approximately $132,000, a gain associated with the collection of a
related-party note receivable of approximately $178,000 and accounts receivable
of approximately $45,000 that
26
were both previously written off. Other income in 2004 includes fees generated
for consulting services we provided, associated with the evaluation of oil and
gas properties, of approximately $110,000 and the collection of accounts
receivable that were previously written off of approximately $165,000.
Equity in loss of affiliate. In 2004 we recorded a loss from our equity interest
in New Avoca of $96,116. Our interest in New Avoca was sold in October 2004.
CRITICAL ACCOUNTING POLICIES
The selection and application of accounting policies is an important process
that has developed as our business activities have evolved and as the accounting
rules have developed. Accounting rules generally do not involve a selection
among alternatives, but involve an implementation and interpretation of existing
rules, and the use of judgment, to the specific set of circumstances existing in
our business. We make every effort to properly comply with all applicable rules
at or before their adoption, and believe the proper implementation and
consistent application of the accounting rules is critical. However, not all
situations are specifically addressed in the accounting literature. In these
cases, we must use our best judgment to adopt a policy for accounting for these
situations. We accomplish this by comparatively analyzing similar situations and
reviewing the accounting guidance governing them, and may consult with our
independent accountants about the appropriate interpretation and application of
these policies. Our most critical accounting policies currently relate to the
accounting for the impairment of long-lived assets, which include primarily our
pipeline assets, as of December 31, 2005 and the accounting for future
abandonment costs.
In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, we initiate a review for impairment of our long-lived assets
whenever events or changes in circumstances indicate that the carrying amount of
a long-lived asset may not be recoverable. Recoverability of an asset is
measured by comparison of its carrying amount to the expected future
undiscounted cash flows expected to result from the use and eventual disposition
of that asset, excluding future interest costs that would be recognized as an
expense when incurred. Any impairment to be recognized is measured by the amount
by which the carrying amount of the asset exceeds its fair market value.
Significant management judgment is required in the forecasting of future
operating results which are used in the preparation of projected cash flows and,
should different conditions prevail or judgments be made, material impairment
charges could be necessary. Currently, our pipeline assets are significantly
under utilized and such underutilization is an indicator of possible impairment
at December 31, 2005. Accordingly, we developed future cash flows as of December
31, 2005 expected to be generated from our pipeline assets based on certain
assumptions. The most significant assumption made in connection with the
preparation of expected future cash flows is the assumption that pipeline
throughput volumes will increase over the next few years due to increasing
current leasing and drilling activities, and prospective drilling activity
surrounding our pipelines. Based on the results of the impairment test, which
indicates expected future undiscounted cash flows are in excess of the pipeline
assets net carrying value, no impairment has been recorded as of December 31,
2005.
The accounting for future abandonment costs changed on January 1, 2003 with the
adoption of SFAS No. 143. This new standard requires that a liability for the
discounted fair value of an asset retirement obligation be recorded in the
period in which it is incurred and the corresponding cost capitalized by
increasing the carrying amount of the related long-lived asset. The liability is
accreted towards its future value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is
recognized. Future asset retirement costs include costs to dismantle and
relocate or dispose of our offshore platforms, pipeline systems and related
onshore facilities and restoration costs of land and seabed. We develop
estimates of these costs for each of our assets based upon the type of platform
structure, depth of water, reservoir characteristics, depth of the reservoir,
market demand for equipment, currently available procedures and consultations
with construction and engineering consultants. Because these costs typically
extend many years into the future, estimating these future costs is difficult
and requires management to make judgments
27
that are subject to future revisions based upon numerous factors, including
changing technology and the political and regulatory environment. We review our
assumptions and estimates of future abandonment costs on a quarterly basis.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS AND ACCOUNTING DEVELOPMENTS
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based
Payment ("SFAS No. 123(R)"). This statement addresses the accounting for
share-based payment transactions in which an enterprise receives employee
services in exchange for (a) equity instruments of the enterprise, or (b)
liabilities that are based on the fair value of the enterprise's equity
instruments or that may be settled by the issuance of such equity instruments.
SFAS No. 123(R) requires an entity to recognize the grant-date fair-value of
stock options and other equity-based compensation issued to employees in the
income statement. The revised Statement requires that an entity account for
those transactions using the fair-value-based method, and eliminates the
intrinsic value method of accounting in APB No. 25, Accounting for Stock Issued
to Employees, which was permitted under SFAS No. 123, as originally issued. The
revised Statement requires entities to disclose information about the nature of
the share-based payment transactions and the effects of those transactions on
the financial statements. SFAS No. 123(R) is effective for public companies for
the first fiscal year beginning after December 31, 2005. All public companies
must use either the modified prospective or the modified retrospective
transition method. We have not yet fully evaluated the impact of the adoption of
this pronouncement, which must be adopted in the first quarter of calendar year
2006. On March 29, 2005, the Securities Exchange Commission staff issued SAB No.
107, Share-Based Payment, to express the views of the staff regarding the
interaction between SFAS No. 123(R) and certain Securities Exchange Commission
rules and regulations and to provide the staff's views regarding the valuation
of share-based payment arrangements for public companies. The Company will take
into consideration the additional guidance provided by SAB 107 in connection
with the implementation of SFAS No. 123(R).
In March 2005, the FASB issued Interpretation (FIN) No. 47, Accounting for
Conditional Asset Retirement Obligations -- An Interpretation of SFAS No. 143,
which clarifies the term "conditional asset retirement obligation" used in SFAS
No. 143, Accounting for Asset Retirement Obligations, and specifically when an
entity would have sufficient information to reasonably estimate the fair value
of an asset retirement obligation. The adoption did not have an impact on the
Company's financial statements.
In May 2005, the FASB issued SFAS No. 154, Accounting for Changes and Error
Corrections - a Replacement of APB Opinion No. 20 and FASB Statement No. 3
("SFAS No. 154"). SFAS No. 154 requires retrospective application of voluntary
changes in accounting principles, unless impracticable. SFAS No. 154 supersedes
the guidance in APB Opinion No. 20 and SFAS No. 3, but does not change any
transition provisions of existing pronouncements. Generally, elective accounting
changes will no longer result in a cumulative effect of a change in accounting
in the income statement, because the effects of any elective changes will be
reflected as prior period adjustments to all periods presented. SFAS 154 will be
effective beginning in fiscal 2006 and will affect any accounting changes that
we elect to make thereafter.
In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid
Financial Instruments--an amendment of FASB Statements No. 133 and 140 ("SFAS
No. 155"). This statement amends SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS No. 133"), and SFAS No. 140,
Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities and resolves issues addressed in SFAS No. 133 Implementation
Issue No. D1, Application of Statement 133 to Beneficial Interest in Securitized
Financial Assets. This Statement: (a) permits fair value remeasurement for any
hybrid financial instrument that contains an embedded derivative that otherwise
would require bifurcation; (b) clarifies which interest-only strips and
principal-only strips are not subject to the requirements of SFAS No. 133; (c)
establishes a requirement to evaluate beneficial interests in securitized
financial assets to identify interests that are freestanding derivatives or that
are hybrid financial instruments that contain an embedded derivative requiring
bifurcation; (d) clarifies that concentrations of
28
credit risk in the form of subordination are not embedded derivatives; and, (e)
eliminates restrictions on a qualifying special-purpose entity's ability to hold
passive derivative financial instruments that pertain to beneficial interests
that are or contain a derivative financial instrument. The standard also
requires presentation within the financial statements that identifies those
hybrid financial instruments for which the fair value election has been applied
and information on the income statement impact of the changes in fair value of
those instruments. The Company is required to apply SFAS No. 155 to all
financial instruments acquired, issued or subject to a remeasurement event
beginning January 1, 2007, although early adoption is permitted as of the
beginning of an entity's fiscal year. The provisions of SFAS No. 155 are not
expected to have an impact at adoption.
The remainder of this page left blank intentionally.
29
ITEM 7. FINANCIAL STATEMENTS
Page
----
Index to Financial Statements:
Report of Independent Registered Public Accounting Firm.................. 31
Consolidated Balance Sheet, at December 31, 2005......................... 32
Consolidated Statements of Operations, for the years
ended December 31, 2005 and 2004...................................... 34
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 2005 and 2004................................ 35
Consolidated Statements of Cash Flows, for the years
ended December 31, 2005 and 2004...................................... 36
Notes to Consolidated Financial Statements............................... 38
30
Report of Independent Registered Public Accounting Firm
The Board of Directors and
Stockholders of
Blue Dolphin Energy Company
We have audited the accompanying consolidated balance sheet of Blue Dolphin
Energy Company and subsidiaries (the "Company") as of December 31, 2005, 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, 2005.
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 the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Blue
Dolphin Energy Company and subsidiaries as of December 31, 2005, and the
consolidated results of their operations and their cash flows for each of the
years in the two-year period ended December 31, 2005 in conformity with
accounting principles generally accepted in the United States of America.
/s/ UHY Mann Frankfort Stein & Lipp CPAs, LLP
Houston, Texas
March 24, 2006
31
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 2005
Assets
Current assets:
Cash and cash equivalents $1,297,088
Accounts receivable 1,602,296
Prepaid expenses and other current assets 182,577
----------
Total current assets 3,081,961
Property and equipment, at cost:
Oil and gas properties, including $5,343 of
unproved leasehold cost (full-cost method) 549,720
Pipelines 4,543,782
Onshore separation and handling facilities 1,688,232
Land 860,275
Other property and equipment 264,428
----------
7,906,437
Less accumulated depletion, depreciation,
amortization, and impairment 2,926,210
----------
4,980,227
Other assets 11,359
----------
$8,073,547
==========
See accompanying notes to consolidated financial statements.
32
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET, CONTINUED
December 31, 2005
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 394,765
Notes payable 450,000
Current portion of long-term debt 120,000
Accrued expenses and other current liabilities 64,456
------------
Total current liabilities 1,029,221
Long-term liabilities:
Long-term debt 500,000
Asset retirement obligations 1,756,269
------------
Total long-term liabilities 2,256,269
Stockholders' equity:
Common stock, $0.01 par value, 25,000,000
shares authorized and 9,939,302 shares
issued and outstanding 99,393
Additional paid-in capital 27,980,475
Accumulated deficit (23,291,811)
------------
Total stockholders' equity 4,788,057
------------
$ 8,073,547
============
See accompanying notes to consolidated financial statements.
33
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31, 2005 and 2004
2005 2004
---------- -----------
Revenue from operations:
Pipeline operations $1,375,173 $ 1,014,137
Oil and gas sales 3,136,010 395,700
Gain on sale of oil and gas property -- 25,809
---------- -----------
Revenue from operations 4,511,183 1,435,646
Cost of operations:
Pipeline operating expenses 1,081,563 1,078,665
Lease operating expenses 155,174 134,313
Depletion, depreciation and amortization 403,217 432,766
General and administrative expenses 2,608,511 2,387,601
Accretion expense 100,308 96,542
---------- -----------
Cost of operations 4,348,773 4,129,887
---------- -----------
Income (loss) from operations 162,410 (2,694,241)
Other income (expense):
Interest and other expense (124,294) (426,973)
Gain on sale of assets 140,409 371,340
Interest and other income 375,966 345,656
Equity in losses of affiliate -- (96,116)
---------- -----------
Income (loss) before income taxes 554,491 (2,500,334)
Income tax expense (13,105) --
---------- -----------
Net income (loss) $ 541,386 $(2,500,334)
========== ===========
Income (loss) per common share:
- basic $ 0.06 $ (0.37)
========== ===========
- diluted $ 0.06 $ (0.37)
========== ===========
Weighted average number of common shares
- basic 8,763,475 6,734,395
========== ===========
- diluted 8,874,117 6,734,395
========== ===========
See accompanying notes to consolidated financial statements.
34
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years Ended December 31, 2005 and 2004
Common Additional Total
stock Common paid-in Accumulated stockholders'
shares stock capital deficit equity
--------- ------- ----------- ------------ -------------
Balance at December 31, 2003 6,657,845 $66,578 $26,267,308 $(21,332,863) $ 5,001,023
Exercise of stock options 93,688 937 19,063 -- 20,000
Common stock issued for services 112,156 1,122 140,878 -- 142,000
Issuance of warrants -- -- 701,913 -- 701,913
Net loss -- -- -- (2,500,334) (2,500,334)
--------- ------- ----------- ------------ -----------
Balance at December 31, 2004 6,863,689 68,637 27,129,162 (23,833,197) 3,364,602
Exercise of stock options 201,899 2,019 772,350 -- 774,369
Common stock issued for services 53,345 533 107,167 -- 107,700
Exercise of warrants 2,820,369 28,204 (28,204) -- --
Net income -- -- -- 541,386 541,386
--------- ------- ----------- ------------ -----------
Balance at December 31, 2005 9,939,302 $99,393 $27,980,475 $(23,291,811) $ 4,788,057
========= ======= =========== ============ ===========
See accompanying notes to consolidated financial statements.
35
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2005 and 2004
2005 2004
----------- -----------
Operating activities:
Net income (loss) $ 541,386 $(2,500,334)
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating activities:
Depletion, depreciation and amortization 403,217 432,766
Amortization of debt issuance costs 54,630 122,418
Gain on sale of assets (140,409) (397,149)
Accretion of asset retirement obligations 100,308 96,542
Gain on modification of note payable (132,368) --
Equity in losses of affiliate -- 96,116
Compensation from exercise of stock options 774,369 --
Compensation from issuance of warrants -- 693,513
Common stock issued for services 94,800 142,000
Changes in operating assets and liabilities:
Accounts receivable (1,285,932) 172,721
Prepaid expenses and other assets (68,095) 51,404
Deferred federal income tax -- 244,444
Trade accounts payable and accrued expenses (292,274) (1,757,275)
----------- -----------
Net cash provided by (used in) operating
activities 49,632 (2,602,834)
----------- -----------
Investing activities:
Exploration and development costs (72,501) (26,590)
Purchases of property and equipment (35,849) (11,141)
Proceeds from sale of assets 214,632 1,000,127
Development costs - New Avoca -- (87,667)
----------- -----------
Net cash provided by investing activities 106,282 874,729
----------- -----------
See accompanying notes to consolidated financial statements.
36
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
Years ended December 31, 2005 and 2004
2005 2004
---------- -----------
Financing activities:
Proceeds from (payments on) borrowings (430,000) 750,000
Financing costs incurred (2,275) (192,638)
Proceeds received from issuance of warrants
and exercise of stock options 12,900 28,400
---------- -----------
Net cash provided by (used in) financing
activities (419,375) 585,762
---------- -----------
Decrease in cash and cash equivalents (263,461) (1,142,343)
Cash and cash equivalents at beginning of year 1,560,549 2,702,892
---------- -----------
Cash and cash equivalents at end of year $1,297,088 $ 1,560,549
========== ===========
Supplementary cash flow information:
Interest paid $ 46,422 $ 15,807
========== ===========
See accompanying notes to consolidated financial statements.
37
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2005 and 2004
(1) ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Blue Dolphin Energy Company was incorporated in Delaware in January 1986 to
engage in oil and gas exploration, production and acquisition activities
and oil and gas transportation and marketing. We were formed pursuant to a
reorganization effective June 9, 1986.
PRINCIPLES OF CONSOLIDATION
Our consolidated financial statements include the accounts of our
wholly-owned subsidiaries. All significant intercompany balances and
transactions have been eliminated in consolidation.
ACCOUNTING ESTIMATES
We have made a number of estimates and assumptions relating to the
reporting of assets and liabilities and to the disclosure of contingent
assets and liabilities, including reserve information, which affects the
depletion calculation as well as the computation of the full cost ceiling
limitation to prepare these consolidated financial statements in conformity
with accounting principles generally accepted in the United States of
America. While we believe current estimates are reasonable and appropriate,
actual results could differ from those estimated.
CASH EQUIVALENTS
Cash equivalents include liquid investments with an original maturity of
three months or less. Cash balances are maintained in depository and
overnight investment accounts with financial institutions which at times,
exceed insured limits. We monitor the financial condition of the financial
institutions and have experienced no losses associated with these accounts.
OIL AND GAS PROPERTIES
Oil and gas properties are accounted for using the full-cost method of
accounting, whereby all costs associated with acquisition, exploration, and
development of oil and gas properties, including directly related internal
costs, are capitalized on a country-by-country cost center basis. We
utilize one cost center for all of our properties. Amortization of such
costs and estimated future development costs is determined using the
unit-of-production method. 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 prepared
internally by us. The net carrying value of oil and gas properties, less
related deferred income taxes, is limited to the lower of unamortized cost
or the cost center ceiling, defined as the sum of the present value (10%
discount rate applied) of estimated future net revenues from proved
reserves, after giving effect to income taxes, and the lower of cost or
estimated fair value of unproved properties. Disposition of oil and gas
properties are recorded as adjustments to capitalized costs, with no gain
or loss recognized unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves.
38
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table reflects the depletion expense incurred from oil and
gas properties during the years indicated:
Years ended
December 31,
-------------
2005 2004
----- -----
Depletion expense per Mcf
equivalent produced $0.19 $1.23
===== =====
At December 31, 2005, oil and gas properties included $5,343 of unproved
leasehold costs that are not being amortized. These costs will begin to be
amortized when they are evaluated, whether or not proved reserves are
discovered, or when the lease term expires. Unproved leasehold costs
consist of an interest in a federal lease located in the Gulf of Mexico
with an expiration date of May 2006. In order to retain leases after the
primary term, they must be producing or development operations must be in
progress. Leases have primary terms of 5 years. Development of this lease
is dependent upon the other owners of the lease initiating a plan of
development.
The following table reflects the years when costs were incurred for
unproved leasehold costs:
Years ended
December 31,
-------------------
Total (1) 2005 2004 Prior Years
--------- --------- ------- -----------
Property acquisition costs, net $139,703 $ 1,250 $16,892 $121,561
Exploration costs, net 39,136 -- -- 39,136
Properties sold (74,223) (74,223) -- --
Properties evaluated (2) (42,593) (42,593) -- --
Leases expired (56,680) (56,680) -- --
-------- --------- ------- --------
$ 5,343 $(172,246) $16,892 $160,697
======== ========= ======= ========
(1) Unproved leasehold costs are net of leasehold costs transferred to the
amortization base when they are evaluated and proved reserves are
discovered, impairment is indicated or when the lease term expires.
(2) Properties determined to have no future value.
We capitalize interest on expenditures made in connection with significant
exploration and development 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 years reflected herein.
39
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PIPELINES AND FACILITIES
Pipelines and facilities are recorded at cost. Depreciation is computed
using the straight-line method over estimated useful lives ranging from
10-22 years.
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 ranging from 3-10 years.
In accordance with Statements of Financial Accounting Standards ("SFAS")
No. 144, Accounting for the Impairment or Disposal of Long-lived Assets,
assets are grouped and evaluated for impairment based on the ability to
identify separate cash flows generated therefrom.
ASSET RETIREMENT OBLIGATIONS
In August 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 143, Accounting for Asset Retirement Obligations, as amended,
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 No. 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, a gain or loss on settlement is recognized.
We have asset retirement obligations associated with the future abandonment
of pipelines and related facilities and offshore oil and gas properties.
The following table summarizes our asset retirement obligation transactions
during the years ended December 31, 2005 and 2004.
Years ended
December 31,
---------------
2005 2004
------ ------
(in thousands)
Beginning asset retirement obligations ......... $1,622 $1,552
Liabilities incurred ........................... 40 --
Liabilities settled ............................ -- (14)
Gain from adjustment to estimated obligations .. (6) (9)
Accretion expense .............................. 100 97
Revisions in estimated cash flows .............. -- (4)
------ ------
Ending asset retirement obligations ............ $1,756 $1,622
====== ======
40
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
INVESTMENT IN NEW AVOCA
Until its sale in October 2004, we recorded our investment in New Avoca
(25% owned and managed by us) using the equity method of accounting. Under
the equity method, investments are recorded at cost plus our equity in
earnings and losses after acquisition.
STOCK-BASED COMPENSATION
We apply SFAS No. 123, Accounting for Stock-Based Compensation, which
allows us to adopt a fair value based method of accounting for a
stock-based employee compensation plan or to continue to use the intrinsic
value based method of accounting prescribed by Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees. We account for
stock-based compensation under the intrinsic value method and provide the
pro forma effects of the fair value method as required.
Stock-based compensation expense of $774,369 was recognized in the twelve
months ended December 31, 2005. Recognition of non-cash expense is required
by Financial Accounting Standards Board Interpretation No. 44 Accounting
for Certain Transactions involving Stock Compensation - An Interpretation
of APB Opinion No. 25 ("FIN 44"). Pursuant to FIN 44, stock options
exercised in a "cashless" manner by surrendering a portion of the option
shares issued to pay the option exercise price, trigger variable accounting
treatment, requiring the measurement of compensation expense at a period
beyond the date of grant.
In the fiscal quarter ending March 31, 2006, we will begin accounting for
stock-based compensation under Statement of Financial Accounting Standards
No. 123(R) Share-Based Payment. SFAS No. 123(R) is a revision to Statement
of Financial Accounting Standards No. 123 Accounting for Stock-Based
Compensation, and eliminates the ability to account for share-based
compensation transactions using APB Opinion No. 25. It requires that such
transactions be accounted for using a fair value-based method.
The remainder of this page left blank intentionally.
41
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Had compensation cost for our stock option plans been determined based on
the fair market value at the grant dates for awards made, our net income
(loss) and income (loss) per share would have been adjusted to the pro
forma amounts indicated below:
Years ended December 31,
------------------------
2005 2004
---------- -----------
Net income (loss) as reported $ 541,386 $(2,500,334)
Add: total stock-based employee compensation expense
included in net income (loss), net of related tax effects 774,369 693,513
Deduct: total stock-based employee compensation expense
determined under fair value based method for all awards,
net of tax related effects (66,420) (866,193)
---------- -----------
Pro forma net income (loss) $1,249,335 $(2,673,014)
========== ===========
Basic income (loss) per share:
As reported $ 0.06 $ (0.37)
Pro forma $ 0.14 $ (0.40)
Diluted income (loss) per share:
As reported $ 0.06 $ (0.37)
Pro forma $ 0.14 $ (0.40)
RECOGNITION OF OIL AND GAS REVENUE
Sales from producing wells are recognized on the entitlement method of
accounting which defers recognition of sales when, and to the extent that,
deliveries to customers exceed our net revenue interest in production.
Similarly, when deliveries are below our net revenue interest in
production, sales are recorded to reflect the full net revenue interest.
Our imbalance liability at December 31, 2005 was not material.
RECOGNITION OF PIPELINE TRANSPORTATION REVENUE
Revenues from our pipelines are derived from fee-based contracts and are
typically based on transportation fees per unit of volume transported
multiplied by the volume delivered. Revenue is recognized when volumes have
been physically delivered for the customer through the pipeline.
INCOME TAXES
We provide for income taxes using the asset and liability method pursuant
to SFAS No. 109, Accounting for Income Taxes. Under the asset and liability
method of SFAS No. 109, deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences
42
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
between the financial statement carrying amounts of existing assets and
liabilities and their respective tax bases and operating loss and tax
credit carryforwards. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered or settled.
The effect on deferred tax assets and liabilities of a change in tax rates
is recognized in income in the period that includes the enactment date.
EARNINGS PER SHARE
We follow SFAS No. 128, Earnings per Share, for computing and presenting
earnings per share which requires, among other things, dual presentation of
basic and diluted earnings per share on the face of the statement of
operations.
Employee stock options of 346,942 and stock warrants of 3,100,000 at
December 31, 2004 were not included in the computation of diluted earnings
per share because the effect of their assumed exercise and conversion would
have an antidilutive effect on the computation of diluted loss per share.
The following table provides a reconciliation between basic and diluted
earnings per share:
Weighted-
Average Number
of Common Shares
Outstanding
and Potential Per
Net Income Dilutive Share
(Loss) Common Shares Amount
----------- ---------------- ------
Year ended December 31, 2005
Basic income per share $ 541,386 8,763,475 $0.06
Effect of dilutive stock options -- 110,642 --
----------- --------- -----
Diluted income per share $ 541,386 8,874,117 $0.06
=========== ========= =====
Year ended December 31, 2004
Basic and diluted loss per share $(2,500,334) 6,734,395 $(0.37)
=========== ========= =====
ENVIRONMENTAL
We are subject to extensive federal, state and local environmental laws and
regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require us to remove or
mitigate the environmental effects of the disposal or release of petroleum
or chemical substances at various sites. Environmental expenditures are
expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations
and that have no future economic benefits are expensed. Liabilities for
expenditures of a noncapital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated. Such liabilities are generally recorded at their undiscounted
amounts unless the amounts and timing of payments is fixed or reliably
determinable.
43
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based
Payment. This statement addresses the accounting for share-based payment
transactions in which an enterprise receives employee services in exchange
for (a) equity instruments of the enterprise, or (b) liabilities that are
based on the fair value of the enterprise's equity instruments or that may
be settled by the issuance of such equity instruments. SFAS No. 123(R)
requires an entity to recognize the grant-date fair-value of stock options
and other equity-based compensation issued to employees in the income
statement. The revised Statement requires that an entity account for those
transactions using the fair-value-based method, and eliminates the
intrinsic value method of accounting in APB No. 25, Accounting for Stock
Issued to Employees, which was permitted under SFAS No. 123, as originally
issued. The revised Statement requires entities to disclose information
about the nature of the share-based payment transactions and the effects of
those transactions on the financial statements. SFAS No. 123(R) is
effective for public companies for the first fiscal year beginning after
December 31, 2005. All public companies must use either the modified
prospective or the modified retrospective transition method. We have not
yet evaluated the impact of the adoption of this pronouncement, which must
be adopted in the first quarter of calendar year 2006. On March 29, 2005,
the Securities Exchange Commission staff issued SAB No. 107, Share-Based
Payment, to express the views of the staff regarding the interaction
between SFAS No. 123(R) and certain Securities Exchange Commission rules
and regulations and to provide the staff's views regarding the valuation of
share-based payment arrangements for public companies. The Company will
take into consideration the additional guidance provided by SAB 107 in
connection with the implementation of SFAS No. 123(R).
In March 2005, the FASB issued Interpretation (FIN) No. 47, Accounting for
Conditional Asset Retirement Obligations -- An Interpretation of SFAS No.
143, which clarifies the term "conditional asset retirement obligation"
used in SFAS No. 143, Accounting for Asset Retirement Obligations, and
specifically when an entity would have sufficient information to reasonably
estimate the fair value of an asset retirement obligation. The adoption did
not have an impact on the Company's financial statements.
In May 2005, the FASB issued SFAS No. 154, Accounting for Changes and Error
Corrections - a Replacement of APB Opinion No. 20 and FASB Statement No. 3
("SFAS No. 154"). SFAS No. 154 requires retrospective application of
voluntary changes in accounting principles, unless impracticable. SFAS No.
154 supersedes the guidance in APB Opinion No. 20 and SFAS No. 3, but does
not change any transition provisions of existing pronouncements. Generally,
elective accounting changes will no longer result in a cumulative effect of
a change in accounting in the income statement, because the effects of any
elective changes will be reflected as prior period adjustments to all
periods presented. SFAS No. 154 will be effective beginning in fiscal 2006
and will affect any accounting changes that we elect to make thereafter.
In February 2006, the FASB issued SFAS No. 155, Accounting for Certain
Hybrid Financial Instruments--an amendment of FASB Statements No. 133 and
140 ("SFAS No. 155"). This statement amends SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities ("SFAS No. 133"), and SFAS
No. 140, Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities and resolves issues addressed in SFAS No.
133 Implementation Issue No. D1, Application of Statement No. 133 to
Beneficial Interest in
44
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Securitized Financial Assets. This Statement: (a) permits fair value
remeasurement for any hybrid financial instrument that contains an embedded
derivative that otherwise would require bifurcation; (b) clarifies which
interest-only strips and principal-only strips are not subject to the
requirements of SFAS No. 133; (c) establishes a requirement to evaluate
beneficial interests in securitized financial assets to identify interests
that are freestanding derivatives or that are hybrid financial instruments
that contain an embedded derivative requiring bifurcation; (d) clarifies
that concentrations of credit risk in the form of subordination are not
embedded derivatives; and, (e) eliminates restrictions on a qualifying
special-purpose entity's ability to hold passive derivative financial
instruments that pertain to beneficial interests that are or contain a
derivative financial instrument. The standard also requires presentation
within the financial statements that identifies those hybrid financial
instruments for which the fair value election has been applied and
information on the income statement impact of the changes in fair value of
those instruments. The Company is required to apply SFAS No. 155 to all
financial instruments acquired, issued or subject to a remeasurement event
beginning January 1, 2007, although early adoption is permitted as of the
beginning of an entity's fiscal year. The provisions of SFAS No. 155 are
not expected to have an impact at adoption.
(2) LIQUIDITY AND GOING CONCERN
At December 31, 2005, our working capital was approximately $2.1 million.
This is a significant improvement from our December 31, 2004 working
capital of approximately $0.4 million. Due to our continuing losses and
indebtedness, our auditors, UHY Mann, Frankfort, Stein and Lipp, LLP added
an explanatory paragraph to their opinion on our consolidated financial
statements for the year ended December 31, 2004, indicating that
substantial doubt existed about our ability to continue as a going concern.
However, our financial condition experienced a significant improvement as a
result of the cash flows we have received from our non-operated working
interests in High Island Block 37 and High Island Block A-7, increased gas
transportation rates negotiated with existing shippers in 2004 and
transportation agreements we have signed with three new shippers on the
Blue Dolphin System in 2005.
We are continuing to receive monthly cash inflows from both of the High
Island properties. The two wells in High Island Block 37 are currently
producing approximately 23 MMcf per day combined. High Island Block A-7 has
one well currently producing at approximately 7 MMcf per day. Only one of
the new shippers on the Blue Dolphin System is delivering production into
our pipeline at this time. It is expected the other two new shippers will
initiate deliveries in the second quarter of 2006.
Also, in March 2006, we entered into a stock purchase agreement with
certain accredited investors for the private placement of 1,171,432 shares
of our common stock at a price of $1.75 per share. The net proceeds from
this offering after commissions and expenses were approximately $2,025,000.
We expect to use these proceeds for possible acquisitions and planned
expansions of our existing facilities as well as for working capital and
general corporate purposes. We believe we have sufficient liquidity to
satisfy our working capital requirements through December 31, 2006.
(3) FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash and cash equivalents, accounts receivable and
accounts payable approximate fair value due to the short-term maturities of
these instruments. The carrying value
45
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
of our notes payable and debt approximates the fair value due to the
short-term nature of such note.
(4) INCOME TAXES
Income tax expense consisted of current federal expense of $13,105 and $0
for 2005 and 2004, respectively.
The income tax effects of temporary differences that give rise to
significant portions of deferred tax assets and deferred tax liabilities at
December 31, 2005 are presented below:
Deferred tax assets:
Net operating loss and capital loss carryforwards $ 4,095,317
AMT credit carryforward 13,105
Deferred tax liabilities:
Basis differences in property and equipment (19,191)
-----------
Net deferred tax asset 4,089,231
Less: valuation allowance (4,089,231)
-----------
Deferred tax asset, net $ --
===========
In assessing the reliability of deferred tax assets, we apply SFAS No. 109
to determine whether it is more likely than not that some portion or all of
the deferred tax assets will not be realized. As a result, a full valuation
allowance against our deferred tax asset was recognized at December 31,
2005 due to our uncertainty as to the utilization of the deferred tax asset
in the foreseeable future.
Our effective tax rate applicable to continuing operations in 2005 and 2004
is as follows:
Years ended
December 31,
------------
2005 2004
---- ----
Expected tax rate (34%) (34%)
State taxes, net of federal benefit -- --
Expenses not deductible for tax purposes -- --
Change in valuation allowance recognized
in earnings 34% 34%
Other 2.35% --
---- ---
2.35% 0%
==== ===
For federal tax purposes, we have a net operating loss carryforwards
("NOLs") of approximately $12.0 million at December 31, 2005. These NOLs
must be utilized prior to their expiration, which is between 2006 and 2024.
During 2004, we received a $244,444 refund from prior periods alternative
minimum tax credits.
On September 8, 2004, American Resources Offshore, a wholly owned
subsidiary, was sold to Ivar Siem, our Chairman and chief Executive
Officer, on behalf of certain stockholders who held a number of shares of
our common stock above a threshold that he determined at the time of sale.
46
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
American Resources had $17.5 million of NOL's that we would likely have not
been able to utilize due to limitations on their use resulting from a prior
ownership change. American Resources did have $7.3 million of NOL's that
were not subject to limitations.
(5) LONG-TERM DEBT AND NOTES PAYABLE
On February 28, 2005 (effective as of January 1, 2005), we entered into the
Amendment to our Purchase Agreement with MCNIC. Under the terms of the
original Purchase Agreement, we acquired MCNIC's one-third interests in
both the Blue Dolphin System and the inactive Omega Pipeline. Pursuant to
the terms of the Amendment, the Original Promissory Note was exchanged for
the New Promissory Note, and all accrued interest on the Original
Promissory Note, $132,368 at December 31, 2004, was forgiven and included
in other income for the year ended December 31, 2005. In addition to the
New Promissory Note, MCNIC can receive additional payments of up to
$500,000 from 50% of the net profits, if any, realized from the one-third
interest in the Blue Dolphin System through December 31, 2006. We made a
principal payment on the New Promissory Note of $30,000 upon the execution
of the Amendment. Under the terms of the New Promissory Note we will make
monthly principal payments of $10,000 through its maturity date of December
31, 2006. The principal amount of the New Promissory Note may be increased
by up to $500,000 if 50% or more of our 83% interest in the Blue Dolphin
System is sold before December 31, 2006.
Long-term debt at December 31, 2005 is as follows:
Note payable secured by the 1/3 interest acquired $620,000
Less current maturities 120,000
--------
$500,000
========
In April 2005, the holders of $450,000 of the $750,000 aggregate principal
amount of promissory notes sold in September 2004, agreed to extend the
maturity date of their promissory notes to June 30, 2006, and to defer the
payment of all unpaid and future interest on their promissory notes until
maturity. The promissory notes were originally sold on September 8, 2004
pursuant to the Note and Warrant Purchase Agreement we entered into with
certain accredited investors and certain of our directors. The remaining
$300,000 aggregate principal amount of promissory notes was retired at
maturity on September 8, 2005.
Total interest expense was approximately $82,000 and $85,000 for 2005 and
2004, respectively.
(6) EXERCISE OF WARRANTS
At January 1, 2005, there were 3,100,000 warrants outstanding that were
issued pursuant to our Note and Warrant Purchase Agreement dated September
8, 2004. During the twelve months ended December 31, 2005, all 3,100,000
warrants were exercised.
The exercise of the warrants was accomplished via net exercises, whereby
holders surrendered their right to purchase a portion of the shares of
common stock, resulting in 279,631 shares of common stock being surrendered
to us for payment of the warrant exercise price and 2,820,369 shares issued
to warrant holders.
47
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) STOCKHOLDERS' EQUITY
In 2005, 319,321 stock options were exercised in a "cashless" manner,
resulting in the issuance of 201,899 shares of common stock and recognition
of approximately $774,000 of non-cash compensation expense. Also in 2005,
3,100,000 warrants outstanding were exercised in a "cashless" manner,
whereby holders surrender a portion of the shares obtained to pay for the
exercise price of the warrants, resulting in 279,631 shares of common stock
being surrendered and 2,820,369 shares of common stock issued to the
warrant holders.
In January 2006, we issued 30,000 shares of common stock into our Blue
Dolphin Services Co. 401K Plan as a 2005 contribution. We recorded
compensation expense of $64,800 associated with this contribution.
(8) STOCK OPTIONS
Effective April 14, 2000, we adopted, after approval by stockholders, a
stock incentive plan (the "2000 Plan"). The stock subject to the options
and other provisions of the 2000 Plan are shares of our common stock. We
amended the 2000 Plan effective March 19, 2003, after approval by our
stockholders on May 21, 2003, increasing the number of shares of common
stock available for incentive stock options ("ISOs") from 500,000 to
650,000 shares. The 2000 Plan is administered by the Compensation Committee
of our Board of Directors. Options granted must be exercised within 10
years from their grant date. The exercise price of ISOs cannot be less than
100% of the fair market value of a share of common stock. The 2000 Plan
also provides for the granting of other incentive awards, however only ISOs
and non-statutory stock options have been issued under the 2000 Plan.
We adopted a stock option plan in 1996 (the "1996 Plan"). The stock subject
to the options and other provisions of the 1996 Plan are shares of common
stock. The remaining options outstanding issued pursuant to this plan
expired in January 2004.
The remainder of this page left blank intentionally.
48
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
At December 31, 2005 we had reserved a total of 143,997 shares of common
stock for issuance under the above mentioned stock option plans. A summary
of the status of our fixed stock options granted to key employees, officers
and directors, for the purchase of shares of common stock, are as follows:
DECEMBER 31,
-------------------------------------------------------
2005 2004
-------------------------- --------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE
--------- -------------- --------- --------------
Options outstanding at the beginning
of the year 346,942 $1.09 501,919 $1.06
Options granted at an exercise price
of $.80 per share 90,376 $0.80 -- --
Options exercised (289,321) $0.71 (117,142) $0.39
Options expired or cancelled (4,000) $4.89 (37,835) $2.99
--------- ---------
Options outstanding at the end of the year 143,997 346,942
========= =========
Weighted average exercise price of
options outstanding $ 1.56 $ 1.09
Weighted average fair value of options
granted during the period $ 0.73 --
Weighted average remaining contractual
life of options outstanding 7.1 years 7.6 years
The remainder of this page left blank intentionally.
49
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes information about fixed stock options outstanding
at December 31, 2005:
OPTIONS OUTSTANDING AND EXERCISABLE
-----------------------------------------------
WEIGHTED
AVERAGE
REMAINING WEIGHTED
NUMBER CONTRACTUAL LIFE AVERAGE
EXERCISE PRICES OUTSTANDING IN YEARS EXERCISE PRICE
---------------- ----------- ---------------- --------------
$.35 to $.80 98,768 7.8 $0.54
$1.55 to $1.90 23,429 6.1 $1.71
$6.00 21,800 4.4 $6.00
-------
143,997
=======
At December 31, 2005, options for 143,997 shares of common stock were
immediately exercisable. There were 90,376 options granted in 2005, and no
options granted in 2004. Pursuant to the requirements of SFAS No. 123, the
weighted average fair market value of options granted during 2005 was $0.73
per share. The weighted average closing bid price for our common stock at
the date the options were granted during 2005 was $0.80 per share. The
weighted average exercise price for outstanding options at December 31,
2005 and 2004 per share was $1.56 and $1.09, respectively. The fair market
value pursuant to SFAS 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 104.6%, risk-free interest rate of 3.72% for
grants in 2005, and an expected life of one year. There were no grants of
stock options in 2004. As we have not declared dividends on our common
stock since it became a public entity, no dividend yield was used. Actual
value realized, if any, is dependent on the future performance of our
common stock and overall stock market conditions. There is no assurance the
value realized by an optionee will be at or near the value estimated by the
Black-Scholes model.
Outstanding options at December 31, 2005 expire between May 17, 2010 and
February 3, 2015.
(9) RELATED PARTY TRANSACTIONS
Related party transactions which are not disclosed elsewhere in these
consolidated financial statements are discussed in the following
paragraphs:
We own 0.07% of the common stock of Drillmar, Inc. ("Drillmar"). Our
Chairman, Ivar Siem, and one of our Directors, Harris A. Kaffie, own or
control 28.1%, and 18.6%, respectively, of Drillmar's common stock. Messrs.
Siem and Kaffie are both directors, and Mr. Siem is Chairman and President
of Drillmar.
In 2002, we recorded a full impairment of our investment in Drillmar and a
full reserve for the accounts receivable amount owed to us from Drillmar of
approximately $200,000 due to Drillmar's working capital deficiency and
delays in securing capital funding. During 2004, we
50
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
collected $165,000 of the accounts receivable from Drillmar and we have
collected the remaining balance of approximately $45,000 in 2005.
In January 2003, Drillmar stockholders approved a restructuring plan
whereby Drillmar was able to issue up to $3.0 million of convertible notes
that will convert into common stock representing over 99% of Drillmar's
outstanding shares. As a result, our ownership in Drillmar has been reduced
to less than 1%. In November 2003, we converted a contingent obligation due
from Drillmar for providing office space, accounting and administrative
services from May 2002 through January 2003 totaling $162,000 (9 months at
$18,000 per month) into a convertible note. In December 2005, we collected
$178,555 from Drillmar for this convertible note, including interest at 6%
per annum.
We entered into an agreement with Drillmar effective as of February 1,
2003, whereby we provide and charge for office space which is currently
$4,178 per month. We had provided professional, accounting and
administrative services to Drillmar based on hourly rates based on our
cost. However, since our implementation of staff reductions in mid 2004, no
such services have been provided. The agreement can be terminated upon 30
days notice or by the mutual agreement of the parties.
(10) LEASES
We have various noncancelable operating leases which continue through 2006.
In March 2003, we entered into a sublease agreement expiring December 31,
2006 for certain of our office space with TexCal Energy (GP) LLC, formerly
Tri-Union Development Corporation. Our annual receipts from this sublease
are approximately $78,000. One of our Directors, Mr. Trimble, was the
Chairman and Chief Executive Officer of TexCal Energy (GP) LLC until
November 2004.
The following is a schedule of future minimum lease payments required under
noncancelable operating leases at December 31, 2005:
Future minimum
Year ending Future minimum Future sublease lease payments,
December 31, lease payments payments net
------------ -------------- --------------- ---------------
2006 $201,549 $78,552 $122,997
2007 5,931 -- 5,931
2008 5,931 -- 5,931
2009 5,931 -- 5,931
2010 3,174 -- 3,174
-------- ------- --------
Total $222,516 $78,552 $143,964
======== ======= ========
51
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Rental expense on operating leases, net of sublease income and other rental
reimbursements, for the years indicated are as follows:
Years ended
December 31,
------------
2005 $46,287
2004 $64,632
(11) COMMITMENTS AND CONTINGENCIES
We are involved in various claims and legal actions arising in the ordinary
course of business. In our opinion, the ultimate disposition of these
matters will not have a material effect on our consolidated financial
position, results of operations or cash flows.
(12) BUSINESS SEGMENT INFORMATION
Our income producing operations are conducted in two principal business
segments: (i) pipeline transportation services and (ii) oil and gas
exploration and production. Intercompany revenue and expenses are
eliminated in consolidation. Information concerning these segments for the
years ended December 31, 2005 and 2004 is as follows:
Depletion,
Operating Depreciation,
income Identifiable Amortization and
Revenues (loss) (1) assets (3) Impairment (2)
---------- ---------- ------------ ----------------
Year Ended December 31, 2005:
Pipeline transportation $1,375,173 (467,484) 5,645,179 319,686
Oil and gas exploration
and production 3,136,010 2,025,255 1,358,484 73,940
Other (1,395,361) 1,069,884 9,591
---------- ---------- --------- -------
Consolidated 4,511,183 162,410 8,073,547 403,217
Other income 392,081
----------
Income before income taxes 554,491
Year Ended December 31, 2004:
Pipeline transportation $1,014,137 (1,331,046) 5,743,418 327,418
Oil and gas exploration
and production 395,700 (182,770) 295,916 94,025
Other 25,809 (1,180,425) 1,364,133 11,323
---------- ---------- --------- -------
Consolidated 1,435,646 (2,694,241) 7,403,467 432,766
Other income 193,907
----------
Loss before income taxes (2,500,334)
----------
1. Consolidated income (loss) from operations includes $1,385,768 and
$1,194,911 in unallocated general and administrative expenses, and
unallocated depletion, depreciation,
52
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
amortization and impairment of $9,591 and $11,323 for the years ended
December 31, 2005 and 2004, respectively. All unallocated amounts are
included in "Other".
2. Pipeline depletion, depreciation and amortization includes a provision for
pipeline abandonment of $48,595 for the years ended December 31, 2005 and
2004. Oil and gas depletion, depreciation, amortization and impairment
includes a provision for abandonment costs of platforms and wells of
$20,169 and $24,497 for the years ended December 31, 2005 and 2004,
respectively.
3. See the supplemental disclosures for oil and gas producing activities for
discussion of capitalized costs incurred for oil and gas production
operations. Capital expenditures of $25,179 and $1,075 were recorded for
pipeline operations for the years ended December 31, 2005 and 2004,
respectively.
Our primary market area is the Texas and Louisiana Gulf Coast region of the
United States. We have a concentration of credit risk with customers in the
energy industry. Our customers may be similarly affected by changes in
economic, regulatory or other factors. Trade receivables are generally not
collateralized; however, our customers' historical and future credit
positions are thoroughly analyzed prior to extending credit. Revenues from
major customers exceeding 10% of revenues were as follows for the period
indicated.
Oil and gas Pipeline
Sales Operations Total
----------- ---------- ----------
Year ended December 31, 2005:
Hydro Gulf, LLC (formerly Spinnaker $ 722,499 -- $ 722,499
Exploration Company)
Fidelity Exploration and
Production Company $2,413,511 -- $2,413,511
Year ended December 31, 2004:
Hydro Gulf, LLC (formerly Spinnaker $ 331,858 -- $ 331,858
Exploration Company)
Houston Exploration -- $239,444 $ 239,444
Apache Corporation -- $229,265 $ 229,265
Kerr McGee Oil & Gas -- $152,487 $ 152,487
(13) SUPPLEMENTAL OIL AND GAS INFORMATION - UNAUDITED
The following supplemental information regarding our oil and gas activities
are presented pursuant to the disclosure requirements promulgated by the
Securities and Exchange Commission and SFAS No. 69, Disclosures About Oil
and Gas Producing Activities.
In April 2003, we began to receive revenue from our 8.9% reversionary
working interest in the High Island Block A-7 field, in the Gulf of Mexico.
Production from this field accounted for 23% and 84% of our oil and gas
sales for the years ended December 31, 2005 and 2004, respectively, and 16%
and 23% of our total revenue for these periods, respectively.
In August 2003, "payout" occurred on the High Island Block 34 field, in
which we owned a 1.8% reversionary interest. In June 2004, we sold our
working interest to Fidelity Exploration Company for approximately $34,000
and recorded a gain of $25,809. Production from this field
53
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
accounted for 16% of our oil and gas sales for the year ended December 31,
2004, and 4% of our total revenues for this period.
In September 2005, we began receiving payments for our contractual
after-payout working interest in High Island Block 37. The initial payment
of approximately $1.3 million was for production net of expenses from the
estimated payout on July 1, 2004, through May 2005. We have recognized
gross gas and oil sales revenues of approximately $2.4 million and lease
operating expenses of approximately $16,000 associated with High Island
Block 37 in 2005, representing our interests from payout through December
2005. We have a working interest of approximately 2.8% in two wells in the
block.
Also in September 2005, two wells in High Island Block A-7 were
successfully recompleted and resumed production at a significantly higher
rate compared to the single well that produced through the first and second
quarters of 2005. The wells were shut-in while third party transporters
made repairs following Hurricane Rita. One well resumed production in late
October and the second well resumed production in early November. We
recognized gross gas and oil sales revenues of approximately $722,000 and
lease operating expenses of approximately $125,000 for High Island Block
A-7 for the year ended December 31, 2005. Approximately $630,000 of these
revenues are for production in the fourth quarter after the recompletions.
Lease operating expenses were spread relatively evenly throughout the year.
Our after-payout working interest is approximately 8.9 % in both wells.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Set forth below is a summary of the changes in the estimated quantities of
our crude oil and condensate, and gas reserves for the periods indicated,
as estimated by us at December 31, 2005 and 2004. All of our reserves are
located within the United States of America. Proved reserves cannot be
measured exactly because the estimation of reserves involves numerous
judgmental determinations. Accordingly, reserve estimates must be
continually revised as a result of new information obtained from drilling
and production history, new geological and geophysical data and changes in
economic conditions.
Proved reserves are estimated quantities of 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.
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54
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Oil Gas
Quantity of Oil and Gas Reserves (Bbls) (Mcf)
-------------------------------- ------ --------
Total proved reserves at December 31, 2003 291 41,650
Revisions to previous estimate 884 60,984
Production (810) (66,491)
Reserves sold -- (879)
----- --------
Total proved reserves at December 31, 2004 365 35,264
===== ========
Revisions of previous estimates -- --
Extensions, discoveries, improved recovery
and other additions 1,303 685,080
Purchases of reserves in place -- --
Sales of reserves in place -- --
Production (781) (378,791)
----- --------
Total proved reserves at December 31, 2005 887 341,553
===== ========
Proved developed reserves:
December 31, 2005 887 341,553
December 31, 2004 365 35,264
55
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
CAPITALIZED COSTS OF OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the aggregate amounts of capitalized costs
relating to our oil and gas producing activities and the aggregate amount of
related accumulated depletion, depreciation, amortization and impairment as of:
December 31,
---------------------
2005 2004
--------- ---------
Unproved properties and prospect generation
costs not being amortized $ 5,343 $ 177,589
Proved properties being amortized 544,377 339,621
Less accumulated depletion, depreciation,
amortization and impairment (403,982) (331,752)
--------- ---------
Net capitalized costs $ 145,738 $ 185,458
========= =========
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
The following table reflects the costs incurred in oil and gas property
acquisition, disposition, exploration and development activities during the
periods indicated:
Years ended
December 31,
-----------------
2005 2004
------- -------
Exploration costs $ -- $26,197
Development costs 72,501 393
------- -------
$72,501 $26,590
======= =======
We did not acquire any oil and gas properties in 2004 or 2005.
56
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities below exclude
non-oil and gas revenues, general and administrative expenses, interest expense
and interest income.
Years ended December 31,
------------------------
2005 2004
---------- ---------
Revenues from oil and gas producing activities $3,136,010 $ 395,700
Production costs (155,174) (134,313)
Depreciation, Depletion, and Amortization (73,940) (94,025)
---------- ---------
Pretax income from producing activities 2,906,896 167,362
Income tax expense (123,698) --
---------- ---------
Results of oil and gas producing activities
(excluding corporate overhead and interest costs) $2,783,198 $ 167,362
========== =========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following table reflects the Standardized Measure of Discounted Future Net
Cash Flows relating to our interest in proved oil and gas reserves as of:
December 31,
-----------------------
2005 2004
----------- ---------
Future cash inflows $ 3,807,000 $ 270,000
Future development and dismantlement costs (268,000) (216,000)
Future production costs (162,000) (108,000)
Future income taxes (1,148,180) 18,360
10% discount factor (123,420) 23,760
----------- ---------
Standardized measure of discounted
future net cash inflows (outflows) $ 2,105,400 $ (11,880)
=========== =========
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 year-end prices and (2) deducting estimated expenditures to be incurred
during each year to develop and produce the proved reserves (based on year-end
costs).
57
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
We caution readers that the standardized measure information which places a
value on proved reserves is not indicative of either fair market value or
present value of future cash flows. Other logical assumptions could have been
used for this computation which would likely have resulted in significantly
different amounts. Such information is disclosed solely in accordance with
Statement 69 and the requirements promulgated by the Securities Exchange
Commission to provide readers with a common base for use in preparing their own
estimates of future cash flows and for comparing reserves among companies. We do
not rely on these computations when making investment and operating decisions.
Principal changes in the Standardized Measure of Discounted Future Net Cash
Flows attributable to our proved oil and gas reserves for the periods indicated
are as follows:
December 31
-----------------------
2005 2004
----------- ---------
Sales and transfers, net of production costs $(2,980,836) $(261,387)
Extensions, discoveries, and improved recovery, net
of future production and development costs 6,170,836 --
Net change in estimated future development costs 204,039 1,869
Sales of minerals in place -- (4,119)
Revisions in previous quantity estimates -- 190,537
Net changes in sales and transfer prices,
net of production costs (54,000) 4,648
Accretion of discount (1,800) (3,800)
Net change in income taxes (1,090,720) (6,800)
Change in production rates and other (130,239) 92,252
----------- ---------
Net change $ 2,117,280 $ 13,200
=========== =========
(14) SUBSEQUENT EVENTS
In March 2006, we entered into a stock purchase agreement with certain
accredited investors for the private placement of 1,171,432 shares of our
common stock at a purchase price of $1.75 per share. The net proceeds from
the offering after the payment of commissions and expenses were
approximately $2,025,000. The Company expects to use the proceeds for
possible acquisitions and planned expansions of its facilities, as well as
for working capital needs and general corporate purposes. In addition, in
connection with the terms of a Placement Agency Agreement, we issued
warrants to purchase an aggregate of 8,572 shares of common stock. The
warrants vest immediately upon issuance and the exercise price per share
varies based on the following conditions: (i) until the later of the
registration of the warrants or one year from the issue date, 110% of the
purchase price per share in the offering, (ii) from the later of (x) the
registration of
58
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
the warrants and (y) one year, until two years from the issue date, 120% of
the purchase price per share in the offering and (iii) after the expiration
of two years from the issue date of the warrants, 130% of the purchase
price per share in the offering.
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
ITEM 8A. CONTROLS AND PROCEDURES
We have evaluated the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the Exchange Act), as of the end of the year covered by this report. The
evaluation was accomplished under the supervision and with the participation of
our management, including our Chief Executive Officer and Principal Accounting
and Financial Officer. Based upon this evaluation, the Chief Executive Officer
and Principal Accounting and Financial Officer concluded that at December 31,
2005, our disclosure controls and procedures are effective to ensure that
information required to be disclosed by us in reports that we file or submit
under the Exchange Act, is recorded, processed, summarized and reported within
the time periods specified in the Securities Exchange Commission's rules and
forms.
However, during the fourth quarter of 2005, management determined that a
significant deficiency in our internal controls over financial reporting
impacted the adequacy of our disclosure controls and procedures with respect to
the application of Generally Accepted Accounting Principles ("GAAP") to the
"cashless" exercise of stock options by certain directors and employees. We
account for stock-based compensation as fixed awards under the Intrinsic Value
Method as prescribed by Accounting Principles Board Opinion No. 25 Accounting
for Stock Issued to Employees ("APB No. 25"). Under APB No. 25, the compensation
expense associated with option grants that receive fixed accounting treatment is
measured at the grant date. When variable accounting treatment is applied,
compensation expense is measured again and recognized at periods after the
initial measurement date. We concluded, after consultation with UHY, that
options exercised using the "cashless" exercise method require variable
accounting treatment under Financial Accounting Standards Board Interpretation
No. 44 Accounting for Certain Transactions involving Stock Compensation - An
Interpretation of APB Opinion No. 25 ("FIN 44"). The error in our reporting of
compensation expense resulted in the restatement of the financial information
for the quarters ended March 31, 2005 and June 30, 2005. The error was
discovered prior to the filing of the financial information for the quarter
ended September 30, 2005. Compensation expense for the period covered by this
report has been reported using variable accounting when required, consistent
with FIN 44.
In response to the identified significant deficiency, we took remedial steps to
improve the control processes regarding the application of GAAP and preparation
and review of the consolidated financial statements. Specifically, key personnel
involved in our financial reporting process enhanced the methods through which
authoritative guidance will be monitored on a regular basis. On-going reviews of
authoritative guidance are being conducted in order to ensure that the guidance
is being complied with in the preparation of the financial statements, related
disclosures and periodic filings with the Securities Exchange Commission. As
previously disclosed, there were also changes in our internal controls over
financial reporting in the form of more in-depth project status review
procedures. All of these changes were designed to enhance our existing
disclosure controls and procedures. Other than the changes discussed above,
there have been no changes made in our internal control over financial reporting
that
59
materially affected, or is reasonably likely to materially affect, the internal
control over financial reporting, during the period covered by this report.
PART III
ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT; COMPLIANCE WITH
SECTION 16(A) OF THE EXCHANGE ACT
The information required by Item 9 is incorporated by reference to our
definitive proxy statement relating to our 2006 annual meeting of stockholders,
which proxy statement will be filed pursuant to Regulation 14A within 120 days
after the end of the last fiscal year.
ITEM 10. EXECUTIVE COMPENSATION
The information required by Item 10 is incorporated by reference to our
definitive proxy statement relating to our 2006 annual meeting of stockholders,
which proxy statement will be filed pursuant to Regulation 14A within 120 days
after the end of the last fiscal year.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by Item 11 is incorporated by reference to our
definitive proxy statement relating to our 2006 annual meeting of stockholders,
which proxy statement will be filed pursuant to Regulation 14A within 120 days
after the end of the last fiscal year.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 12 is incorporated by reference to our
definitive proxy statement relating to our 2006 annual meeting of stockholders,
which proxy statement will be filed pursuant to Regulation 14A within 120 days
after the end of the last fiscal year.
ITEM 13. EXHIBITS
(a) 1. Exhibits
No. Description
--- -----------
3.1 (1) Amended and Restated Certificate of Incorporation of the
Company.
3.2 (8) Amended and Restated Bylaws of the Company.
4.1 (2) Specimen Certificate of our Company common stock.
4.2 (6) Form of Promissory Note issued pursuant to the Note and Warrant
Purchase Agreement dated September 8, 2004.
* 10.1 (3) Blue Dolphin Energy Company 2000 Stock Incentive Plan.
60
* 10.2 (4) Amendment to the Blue Dolphin Energy Company 2000 Stock
Incentive Plan.
10.3 (5) Purchase and Sale Agreement by and between Blue Dolphin
Pipeline Company and MCNIC, dated February 1, 2002.
10.4 (6) Sale of American Resources Offshore, Inc. Common Stock
Agreement between Blue Dolphin Exploration Co. and Ivar Siem,
dated September 8, 2004.
10.5 (6) Note and Warrant Purchase Agreement between Blue Dolphin Energy
Company and Certain Investors, dated September 8, 2004.
10.6 (6) Consulting Agreement between Blue Dolphin Services Co. and F.
Gardner Parker dated September 8, 2004.
10.7 (7) Purchase and Sale Agreement by and between Blue Dolphin Energy
Company, WBI Pipeline & Storage Group, Inc. and SemGas LP,
dated October 29, 2004.
10.8 (9) Amendment to the Asset Purchase Agreement by and among MCNIC
Offshore Pipeline and Processing Company and Blue Dolphin Pipe
Line Company dated February 28, 2005.
* * 10.9 Placement Agency Agreement by and between Blue Dolphin Energy
Company and Starlight Investments, LLC dated May 27, 2005.
* * 10.10 Form of Stock Purchase Agreement between Blue Dolphin Energy
Company and Osler Holdings Limited, Gilbo Invest AS, Spencer
Energy AS, Spencer Finance Corp., Hudson Bay Fund, LP, Don
Fogel and SIBEX Capital Fund, Inc. dated March 8, 2006.
14.1 (10) Code of Ethics applicable to the Chairman, Chief Executive
Officer and Senior Financial Officer.
* * 21.1 List of Subsidiaries of the Company.
* * 23.1 Consent of UHY Mann Frankfort Stein & Lipp CPAs, LLP.
* * 31.1 Ivar Siem Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 302 of the Sarbanes-Oxley Act of
2002.
* * 31.2 Gregory W. Starks Certification Pursuant to 18 U.S.C. Section
1350, as adopted pursuant to section 302 of the Sarbanes-Oxley
Act of 2002.
* * 32.1 Ivar Siem Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 906 of the Sarbanes-Oxley Act of
2002.
* * 32.2 Gregory W. Starks Certification Pursuant to 18 U.S.C. Section
1350, as adopted pursuant to section 906 of the Sarbanes-Oxley
Act of 2002.
* Management Compensation Plan.
** Filed herewith.
----------
(1) Incorporated herein by reference to Exhibits filed in connection with the
definitive Proxy Statement of Blue Dolphin Energy Company under the
Securities and Exchange Act of 1934, dated October 13, 2004 (Commission
File No. 000-15905).
61
(2) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1989
under the Securities and Exchange Act of 1934, dated March 30, 1990
(Commission File No. 000-15905).
(3) Incorporated herein by reference to Exhibits filed in connection with the
Proxy Statement of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated May 18, 2000 (Commission File No. 000-15905).
(4) Incorporated herein by reference to Exhibits filed in connection with the
definitive Proxy Statement of Blue Dolphin Energy Company under the
Securities and Exchange Act of 1934, dated April 16, 2003 (Commission File
No. 000-15905).
(5) Incorporated herein by reference to Exhibits filed in connection with Form
10-KSB of Blue Dolphin Energy Company under the Securities and Exchange Act
of 1934, dated July 23, 2002 (Commission File No. 000-15905).
(6) Incorporated herein by reference to Exhibits filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated September 14, 2004 (Commission File No. 000-15905).
(7) Incorporated herein by reference to Exhibits filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated December 6, 2004 (Commission File No. 000-15905).
(8) Incorporated herein by reference to Exhibits filed in connection with Form
10-QSB of Blue Dolphin Energy Company for the quarter ended June 30, 2004
under the Securities and Exchange Act of 1934, dated August 20, 2004
(Commission File No. 000-15905)
(9) Incorporated herein by reference to Exhibits filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated March 2, 2005.
(10) Incorporated herein by reference to Exhibit 14.1 filed in connection with
Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31,
2004 under the Securities Exchange Act of 1934, dated March 25, 2005
(commission file No. 000-15905).
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by Item 14 is incorporated by reference to our
definitive proxy statement relating to our 2006 annual meeting of stockholders,
which proxy statement will be filed pursuant to Regulation 14A within 120 days
after the end of the last fiscal year.
62
SIGNATURES
In accordance with 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/ Ivar Siem
------------------------------------
Ivar Siem
(Chairman and CEO)
Date: March 30, 2006
In accordance with 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/ Ivar Siem Chairman and CEO March 30, 2006
------------------------------------- (Principal Executive Officer)
Ivar Siem
/s/ Gregory W. Starks Treasurer March 30, 2006
------------------------------------- (Principal Accounting and
Gregory W. Starks Financial Officer)
/s/ Laurence N. Benz Director March 30, 2006
-------------------------------------
Laurence N. Benz
/s/ Harris A. Kaffie Director March 30, 2006
-------------------------------------
Harris A. Kaffie
/s/ Michael S. Chadwick Director March 30, 2006
-------------------------------------
Michael S. Chadwick
/s/ James M. Trimble Director March 30, 2006
-------------------------------------
James M. Trimble
/s/ F. Gardner Parker Director March 30, 2006
-------------------------------------
F. Gardner Parker
63
EXHIBIT INDEX
No. Description
--- -----------
3.1 (1) Amended and Restated Certificate of Incorporation of the
Company.
3.2 (8) Amended and Restated Bylaws of the Company.
4.1 (2) Specimen Certificate of our Company common stock.
4.2 (6) Form of Promissory Note issued pursuant to the Note and Warrant
Purchase Agreement dated September 8, 2004.
* 10.1 (3) Blue Dolphin Energy Company 2000 Stock Incentive Plan.
* 10.2 (4) Amendment to the Blue Dolphin Energy Company 2000 Stock
Incentive Plan.
10.3 (5) Purchase and Sale Agreement by and between Blue Dolphin
Pipeline Company and MCNIC, dated February 1, 2002.
10.4 (6) Sale of American Resources Offshore, Inc. Common Stock
Agreement between Blue Dolphin Exploration Co. and Ivar Siem,
dated September 8, 2004.
10.5 (6) Note and Warrant Purchase Agreement between Blue Dolphin Energy
Company and Certain Investors, dated September 8, 2004.
10.6 (6) Consulting Agreement between Blue Dolphin Services Co. and F.
Gardner Parker dated September 8, 2004.
10.7 (7) Purchase and Sale Agreement by and between Blue Dolphin Energy
Company, WBI Pipeline & Storage Group, Inc. and SemGas LP,
dated October 29, 2004.
10.8 (9) Amendment to the Asset Purchase Agreement by and among MCNIC
Offshore Pipeline and Processing Company and Blue Dolphin Pipe
Line Company dated February 28, 2005.
* * 10.9 Placement Agency Agreement by and between Blue Dolphin Energy
Company and Starlight Investments, LLC dated May 27, 2005.
* * 10.10 Form of Stock Purchase Agreement between Blue Dolphin Energy
Company and Osler Holdings Limited, Gilbo Invest AS, Spencer
Energy AS, Spencer Finance Corp., Hudson Bay Fund, LP, Don
Fogel and SIBEX Capital Fund, Inc. dated March 8, 2006.
14.1 (10) Code of Ethics applicable to the Chairman, Chief Executive
Officer and Senior Financial Officer.
* * 21.1 List of Subsidiaries of the Company.
* * 23.1 Consent of UHY Mann Frankfort Stein & Lipp CPAs, LLP.
* * 31.1 Ivar Siem Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 302 of the Sarbanes-Oxley Act of
2002.
* * 31.2 Gregory W. Starks Certification Pursuant to 18 U.S.C. Section
1350, as adopted pursuant to section 302 of the Sarbanes-Oxley
Act of 2002.
* * 32.1 Ivar Siem Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 906 of the Sarbanes-Oxley Act of
2002.
* * 32.2 Gregory W. Starks Certification Pursuant to 18 U.S.C. Section
1350, as adopted pursuant to section 906 of the Sarbanes-Oxley
Act of 2002.
* Management Compensation Plan.
** Filed herewith.
----------
(1) Incorporated herein by reference to Exhibits filed in connection with the
definitive Proxy Statement of Blue Dolphin Energy Company under the
Securities and Exchange Act of 1934, dated October 13, 2004 (Commission
File No. 000-15905).
(2) Incorporated herein by reference to Exhibits filed in connection with Form
10-K of Blue Dolphin Energy Company for the year ended December 31, 1989
under the Securities and Exchange Act of 1934, dated March 30, 1990
(Commission File No. 000-15905).
(3) Incorporated herein by reference to Exhibits filed in connection with the
Proxy Statement of Blue Dolphin Energy Company under the Securities and
Exchange Act of 1934, dated May 18, 2000 (Commission File No. 000-15905).
(4) Incorporated herein by reference to Exhibits filed in connection with the
definitive Proxy Statement of Blue Dolphin Energy Company under the
Securities and Exchange Act of 1934, dated April 16, 2003 (Commission File
No. 000-15905).
(5) Incorporated herein by reference to Exhibits filed in connection with Form
10-KSB of Blue Dolphin Energy Company under the Securities and Exchange Act
of 1934, dated July 23, 2002 (Commission File No. 000-15905).
(6) Incorporated herein by reference to Exhibits filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated September 14, 2004 (Commission File No. 000-15905).
(7) Incorporated herein by reference to Exhibits filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated December 6, 2004 (Commission File No. 000-15905).
(8) Incorporated herein by reference to Exhibits filed in connection with Form
10-QSB of Blue Dolphin Energy Company for the quarter ended June 30, 2004
under the Securities and Exchange Act of 1934, dated August 20, 2004
(Commission File No. 000-15905)
(9) Incorporated herein by reference to Exhibits filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated March 2, 2005.
(10) Incorporated herein by reference to Exhibit 14.1 filed in connection with
Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31,
2004 under the Securities Exchange Act of 1934, dated March 25, 2005
(commission file No. 000-15905).