UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-KSB
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 2004
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from _______ to _______
Commission file Number: 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Name of small business issuer in its charter)
DELAWARE 73-1268729
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
801 TRAVIS, SUITE 2100, HOUSTON, TEXAS 77002
(Address of principal executive office) (Zip Code)
Issuer's telephone number (713) 227-7660
Securities registered pursuant to Section 12(b) of the Exchange Act: NONE
Securities registered pursuant to Section 12(g) of the Exchange Act:
COMMON STOCK, $.01 PAR VALUE
(Title of Class)
Check whether the issuer (1) filed all reports required to be filed
by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for
such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Check if there is no disclosure of delinquent filers in response to
Item 405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. [ ]
The issuer's revenues for the year ended December 31, 2004 were
$1,435,646.
The aggregate market value of the common stock, par value $.01 per
share, held by non-affiliates of the registrant as of March 14, 2005, was
approximately $11,000,000.
As of March 11, 2005, there were outstanding 6,863,689 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 2005 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, 2004, are incorporated by reference in Part III
of this report.
Transitional Small Business Disclosure Format. Yes [ ] No [X]
TABLE OF CONTENTS
PAGE
----
PART I
Item 1. Description of Business...................................................... 1
Item 2. Description of Property...................................................... 18
Item 3. Legal Proceedings............................................................ 18
Item 4. Submission of Matters to a Vote of Security Holders.......................... 18
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............................... ......................... 29
Item 8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosures..................................................... 54
Item 8A. Controls and Procedures...................................................... 54
PART III
Item 9. Directors and Executive Officers of the Registrant........................... 54
Item 10. Executive Compensation....................................................... 54
Item 11. Security Ownership of Certain Beneficial Owners and Management............... 55
Item 12. Certain Relationships and Related Transactions............................... 55
Item 13. Exhibits, Lists and Reports on Form 8-K...................................... 55
Item 14. Principal Accountant Fees and Services....................................... 57
Signatures............................................................................. 58
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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;
- 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 is a holding company that conducts
substantially all of its operations through its subsidiaries. We conduct our
business activities in two primary business segments: (i) pipeline operations,
and (ii) oil and gas exploration and production. Substantially all of our assets
consist of equity interests in our subsidiaries. Our subsidiaries and affiliates
are:
- Blue Dolphin Pipe Line Company, a Delaware corporation;
- Blue Dolphin Petroleum Company, a Delaware corporation;
- Blue Dolphin Exploration Company, a Delaware corporation;
- Blue Dolphin Services Co., a Texas corporation;
- Petroport, Inc., a Delaware corporation; and
- Drillmar, Inc., a Delaware corporation in which we own a 12.8%
interest.
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" on pages
16 through 18 of this Form 10-KSB.
RECENT DEVELOPMENTS
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
2,800,000 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 closing
of 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. The
Promissory Notes mature on September 8, 2005, and accrue interest at a rate of
12.0% per annum, of which 4% is payable monthly and 8% is payable at maturity.
The Promissory Notes are secured by a second lien on our Blue Dolphin System (as
defined in "Pipeline Operations and Activities-Blue Dolphin Pipeline System").
The Warrants are immediately exercisable and will expire five years after their
date of issuance. Each Warrant is exercisable to acquire one share of common
stock at an exercise price of $0.25 per share. The Warrants contain standard
antidilution provisions, as well as provisions that will result in adjustments
to the exercise price of the Warrants if we issue common stock at a price below
$0.25 per share, subject to certain exceptions.
In October 2004, we sold our 25% equity interest in New Avoca Gas Storage
LLC ("New Avoca") to SemGas LP. Pursuant to the terms of the Purchase and Sale
Agreement, we received approximately $930,000 for our interest in New Avoca, and
may receive an additional payment of up to approximately $375,000, subject to
the commencement of commercial operations at the New Avoca natural gas storage
facility prior to October 29, 2011.
On February 28, 2005 (effective as of January 1, 2005), we entered into an
amendment (the "Amendment") to our Asset Purchase Agreement dated February 1,
2002 (the "Purchase Agreement") with MCNIC Offshore Pipeline and Processing
Company ("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 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 50% or more of our 83%
interest in the Blue Dolphin System is sold before December 31, 2006.
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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. 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 provision of such services with third
party producer/shippers may be for specified time periods, there can be no
assurance that current or future producer/shippers will not subsequently tie-in
to alternative transportation systems or that current rates charged will be
maintained in the future. We actively market gathering and transportation
services to prospective third party producer/shippers in the vicinity of our
pipeline systems. Future utilization of the pipelines and related facilities
will depend upon the success of drilling programs around the pipelines, and the
attraction, and retention, of producer/shippers to the systems.
Blue Dolphin Pipeline System. The Blue Dolphin 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 shore 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.
Various fees are charged to producer/shippers for provision of
transportation and shore facility services. Our current aggregate capacity is
approximately 160 MMcf per day of gas and 7,000 Bbls per day of crude oil and
condensate. Gas throughput for the Blue Dolphin System averaged approximately 4%
and 6% of capacity during 2004 and 2003, respectively. All gas and liquids
volumes transported in 2004 and 2003 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 from the Blue
Dolphin System, we renegotiated our gas transportation rates with our shippers,
effective October 1, 2004. As a result, fourth quarter 2004 gas transportation
revenues from the Blue Dolphin System totaled $318,000. Without the increase in
rates, gas transportation revenues for the fourth quarter of 2004 would have
been $107,000.
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 to a transmission pipeline in Galveston Area Block 391 (the "GA 350
Pipeline"), approximately 14 miles south of the Blue Dolphin
3
Pipeline. Current system capacity on the GA 350 Pipeline is 65 MMcf per day of
gas. Gas throughput for the GA 350 Pipeline averaged approximately 26% and 17%
of capacity during 2004 and 2003, respectively. The pipeline currently
transports approximately 22 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 currently inactive
Omega Pipeline. The Omega Pipeline originates in West Cameron Block 342 and
extends to High Island Area, East Addition Block A-173, where it was previously
connected to the High Island Offshore System ("HIOS"). The line could either be
reconnected to HIOS, or a lateral pipeline could be constructed connecting into
the Black Marlin Pipeline, approximately 14 miles to the west. Reactivation of
the Omega Pipeline will be dependent upon future drilling activity in the
vicinity and successfully attracting reserves to the system.
New Avoca Gas Storage Project
We formed New Avoca with WBI Holdings, Inc. ("WBI"), and together held
assets to develop a natural gas storage project in Avoca, New York. We held a
25% equity interest and were the manager of New Avoca. Our investment in New
Avoca was recorded by using the equity method of accounting. In October 2004, we
sold our 25% interest in New Avoca. See "Recent Developments."
OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Our oil and gas assets are held by Blue Dolphin Petroleum and Blue Dolphin
Exploration. Our oil and gas exploration and production activities include the
exploration, acquisition, development, operation and, when appropriate,
disposition of oil and gas properties. We focus our oil and gas activities in
the western and central Gulf of Mexico. We currently own seismic and other data
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.
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 A-7. High Island Block A-7 is located 33 miles offshore
Texas in an average water depth of 39 feet. We own an 8.9% working interest in
this lease that covers approximately 5,760 acres. The lease contains one
producing well which is operated by Spinnaker Exploration Company. During the
years ended December 31, 2004 and 2003, we recorded revenues from oil and gas
sales of approximately $332,000 and $1,447,000, respectively, from this field.
Unproved Leasehold Interests. Our leased prospect inventory, which we
continue to market, consists of a prospect on the offshore lease for West
Cameron Area Block 212. We have after payout reversionary working interests in
the following offshore leases.
- Galveston Area Block 297
- Galveston Area Block 287
- Galveston Area Block 271
- Galveston Area Block 284
In December 2004, we placed our interest in Galveston Area Blocks 287 and
297 in the Gulf of Mexico with third parties. These blocks are part of a
prospect we generated that includes Galveston Area
4
Block 298. A well is currently being drilled in Galveston Area Block 297. As a
result of the placement of our working interest in Galveston Area Blocks 287 and
297, we expect to receive proceeds of approximately $160,000, and a 7.5% after
payout reversionary working interest.
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 (which payment the TPW required) and
$40,000 represented the cost of buoys to mark the reef sites. While the scope of
work with Tetra was changed, the contract price and payment terms remained
unchanged. Our payments to Tetra began in September 2003. 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. We reduced our provision
for the Buccaneer Field abandonment costs resulting in a gain of approximately
$.5 million for the year ended December 31, 2003. At December 31, 2004, accounts
payable includes approximately $450,000 due Tetra, payable as described above.
Sale of Oil and Gas Properties. During 2002, we sold all of our producing
oil and gas properties. From October 2002 to late April 2003, we had no interest
in any producing oil and gas properties.
In June 2004, we sold our working interest in the High Island Block 34
field for approximately $34,000 to Fidelity Exploration and Production Company.
Production from this field accounted for 4% and 2% of our total revenues for the
years ended December 31, 2004 and 2003, respectively.
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, 2004.
The quantities of proved oil and gas reserves presented below include only
those amounts which we reasonably expect to recover in the future from known oil
and gas reservoirs under existing economic and operating conditions. Therefore,
proved reserves are limited to those quantities that are believed to be
recoverable at prices and costs, and under regulatory practices and technology
existing at the time of the estimate. Accordingly, changes in oil and gas
prices, operation and development costs, regulations, technology, future
production and other factors, many of which are beyond our control, could
significantly affect the estimates of proved reserves and the discounted present
value of future net revenues attributable thereto.
Estimates of production and future net revenues cannot be expected to
represent accurately the actual production or revenues that may be recognized
with respect to oil and gas properties or the actual present market value of
such properties. For further information concerning our Proved Reserves, changes
in Proved Reserves, estimated future net revenues and costs incurred in our oil
and gas activities and the discounted present value of estimated future net
revenues from our Proved Reserves, see Note 13 Supplemental Oil and Gas
Information to Consolidated Financial Statements included in Item 7.
5
The following table presents the estimates of Proved Reserves, Proved
Developed Reserves, and Proved Undeveloped Reserves (as hereinafter defined),
future net revenues and the discounted present value of future net revenues from
Proved Reserves before income taxes to our net interest in oil and gas
properties as of December 31, 2004. 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, 2004 (1)(2)
Present Value of
Future Net Cash Future Net Cash
Net Oil Net Gas outflows Before Outflows Before
Reserves Reserves Income Taxes Income Taxes (1)
(Mbbls) (Mmcf) (in thousands) (in thousands)
-------- -------- --------------- -----------------
Total Proved Reserves
High Island Block A-7 .4 35.3 $ (54) $ (18)
Total Proved Developed
High Island Block A-7 .4 35.3 $ (54) $ (18)
-----------------------
(1) The estimated present value of future net cash outflows before income
taxes from our Proved Reserves have been determined by using prices of
$43.22 per barrel of oil and $7.22 per Mcf of gas, representing the
December 31, 2004 prices for oil and gas and discounted at a 10% annual
rate in accordance with requirements for reporting oil and gas reserves
pursuant to regulations promulgated by the United States Securities and
Exchange Commission (the "SEC Method"). At December 31, 2004, the value of
our reserves is negative as a result of asset retirement obligations
exceeding future revenues.
(2) As of December 31, 2004, 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.
Estimated Undiscounted Capital Expenditures
To Develop Proved Reserves
For the years ending December 31,
(in thousands)
--------------------------------------------
2005 2006 2007 2008 2009
---- ---- ------ ---- ----
High Island Block A-7 $ 13 - $ 203 - -
We will continue to evaluate our capital expenditure program based on,
among other things, demand and prices obtainable for our production. The
availability of capital resources and the willingness of other working interest
owners to participate in development operations may affect our timing for
further development, and there can be no assurance that the timing of the
development of such reserves will be as currently planned.
6
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,
----------------------------------------------
2004 2003 2002
------------ ------------ ------------
Gas:
Production (Mcf) 66,491 274,268 418,895
Revenue $ 367,611 $ 1,513,182 $ 1,221,168
Average Production (Mcf) per day (*) 182.20 751.40 1,147.70
Average Sales Price
Per Mcf $ 5.53 $ 5.52 $ 2.92
Oil:
Production (Bbls) 810 2,271 28,230
Revenue $ 28,089 $ 68,872 $ 560,790
Average Production (Bbls) per day (*) 2.20 6.20 77.30
Average Sales Price
Per Bbl $ 34.68 $ 30.33 $ 19.87
Production Costs (**):
Per Mcfe: $ 1.88 $ 0.65 $ 0.88
-------------------------
(*) Average production is based on a 365 day year. However, we only had
production for 255 days and 304 days in 2003 and 2002, respectively.
(**) Production costs, exclusive of workover costs, are costs incurred to
operate and maintain wells and equipment and to pay production taxes.
Drilling Activity. During fiscal years 2004 and 2003 there was no drilling
activity.
EMPLOYEES
We maintain a professional staff of 7 full-time employees and consultants
capable of supervising and coordinating the operation and administration of our
oil and gas properties and pipeline and other assets. From time to time, major
maintenance, engineering and construction projects are contracted to third-party
engineering and service companies.
CUSTOMERS
We generated revenues from both of our primary business segments. Revenues
from major customers exceeding 10% of revenues were as follows for 2004 and
2003:
7
Oil and gas Pipeline
Sales Operations Total
----------- ---------- -----------
Year ended December 31, 2004:
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
Year ended December 31, 2003:
Spinnaker Exploration Company $ 1,446,622 - $ 1,446,622
COMPETITION
The oil and gas industry is highly competitive in all segments.
Increasingly vigorous competition occurs among oil, gas and other energy
sources, and between producers, transporters, and distributors of oil and gas.
Competition is particularly intense with respect to the acquisition of desirable
mid-stream assets, producing oil and gas properties and the marketing of oil and
gas production. 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
- the availability of vessels for direct shipment
- lightering and transshipment and other means of transportation
- the availability and marketing of other competitive fuels
- fluctuating and seasonal demand for oil, gas and refined products
- 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,
and the development of storage of gas by us are subject to federal, state and
local regulations which can have a significant impact upon our overall
operations.
8
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. Congress
could, however, 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.
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 nonjurisdictional gathering lines, as well as interstate pipelines,
are fully subject to the open access and nondiscrimination requirements of
OCSLA's Section 5, which generally authorizes the FERC to insure that gas
pipelines on the Outer Continental Shelf ("OCS") will transport for non-owner
shippers in a nondiscriminatory manner and will be operated in accordance with
certain pro-competitive principles.
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 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 standardize terms and require compliance with detailed
9
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 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
10
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 impact of such a change is not
expected to be any more burdensome on us than on others similarly situated.
The Clean Air Act and state air quality laws and regulations contain
provisions that impose pollution control requirements on emissions to the air
and require permits for construction and operation of certain emissions sources,
including sources located offshore. We may be required to incur capital
expenditures for air pollution control equipment in connection with maintaining
or obtaining operating permits and approvals addressing emission-related issues,
although we do not expect to be materially adversely affected by such
expenditures.
The Clean Water Act ("CWA") regulates the discharge of pollutants to
waters of the United States and imposes permit requirements on such discharges,
including discharges to wetlands. Federal regulations under the CWA and OPA
require certain owners or operators of facilities that store or otherwise handle
oil, to prepare and implement spill prevention, control and countermeasure plans
and facility response plans relating to the possible discharge of oil into
surface waters. With respect to certain of our operations, we are required to
prepare and comply with such plans and to obtain and comply with permits. The
CWA also prohibits spills of oil and hazardous substances to waters of the
United States in excess of levels set by regulations and imposes liability in
the event of a spill. State laws further provide varying civil and criminal
penalties and liabilities for the spills to both surface and groundwaters. We
believe we are in substantial compliance with the requirements of the CWA, OPA,
and state laws, and that any non-compliance would not have a material adverse
effect on us.
Various federal and state programs regulate the conservation and
development of coastal resources. The federal Coastal Zone Management Act was
passed to preserve and, where possible, restore the natural resources of the
Nation's coastal zone and to provide for federal grants for state management
programs that regulate land use, water use and coastal development. Under the
Louisiana Coastal Zone Management
11
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 near future to expend amounts that are material relative to
our total capital structure. However, it is possible that the costs of
compliance with environmental and health and safety laws and regulations will
continue to increase. Given the frequent changes made to environmental and
health and safety regulations and laws, we are unable to predict the ultimate
cost of compliance.
RISK FACTORS
We need to raise additional capital to meet our obligations during 2005. Our
capital requirements raise substantial doubt about our ability to continue as a
going concern.
During 2005, we have various debt obligations to satisfy along with
continued losses from operations that are currently expected to exceed our
available cash. These obligations include approximately $450,000 due to Tetra
during January through August 2005, $130,000 due to MCNIC during February
through December 2005, and, our promissory notes in the principal amount of
$750,000, along with accrued interest of approximately $60,000 due and payable
in September 2005.
In order to satisfy our debt and other working capital and capital
expenditure requirements for the year ending December 31, 2005, we believe that
we will need to raise approximately $500,000 of capital. In the absence of an
improvement in our operating results, we will need to either extend the payment
terms of our promissory notes, arrange external financing and/or sell assets to
raise the necessary capital.
Historically, we have relied on the proceeds from the sale of assets and
capital raised from the issuance of debt and equity securities to individual
investors and related parties to sustain our operations. There can be no
assurance that we will be able to obtain financing or sell assets on
commercially acceptable
12
terms to meet our capital requirements. Our inability to raise capital will have
a material adverse effect on our financial condition, ability to meet our
obligations and operating needs, and results of operations.
We are primarily dependent on revenues from our pipeline systems.
As a result of our sale of substantially all of our proved oil and gas
reserves in 2002 and the limited remaining reserves that were added in 2003, our
future revenues are primarily dependent on the level of use of our pipeline
systems. Various factors will influence the level of use of our pipeline systems
including the amount of oil and gas production near our pipelines and our
ability to attract new users. There are various competing pipelines in and
around our pipeline systems that we vigorously compete with to attract new users
to our pipeline systems. There can be no assurance that our marketing activities
will result in attracting new oil and gas reserves to our pipeline systems.
Our future success depends, in part, upon our ability to acquire mid-stream
(pipeline) assets and oil and gas reserves.
We are currently attempting to find and acquire mid-stream assets. Until
we acquire additional mid-stream assets, substantially all of our revenues will
be from our existing pipeline systems and reversionary interests in oil and gas
properties. There can be no assurance that we will be able to acquire additional
assets.
We face strong competition from larger companies that may negatively affect our
ability to carry on operations.
We operate in a highly competitive industry. Our competitors include major
integrated oil companies, substantial independent energy companies, affiliates
of major interstate and intrastate pipelines and national and local gas
gatherers, many of which possess greater financial and other resources than we
do. Our ability to successfully compete in the marketplace is affected by many
factors.
- Most of our competitors have greater financial resources than
we do, which gives them better access to capital to acquire
assets.
- We often establish a higher standard for the minimum projected
rate of return on an investment than some of our competitors
since we cannot afford to absorb certain risks. We believe
this puts us at a competitive disadvantage in acquiring
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, the 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;
13
- 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.
We cannot control the activities on properties we do not operate.
Currently, other companies operate or control all 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, could adversely affect us, including the amount and
timing of revenues, if any, we receive from our interests.
We have and generally anticipate that we will typically own substantially
less than a 50% working interest in our prospects and will therefore engage in
joint operations with other working interest owners. 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 more than a majority of the working
interest. For instance, if we are unwilling or unable to participate in the
costs of operations approved by a majority of the working interests in a well,
our working interest in the well (and possibly other wells on the prospect) will
likely be subject to contractual "non-consent penalties". These penalties may
include, for example, full or partial forfeiture of our interest in the well or
a relinquishment of our interest in production from the well in favor of the
participating working interest owners until the participating working interest
owners have recovered a multiple of the costs which would have been borne by us
if we had elected to participate, which often ranges from 400% to 600% of such
costs.
We have pursued, and intend to continue to pursue, acquisitions. Our business
may be adversely affected if we cannot effectively integrate acquired
operations.
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;
14
- 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 risks inherent in the oil and gas industry,
such as:
- 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.
These risks could result in substantial losses to us from injury and loss
of life, damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. Our offshore operations
are also subject to a variety of operating risks peculiar to the marine
environment, such as hurricanes or other adverse weather conditions and more
extensive governmental regulation. These regulations may, in certain
circumstances, impose strict liability for pollution damage or result in the
interruption or termination of operations.
Losses and liabilities from uninsured or underinsured drilling and operating
activities could have a material adverse effect on our financial condition and
results of operations.
We maintain several types of insurance to cover our operations, including
maritime employer's liability and comprehensive general liability. Amounts over
base coverages are provided by primary and excess umbrella liability policies
with maximum limits of $50 million. We also maintain operator's extra expense
coverage, which covers the control of drilled or producing wells as well as
redrilling expenses and pollution coverage for wells out of control.
We may not be able to maintain adequate insurance in the future at rates
we consider reasonable or losses may exceed the maximum limits under our
insurance policies. In 2004, as a result of our operating losses, we cancelled
the property insurance coverage on our pipelines, however we do continue to
carry property insurance coverage on our shore facilities and our offshore
platforms. 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.
15
Compliance with environmental and other government regulations could be costly
and could negatively impact pipeline and production 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 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.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used
in the oil and gas industry.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
BCF. One billion cubic feet of gas.
BTU OR BRITISH THERMAL UNIT. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
CONDENSATE. Liquid hydrocarbons associated with the production of a
primarily gas reserve.
16
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.
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.
17
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. One of our Directors, Mr. James M. Trimble, was the
Chairman and Chief Executive Officer of TexCal Energy (GP) LLC until November
2004.
We have month to month contracts with several companies, including
Drillmar, Inc. (see Note 9 in Item 7 of the Consolidated Financial Statements)
to use our extra office space. Monthly proceeds from these contracts is
approximately $6,000.
ITEM 3. LEGAL PROCEEDINGS
Neither we nor any of our property is subject to any material pending
legal proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
A special meeting of stockholders was held on November 11, 2004. The
matters that were voted on at the meeting, and the number of votes cast for,
against or withheld, as well as the number of abstentions and broker non-votes,
as to such matter, where applicable, are set forth below.
18
Votes Votes Votes Broker
For Against Withheld Abstentions Non-Votes
--------- ------- -------- ----------- ---------
1)Election of Directors
Ivar Siem 4,586,747 17,914 23,178 - 1,389,523
Laurence N. Benz 4,603,472 1,189 23,178 - 1,389,523
Michael S. Chadwick 4,603,472 1,189 23,178 - 1,389,523
Harris A. Kaffie 4,603,400 1,261 23,178 - 1,389,523
F. Gardner Parker 4,603,472 1,189 23,178 - 1,389,523
James M. Trimble 4,602,272 2,389 23,178 - 1,389,523
2) To issue warrants to
purchase up to 1,550,000
shares of common stock
pursuant to that certain
Note and Warrant Purchase
Agreement: 3,666,698 52,670 3,444 - 1,389,523
3) To amend and restate the
Certificate of Incorporation
to increase the number of
authorized shares of common
stock to 25,000,000 shares: 4,564,929 59,137 3,773 - 1,389,523
4) To amend and restate the
Certificate of Incorporation
to (a) incorporate the other
Amendments to the
Certificate that have been,
or will be, approved by the
stockholders and (b) to
eliminate the authorized
Series A preferred stock: 3,666,652 53,945 2,215 - 1,389,523
5) To issue warrants to
purchase up to 100,000
shares of common stock to
Laurence N. Benz, Michael S.
Chadwick and F. Gardner Parker: 3,666,404 55,167 1,241 - 1,389,523
19
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 14, 2005, there were an estimated 600 stockholders of record
and we estimate there are more than 1,000 beneficial owners of our common stock.
NASDAQ quotations reflect inter-dealer prices, without adjustment for retail
mark-ups, markdowns or commissions and may not represent actual transactions.
The following table sets forth, for the periods indicated, the high and low bid
price for the common stock as reported by the NASDAQ.
High Low
------ ------
Quarter Ended March 31, 2003............ $ 0.63 $ 0.41
Quarter Ended June 30, 2003............. $ 1.85 $ 0.38
Quarter Ended September 30, 2003........ $ 4.00 $ 0.75
Quarter Ended December 31, 2003......... $ 3.20 $ 1.65
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
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 have 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, our loan agreement
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 September 2004, we sold Promissory Notes in an aggregate principal
amount of $750,000 and 1,250,000 Warrants, and in November 2004 we sold
1,550,000 Warrants. These securities are more fully described in Item 6
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
20
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 operations and (ii)
oil and gas exploration and production. We conduct our operations through our
subsidiaries. We provide pipeline transportation services to producer/shippers,
and sell oil and gas from a producing property. Our assets are located offshore
and onshore in the Texas Gulf coast area. In addition to satisfying our
liquidity and capital needs, our focus in 2005 is to increase utilization of
existing assets, strategic acquisitions and cost management. Our long-term goal
is to create greater value for our stockholders through the addition of assets.
Our focus on acquisitions has centered on pipelines, however, producing oil and
gas properties are also being considered.
At the beginning of 2004 we faced a significant liquidity shortage. We
estimated that we would need to raise approximately $1,500,000 to satisfy our
liquidity and working capital requirements through 2004. In an effort to address
our current liquidity shortage we:
- Implemented cost savings measures in mid 2004 that included,
among other things, reducing the number of employees and
contract personnel, resulting in expected annual cost savings
of approximately $360,000. As a result of these measures, our
primary focus was shifted to our pipeline business,
- Extended the payment terms of $668,000 of indebtedness that
was due in August and September 2004, to now be payable over a
twelve month period from September 2004 through August 2005,
- Received borrowings of $750,000 through the issuance of
Promissory Notes,
- Sold our interest in New Avoca Gas Storage, LLC for
approximately $930,000 in October 2004. New Avoca was a
development project that required significant additional
capital to develop which we planned to suspend if not sold by
the end of 2004, and
- Negotiated an increase in gas transportation rates on the Blue
Dolphin System effective October 2004, that provided
additional revenues of approximately $210,000 in the fourth
quarter 2004.
In 2004, we engaged Sanders Morris Harris Group, Inc. and Amerifund
Capital Group, LLC as financial advisors to assist us in raising capital and
seeking strategic acquisitions. So far in 2005, we have renegotiated the terms
of a $750,000 promissory note due December 31, 2006 to MCNIC, originally bearing
interest at 6% per annum, whereby under the new terms the note is non-interest
bearing, in the principal amount of $250,000. In addition, all accrued interest
on this promissory note was forgiven. Principal payments to be made in 2005
total $130,000.
As a result of these and other actions taken in 2004, we ended 2004 with
working capital of approximately $400,000. However, due to our continuing losses
from operations and debt service and other contractual obligations due in 2005,
of approximately $1,465,000, we estimate that we will need to raise additional
capital of approximately $500,000 to satisfy our obligations in 2005. Our
inability to raise capital may have a material adverse effect on our financial
condition, ability to meet our obligations and operating needs, and results of
operations. As a result of our ongoing liquidity problems, our auditors UHY Mann
Frankfort Stein & Lipp CPAs, LLP added an explanatory paragraph in their opinion
on our consolidated
21
financial statements as of the year ended December 31, 2004, indicating that
substantial doubt exists about our ability to continue as a going concern. See
Note 2 in Item 7 of the Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
Although we were able to implement certain cost savings measures and
restructure the terms of some of our indebtedness we were not able to generate
sufficient cash from operations to cover operating and general and
administrative expenses. Furthermore, our financial condition has been
significantly and negatively affected by the poor performance of our businesses
and our significant indebtedness. For the year ended December 31, 2004, we
generated total revenues of approximately $1.4 million while operating costs and
general administrative costs, excluding certain non-cash compensation expense,
totaled approximately $2.8 million.
In August 2004, we extended the remaining payments totaling $668,000 due
in September and October 2004 to Tetra for the abandonment/reefing of the
Buccaneer Field. Under the revised terms, we will pay Tetra the outstanding
balance in twelve monthly installments of $55,667 beginning September 1, 2004,
plus interest on the outstanding balance at the rate of six percent per annum.
As of December 31, 2004, the remaining balance due Tetra was approximately
$450,000.
On September 8, 2004, we entered into 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 and 2,800,000
Warrants to purchase shares of our common stock at a purchase price of $0.003
per Warrant. The sale of the Promissory Notes and the first tranche of 1,250,000
Initial Warrants closed on September 8, 2004, and the closing of the sale of the
second tranche of 1,550,000 Additional Warrants closed on November 30, 2004
after we received stockholder approval of the issuance of the Additional
Warrants at our November 11, 2004 special stockholders meeting. We received
proceeds of $758,400 from the issuance of the Promissory Notes and the Warrants.
The Promissory Notes mature on September 8, 2005, and accrue interest at a rate
of 12.0% per annum, of which 4% is payable monthly and 8% is payable at
maturity. The Warrants have an exercise price of twenty five cents per share and
a term of five years.
In October 2004, we sold our 25% equity interest in New Avoca. Pursuant to
the terms of a Purchase and Sale Agreement, we received approximately $930,000
for our interest in New Avoca, and may receive an additional payment of up to
approximately $375,000, subject to the commencement of commercial operations at
the New Avoca natural gas storage facility prior to October 29, 2011. The
proceeds from the sale of our interest in New Avoca will be used for general
corporate purposes.
The current poor performance of our existing assets combined with the
capital requirements inherent in our business raise substantial doubt about our
ability to continue as a going concern. Our long-term viability as a going
concern is dependent upon the following factors:
- our ability to raise capital to meet current commitments and
obligations, and fund the continuation of our business operations;
and
- our ability to ultimately achieve profitability and cash flows from
operations in amounts that will sustain our operations through our
existing assets and acquisition of other assets.
22
The following table summarizes our contractual obligations and other
commercial commitments at December 31, 2004 (amounts in thousands):
Payments Due by Period
--------------------------------------------------
Contractual 1 year After
Obligations Total or less 1-3 years 3-5 years 5 years
----------- ---------- ------- --------- --------- -------
Accounts Payable - Tetra $ 445 445 - - -
Notes Payable and Long-Term Debt 1,651 900 751 - -
Operating Leases, net of sublease 237 120 117 - -
---------- ----- --- -- --
Total Contractual Obligations $ 2,333 1,465 868 - -
========== ===== === == ==
Amount of Commitment Expiration Per Period
--------------------------------------------------
Other Commercial 1 year After
Commitments Total or less 1-3 years 3-5 years 5 years
---------------- ---------- ------- --------- --------- -------
Abandonment - Costs $ 1,622 - 188 - 1,434
---------- -- --- -- -----
Total Commercial Obligations $ 1,622 - 188 - 1,434
========== == === == =====
The following table summarizes our financial position for the periods indicated:
December 31,
(amounts in thousands)
2004 2003
----------------- ----------------
Amount % Amount %
---------- --- --------- ---
Working Capital $ 404 7 $ 680 9
Property and equipment, net 5,324 93 5,775 79
Other noncurrent assets 11 0 848 12
---------- --- --------- ---
Total $ 5,739 100 $ 7,303 100
========== === ========= ===
Long-term Liabilities $ 2,374 41 $ 2,302 32
Stockholders' equity 3,365 59 5,001 68
---------- --- --------- ---
Total $ 5,739 100 $ 7,303 100
========== === ========= ===
The change in our financial position from December 31, 2003 to December
31, 2004, was primarily due to our net loss from operations for the year ended
December 31, 2004 of approximately $2,500,000, the issuance of $750,000 in
promissory notes and the sale of New Avoca for approximately $930,000.
The net cash provided by or used in operating, investing and financing
activities is summarized below:
23
Years Ended December 31
--------------------------
(amounts in thousands)
2004 2003
------------- -----------
Net cash provided by (used in):
Operating activities $ (2,603) $ (1,365)
Investing activities 875 (338)
Financing activites 586 -
------------- -----------
Net decrease in cash $ (1,142) $ (1,703)
============= ===========
For the year ended December 31, 2003, we generated $1.4 million of revenue
from the sale of oil and gas production from the High Island Block A-7 field,
representing approximately 57% of our revenues for that period. Oil and gas
production from the High Island Block A-7 field declined significantly for the
year ended December 31, 2004. Our revenues from the sale of oil and gas
production from the High Island Block A-7 field decreased approximately 76% in
2004 to $332,000, which accounted for approximately 23% of our revenues for that
period. As a result of the decline in production from this field, we expect that
a significant portion of our revenues in 2005 will continue to be derived from
utilization of our pipeline systems. To increase operating results, we must
increase our pipeline revenues and/or acquire additional income generating
assets.
From October 2002 to late April 2003, we had no interest in any producing
oil and gas properties. In late April 2003, we began to receive revenue from our
8.9% reversionary working interest in the High Island Block A-7 field, in the
Gulf of Mexico. See "Sale of Oil and Gas Properties" and "High Island Block A-7"
in Item 1. This field currently produces at a gross rate of 0.8 MMcf/day.
During 2004, we incurred no capital expenditures for the development of
our proved reserves. The reserves and future net revenues presented in Item 1
"Description of Business" reflect projected capital expenditures totaling
$13,000 and $203,000 in the years ending December 31, 2005 and 2007,
respectively. Capital expenditures in 2005 represent workover costs, net to our
interest for the producing well in the High Island Block A-7 field and in 2007
the abandonment costs of our High Island Block A-7 field, net to our interest.
We have significant available capacity in our Blue Dolphin System in a
market area that we believe is experiencing an increased level of interest by
oil and gas operators. Natural gas transportation throughput on our Blue Dolphin
System is currently 7 MMBtu per day representing 4% of system capacity.
Effective October 1, 2004, we renegotiated the gas transportation rates on the
Blue Dolphin System due to losses incurred from operating the system. As a
result, fourth quarter 2004 gas transportation revenues from the Blue Dolphin
System totaled approximately $318,000. Without the increased gas transportation
rates, revenues would have been approximately $107,000, for this same period.
Future utilization of our pipelines and related facilities will depend upon the
success of drilling programs around our pipeline systems, and attraction and
retention of producer/shippers to the systems. As a result of current and
anticipated drilling activity around the Blue Dolphin System, we expect that
utilization of the Blue Dolphin System will increase in late 2005.
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. In addition to the New Promissory Note, MCNIC
can receive additional payments of up to $500,000 from 50%
24
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.
RESULTS OF OPERATIONS
For the year ended December 31, 2004 ("2004"), we reported a net loss of
$2.5 million, compared to a net loss of $793,050 for the year ended December 31,
2003 ("2003").
2004 compared to 2003
Revenue from pipeline operations. Revenues from pipeline operations
increased by $79,377 or 8% in 2004 to $1,014,137. The increase is due to
increased volumes from new wells tied into our GA 350 Pipeline in mid 2004.
Average daily gross gas volumes transported on the GA 350 Pipeline increased
from 10.7 Mmcf per day in 2003 to 16.5 Mmcf per day in 2004, resulting in an
increase in revenues from $257,000 in 2003 to $351,000 in 2004. The increase in
pipeline revenues from the GA 350 Pipeline was offset in part by a 34% decrease
in volumes transported on the Blue Dolphin System in 2004 from those of 2003.
Revenues in 2004 from the Blue Dolphin System totaled $663,000 compared to
$678,000 in 2003. As a result of net operating losses incurred from the
operation of the Blue Dolphin System, we negotiated an increase in our average
gas transportation rates on the Blue Dolphin System effective 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 October 2004. If the increased gas transportation rates
would have been in effect on January 1, 2004, pipeline transportation revenues
would have increased by approximately $640,000. However, there can be no
assurance that volumes transported in 2005 will be at the same level as in 2004.
Revenue from oil and gas sales. Revenues from oil and gas sales decreased
by $1,186,354 in 2004 from $1,582,054 in 2003, primarily due to a significant
production decline in the High Island Block A-7 field. The High Island Block A-7
field provided revenues from oil and gas sales of approximately $332,000 in 2004
compared to approximately $1.4 million in 2003. We expect that production from
the reservoir currently producing will cease in mid 2005, however there is an
additional reservoir in which a recompletion in the existing well is possible.
Oil and gas sales from this additional reservoir are not expected to
significantly increase our total revenues in 2005. Oil and gas sales in 2004
include approximately $64,000 from our interest in the High Island Block 34
field, which we sold in June 2004, compared to $61,000 recorded in 2003.
Gain on sale of oil and gas property. In June 2004 we recorded a gain on
sale of oil and gas property representing a gain of $25,809 recognized from the
sale of our interest in the High Island Block 34 field.
Pipeline operating expenses. Pipeline operating expenses in 2004 decreased
by $120,064 from $1,198,729 in 2003. Cost reductions implemented during 2003
resulted in lower expenses in 2004 of approximately $104,000. Insurance costs in
2004 decreased by $67,000 due to the elimination of property insurance coverage
on our pipelines, offset in part by higher costs associated with our other
insurance. Our elimination of property insurance coverage is consistent with
trends in the pipeline industry. Since the elimination of the property insurance
occurred in mid 2004, we expect that pipeline operating expenses will decrease
in 2005 as a result of lower insurance costs for 2005 to be lower. The above
cost reductions were offset in part by an increase in repair and maintenance
costs of $75,000 in 2004. Legal costs incurred in 2004 associated with an action
filed against us, the outcome of which we do not believe will have a material
25
impact, decreased by $24,000. However, as this litigation continues we incur
significant legal expenses, which could have a material adverse effect on our
financial condition.
Lease operating expenses. Lease operating expenses for 2004 decreased by
$52,343 from $186,656 in 2003 primarily due to a well that stopped producing in
the High Island Block A-7 field in early 2004.
Depletion, depreciation and amortization expense. Depletion, depreciation
and amortization expense decreased by $55,286 in 2004 from $488,052 in 2003. In
2004, we recorded depletion of approximately $88,000 associated with our oil and
gas properties compared to depletion of approximately $146,000 recorded in 2003.
The decrease in depletion was a result of there being no significant remaining
unamortized oil and gas costs as of mid 2004.
Impairment of assets. In 2004 there were no impairment of assets recorded.
In 2003, we recorded a partial impairment of our oil and gas properties of
approximately $89,000, due to the decline in proved reserves from our interest
in the High Island Block A-7 field.
General and administrative. General and administrative expenses increased
by $701,908 from $1,685,693 in 2003. The increase was due to a one time,
non-cash compensation expense recorded in 2004 of $818,000 of which $694,000 is
associated with the issuance of Warrants to certain of our directors and
$124,000 is associated with the issuance of shares of common stock to our 401k
plan. The increase was partially offset by lower personnel and other costs as a
result of our cost reduction plans in 2003 and 2004. The 2004 cost reductions
included the termination of certain employees in mid 2004. The annual cost
savings associated with measures taken is expected to be approximately $360,000.
As a result, 2005 general and administrative expenses are expected to be lower.
However, if our business activities expand, we will need to hire additional
employees and personnel and associated costs may increase.
Interest and other expense. Interest and other expense increased $291,926
in 2004. Interest and other expenses in 2004 includes legal and other fees of
approximately $200,000 associated with a proposed financing transaction that was
not consummated, the amortization of costs associated with the Purchase
Agreement of approximately $120,000 and interest expense on our Promissory Notes
and other debt of $85,000. Other expense in 2003 includes costs associated with
capital funding activities of $65,000 and interest expense on a promissory note
of $45,000. In 2005, the previously recorded interest expense associated with
the MCNIC promissory note has been eliminated, however this decrease will be
offset by the increase in interest expense associated with the issuance of
$750,000 aggregate principal amount of Promissory Notes issued in September
2004.
Gain on sale of assets. 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
$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 decreased $339,115 in
2004 from 2003. Other income in 2004 includes the collection of accounts
receivable that were previously written off of $165,000, and consulting services
provided by us, associated with the evaluation of oil and gas properties, of
$110,000. Other income in 2003 included a $500,000 gain resulting from a
reduction in our provision for the Buccaneer Field abandonment costs, and
consulting services we provided, associated with the evaluation of oil and gas
properties, of approximately $104,000. We do not expect to receive revenues from
consulting services in 2005, as we did in 2004 and 2003. However, in March, 2005
we received the remaining balance of the accounts receivable that were
previously written off of approximately $45,000 from Drillmar.
Cumulative effect of a change in accounting principle. In 2003, as a
result of our adoption of Statement of Financial Accounting Standards (SFAS) No.
143, we recorded a cumulative effect adjustment at January 1, 2003 of a change
in accounting principle for asset retirement obligations of $40,455 (see Note 1
in Item 7 of the Consolidated Financial Statements). There was no adjustment for
changes in accounting
26
principals recorded in 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, 2004 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 impairmaent 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, 2004. Accordingly, we developed future cash flows as of December
31, 2004 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,
2004.
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 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.
27
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS AND ACCOUNTING DEVELOPMENTS
In July 2003, an issue was brought before the FASB regarding whether or
not contract-based oil and gas mineral rights held by lease or contract
("mineral rights") should be recorded or disclosed as intangible assets. The
issue presents a view that these mineral rights are intangible assets as defined
in SFAS No. 141, "Business Combinations," and, therefore, should be classified
separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No.
142, "Goodwill and Other Intangible Assets," became effective for transactions
subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142
required as of January 1, 2002. SFAS No. 141 requires that all business
combinations initiated after June 30, 2001 be accounted for using the purchase
method and that intangible assets be disaggregated and reported separately from
goodwill. SFAS No. 142 established new accounting guidelines for both finite
lived intangible assets and indefinite lived intangible assets. Under the
statements, intangible assets should be separately reported on the face of the
balance sheet and accompanied by disclosure in the notes to financial
statements. SFAS No. 142 does not apply to accounting utilized by the oil and
gas industry as prescribed by SFAS No. 19, and is silent about whether or not
its disclosure provisions apply to oil and gas companies.
In September 2004, the FASB posted FASB staff position ("FSP") SFAS 142-2,
"Application of SFAS 142 to Oil and Gas Producing Entities." The FSP clarifies
that the exception in paragraph 8(b) of SFAS No. 142, "Goodwill and Other
Intangible Assets," includes the balance sheet classification and disclosures
for drilling and mineral rights of oil and gas producing entities. Accordingly,
the FASB staff believes that the scope exception extends to the disclosure
provisions of SFAS No. 142 for drilling and mineral rights of oil and gas
producing entities. SFAS 142-2 is effective for the first reporting period after
September 2, 2004. The FSP had no impact on our financial position, results of
operations or cash flows.
In December, 2004, the FASB issued SFAS No. 123R, "Share-Based Payment,"
that addresses the accounting for share-based payment transactions in which a
company receives employee services in exchange for equity instruments of the
company, such as stock options and restricted stock. SFAS No. 123R eliminates
the ability to account for share-based compensation transactions using APB
Opinion No. 25 and requires instead that such transactions be accounted for
using a fair value-based method. We currently account for stock-based
compensation using the intrinsic method pursuant to APB Opinion No. 25. SFAS No.
123R requires that all stock-based payments to employees, including grants of
employee stock options and restricted stock, be recognized as compensation
expense in the financial statements based on their fair values. Public entities
that file as small business issuers will be required to apply Statement 123R in
the first interim or annual reporting period that begins after December 15,
2005. Accordingly, we will be required to apply SFAS No. 123R beginning in the
fiscal quarter ending March 31, 2006. We are currently assessing the provisions
of SFAS No. 123R and its impact on our consolidated financial statements.
28
ITEM 7 FINANCIAL STATEMENTS
Index to Financial Statements: Page
----
Report of Independent Registered Public Accounting Firm................ 30
Consolidated Balance Sheet, at December 31, 2004....................... 31
Consolidated Statements of Operations, for the years
ended December 31, 2004 and 2003............................... 33
Consolidated Statements of Stockholders' Equity, for the
years ended December 31, 2004 and 2003......................... 34
Consolidated Statements of Cash Flows, for the years
ended December 31, 2004 and 2003............................... 35
Notes to Consolidated Financial Statements............................. 37
29
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, 2004, 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, 2004.
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, 2004, and the
consolidated results of their operations and their cash flows for each of the
years in the two-year period ended December 31, 2004 in conformity with
accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 2 to the
consolidated financial statements, the Company has incurred net losses and
negative cash flows from operations in recent years and has projected a cash
deficit for 2005. Those conditions raise substantial doubt about the Company's
ability to continue as a going concern. Management's plans in regard to those
matters are described in Note 2. The consolidated financial statements do not
include any adjustments that might result from the outcome of this uncertainty.
As discussed in Note 1, the Company adopted the provisions of SFAS No. 143,
"Accounting for Asset Retirement Obligations," as of January 1, 2003.
/s/ UHY Mann Frankfort Stein & Lipp CPAs, LLP
Houston, Texas
March 9, 2005
30
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 2004
Assets
Current assets:
Cash and cash equivalents $1,560,549
Accounts receivable 314,759
Related party receivable 1,605
Prepaid expenses and other assets 191,394
----------
Total current assets 2,068,307
Property and equipment, at cost:
Oil and gas properties, including $177,589
of unproved leasehold cost (full-cost method) 517,210
Pipelines 4,547,362
Onshore separation and handling facilities 1,664,128
Land 860,275
Other property and equipment 253,758
----------
7,842,733
Less accumulated depletion, depreciation,
amortization, and impairment 2,518,932
----------
5,323,801
Other assets 11,359
----------
$7,403,467
==========
See accompanying notes to consolidated financial statements.
31
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET, CONTINUED
December 31, 2004
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 740,907
Notes payable 750,000
Current portion of long-term debt 130,000
Accrued expenses and other liabilities 43,861
------------
Total current liabilities 1,664,768
Long-term liabilities:
Long-term debt 620,000
Interest payable 132,368
Asset retirement obligations 1,621,729
------------
Total long-term liabilities 2,374,097
Stockholders' equity:
Common stock, $.01 par value, 10,000,000 shares
authorized and 6,863,689 shares issued
and outstanding 68,637
Additional paid-in capital 27,129,162
Accumulated deficit (23,833,197)
------------
Total stockholders' equity 3,364,602
------------
$ 7,403,467
============
See accompanying notes to consolidated financial statements.
32
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31, 2004 and 2003
2004 2003
------------ ------------
Revenue from operations:
Pipeline operations $ 1,014,137 $ 934,760
Oil and gas sales 395,700 1,582,054
Gain on sale of oil and gas property 25,809 -
------------ ------------
Revenue from operations 1,435,646 2,516,814
Cost of operations:
Pipeline operating expenses 1,078,665 1,198,729
Lease operating expenses 134,313 186,656
Depletion, depreciation and amortization 432,766 488,052
Impairment of assets - 88,819
General and administrative expenses 2,387,601 1,685,693
Accretion expense 96,542 80,428
------------ ------------
Cost of operations 4,129,887 3,728,377
------------ ------------
Loss from operations (2,694,241) (1,211,563)
Other income (expense):
Interest and other expense (426,973) (135,047)
Gain on sale of assets 371,340 -
Interest and other income 345,656 684,771
Equity in losses of affiliate (96,116) (90,764)
------------ ------------
Loss before income taxes (2,500,334) (752,603)
Income tax expense - -
------------ ------------
Loss before cumulative effect of change
in accounting principle (2,500,334) (752,603)
Cumulative effect of a change in accounting principle
for asset retirement obligations - (40,455)
------------ ------------
Net loss $ (2,500,334) $ (793,058)
============ ============
Loss per common share-basic
Loss before accounting change $ (0.37) $ (0.11)
============ ============
Cumulative effect of a change in accounting principle $ - $ (0.01)
============ ============
Net loss $ (0.37) $ (0.12)
============ ============
Loss per common share-diluted
Loss before accounting change $ (0.37) $ (0.11)
============ ============
Cumulative effect of a change in accounting principle $ - $ (0.01)
============ ============
Net loss $ (0.37) $ (0.12)
============ ============
Weighted average number of common shares
- basic 6,734,395 6,640,285
============ ============
- diluted 6,734,395 6,640,285
============ ============
See accompanying notes to consolidated financial statements.
33
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31,2004 and 2003
Additional Total
Common paid-in Accumulated stockholders'
stock capital deficit equity
------- ---------- ----------- -------------
Balance at December 31, 2002 $66,066 26,239,098 (20,539,805) 5,765,359
Common stock issued for services 28,722
512 28,210 -
Net loss (793,058) (793,058)
------- ---------- ----------- ----------
Balance at December 31, 2003 $66,578 26,267,308 (21,332,863) 5,001,023
Exercise of stock options 937 19,063 20,000
Common stock issued for services 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 68,637 27,129,162 (23,833,197) 3,364,602
======= ========== =========== ==========
See accompanying notes to consolidated financial statements.
34
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2004 and 2003
2004 2003
---- ----
Operating activities:
Net loss $ (2,500,334) $ (793,058)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depletion, depreciation and amortization 432,766 488,052
Amortization of debt issuance costs 122,418 -
Gain on sale of assets (397,149) -
Impairment of assets - 88,819
Change in Abandonment costs - (500,589)
Accretion of asset retirement obligations 96,542 80,428
Change in accounting principle - 40,455
Equity in losses of affiliate 96,116 90,764
Compensation from issuance of warrants 693,513 -
Common stock issued for services 142,000 28,722
Changes in operating assets and liabilities:
Accounts Receivable 172,721 26,207
Prepaid expenses and other assets 51,404 137,289
Deferred federal income tax 244,444 -
Abandonment costs incurred - (3,288,413)
Trade accounts payable and accrued expenses (1,757,275) 2,236,867
------------ ------------
Net cash used in
operating activities (2,602,834) (1,364,457)
------------ ------------
Investing activities:
Exploration and development costs (26,590) (190,237)
Purchases of property and equipment (11,141) (54,256)
Proceeds from sale of assets 1,000,127 -
Development costs - New Avoca (87,667) (93,834)
------------ ------------
Net cash provided by (used in)
investing activities 874,729 (338,327)
------------ ------------
See accompanying notes to consolidated financial statements.
35
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS, CONTINUED
Years ended December 31, 2004 and 2003
2004 2003
---- ----
Financing activities:
Proceeds from Borrowings 750,000 -
Financing costs incurred (192,638) -
Proceeds received from issuance of warrants
and exercise of stock options 28,400 -
----------- -----------
Net cash provided by
financing activities 585,762 -
----------- -----------
Decrease in cash and cash equivalents (1,142,343) (1,702,784)
Cash and cash equivalents at beginning of year 2,702,892 4,405,676
----------- -----------
Cash and cash equivalents at end of year $ 1,560,549 $ 2,702,892
=========== ===========
Supplementary cash flow information:
Interest paid $ 15,807 $ -
=========== ===========
See accompanying notes to consolidated financial statements.
36
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004 and 2003
(1) ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Blue Dolphin Energy Company was incorporated in Delaware in January 1986
to engage in oil and gas exploration, production and acquisition
activities and oil and gas transportation and marketing. We were formed
pursuant to a reorganization effective June 9, 1986.
PRINCIPLES OF CONSOLIDATION
Our consolidated financial statements include the accounts of our
wholly-owned subsidiaries. All significant intercompany balances and
transactions have been eliminated in consolidation.
ACCOUNTING ESTIMATES
We have made a number of estimates and assumptions relating to the
reporting of assets and liabilities and to the disclosure of contingent
assets and liabilities, including reserve information, which affects the
depletion calculation as well as the computation of the full cost ceiling
limitation to prepare these financial statements in conformity with
accounting principles generally accepted in the United States. Actual
results could differ from those estimated.
CASH EQUIVALENTS
Cash equivalents include liquid investments with an original maturity of
three months or less. Cash balances are maintained in depository and
overnight investment accounts with financial institutions which at times,
exceed insured limits. We monitor the financial condition of the financial
institutions and have experienced no losses associated with these
accounts.
OIL AND GAS PROPERTIES
Oil and gas properties are accounted for using the full-cost method of
accounting, whereby all costs associated with acquisition, exploration,
and development of oil and gas properties, including directly related
internal costs, are capitalized on a country-by-country cost center basis.
We utilize one cost center for all of our properties. Amortization of such
costs and estimated future development costs are determined using the
unit-of-production method. Costs directly associated with the acquisition
and evaluation of unproved properties are excluded from the amortization
computation until it is determined whether or not proved reserves can be
assigned to the properties or impairment has occurred. For the year ended
December 31, 2003, we recorded a partial impairment of our oil and gas
properties of approximately $.1 million.
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.
37
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 periods indicated:
Year Ended
December 31,
2004 2003
--------- ---------
Depletion expense per Mcf
equivalent
produced $ 1.23 $ 0.51
========= =========
At December 31, 2004 oil and gas properties included $177,589 of unproved
leasehold costs that are not being amortized. These costs will begin to be
amortized when they are evaluated and proved reserves are discovered,
impairment is indicated or when the lease term expires. Unproved leasehold
costs consist of interests in federal leases located in the Gulf of Mexico
with expiration dates ranging from November 2005 to November 2008. In
order to retain the leases after the primary term, they must be producing
or development operations must be in progress. The leases have primary
terms of 5 years. Development of these leases is dependent upon the other
owners of the leases to initiate a plan of development.
The following table reflects the periods when costs were incurred for
unproved leasehold costs:
December 31,
------------
Total 2004 2003 Prior Years
---------- ------ ------ -----------
Property acquisition costs, net* $ 138,453 16,892 20,464 101,097
Exploration costs, net* 39,136 - - 39,136
---------- ------ ------ ---------
$ 177,589 16,892 20,464 140,233
========== ====== ====== =========
* Costs are net of leasehold costs transferred to the amortization base
when they are evaluated and proved reserves are discovered, impairment is
indicated or when the lease term expires.
We capitalize interest on expenditures made in connection with significant
exploration and 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 periods reflected herein.
PIPELINES AND FACILITIES
Pipelines and facilities are recorded at cost. Depreciation is computed
using the straight-line method over estimated useful lives of 10-22 years.
OTHER PROPERTY AND EQUIPMENT
Depreciation of furniture, fixtures and other equipment, including assets
held under capital leases, is computed using the straight-line method over
estimated useful lives of 3-10 years.
38
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In accordance with 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", which
addresses financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the associated asset
retirement costs. The standard applies to legal obligations associated
with the retirement of long-lived assets that result from the acquisition,
construction, development and/or normal use of the asset.
SFAS 143 requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is incurred
if a reasonable estimate of fair value can be made. The fair value of the
liability is added to the carrying amount of the associated asset and this
additional carrying amount is depreciated over the life of the asset. If
the obligation is settled for other than the carrying amount of the
liability, we will recognize a gain or loss on settlement.
SFAS 143 amended SFAS No. 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies" to require that the fair value of a liability
for an asset retirement obligation be recognized in the period in which it
is incurred if a reasonable estimate of fair value can be made. Under the
provisions of SFAS 143, asset retirement obligations are capitalized as
part of the carrying value of the long-lived asset. Under the provisions
of SFAS 19, asset retirement obligations were recognized using a
cost-accumulation approach. Prior to the adoption of SFAS 143, we recorded
asset retirement obligations through the unit-of-production method for oil
and gas properties, and the straight-line method for pipelines and related
facilities.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $1.0 million increase in the carrying value of
pipelines, (ii) a $400,000 decrease in accumulated depreciation,
depletion, and amortization of property, plant and equipment, and (iii) a
$1.4 million increase in non-current abandonment liabilities. The net
impact of items (i) through (iii) was to record an expense of $40,000, net
of tax, as a cumulative effect adjustment of a change in accounting
principle in our consolidated statement of operations upon adoption on
January 1, 2003.
We have asset retirement obligations associated with the future
abandonment of pipelines and related facilities and offshore oil and gas
properties. During 2003, we abandoned/reefed the Buccaneer Field at a cost
of approximately $3.3 million. Additionally, we reduced our provision for
the Buccaneer Field abandonment costs resulting in a gain of approximately
$.5 million for the year ended December 31, 2003.
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 recorded in accordance with the provisions of SFAS 143 during
the years ended December 31, 2004 and 2003.
39
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Year ended
December 31,
2004 2003
--------- ---------
(in thousands)
Beginning asset retirement obligations................. $ 1,552 $ 3,800
Cumulative effect adjustment........................... - 401
Liabilities incurred during period..................... - 1,060
Liabilities settled during period...................... (14) (3,288)
Gain from adjustment to estimated obligations.......... (9) (501)
Accretion expense...................................... 97 80
Revisions in estimated cash flows...................... (4) -
--------- ---------
Ending asset retirement obligations ................... $ 1,622 $ 1,552
========= =========
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
undistributed earnings and losses after acquisition.
STOCK-BASED COMPENSATION
We apply SFAS No. 123, Accounting for Stock-Based Compensation, which
allows us to adopt a fair value based method of accounting for a
stock-based employee compensation plan or to continue to use the intrinsic
value based method of accounting prescribed by Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees. We account for
stock-based compensation under the intrinsic value method and provide the
pro forma effects of the fair value method as required.
Had compensation cost for our stock option plans been determined based on
the fair market value at the grant dates for awards made, our net income
(loss) and income (loss) per share would have been adjusted to the pro
forma amounts indicated below:
40
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Year ended December 31,
----------------------------
2004 2003
---------- ----------
Net loss as reported (2,500,334) $ (793,058)
Add: total stock-based employee compensation
expense included in net income, net of related tax
effects 693,513 -
Deduct: total stock based employee compensation
expense determined under fair value based method
for all awards, net of tax related effects (866,193) (30,347)
---------- ----------
Pro Forma net loss (2,673,014) $ (823,405)
========== ==========
Basic and diluted loss per share:
As reported $ (0.37) $ (0.12)
Pro Forma $ (0.40) $ (0.12)
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, 2004 and 2003 was not material.
RECOGNITION OF PIPELINE TRANSPORTATION REVENUE
Revenue from the transportation of gas, condensate and crude oil is recognized
on the accrual basis as products are transported.
INCOME TAXES
We provide for income taxes using the asset and liability method pursuant to
SFAS No. 109, Accounting for Income Taxes ("Statement 109"). Under the asset and
liability method of Statement 109, deferred tax assets and liabilities are
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases and operating loss and tax credit carryforwards.
Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in income in the
period that includes the enactment date.
EARNINGS PER SHARE
We follow SFAS No. 128, Earnings per Share ("Statement 128"), 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.
41
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Employee stock options and stock warrants at December 31, 2004 and 2003 were not
included in the computation of diluted earnings per share because the effect of
their assumed exercise and conversion would have an antidilutive effect on the
computation of diluted loss per share.
The following table provides a reconciliation between basic and diluted earnings
per share:
Weighted-
Average Number
of Common Shares
Outstanding
and Potential Per
Dilutive Share
Net Loss Common Shares Amount
---------------- ---------------- -----------
Year ended December 31, 2004
Basic and diluted loss per share $ (2,500,334) 6,734,395 $ (0.37)
Year ended December 31, 2003
Basic and diluted loss per share $ (793,058) 6,640,285 $ (0.12)
ENVIRONMENTAL
We are subject to extensive federal, state and local environmental laws and
regulations. These laws, which are constantly changing, regulate the discharge
of materials into the environment and may require us to remove or mitigate the
environmental effects of the disposal or release of petroleum or chemical
substances at various sites. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have no future
economic benefits are expensed. Liabilities for expenditures of a noncapital
nature are recorded when environmental assessment and/or remediation is
probable, and the costs can be reasonably estimated. Such liabilities are
generally recorded at their undiscounted amounts unless the amount and timing of
payments is fixed or reliably determinable.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2003, an issue was brought before the FASB regarding whether or not
contract-based oil and gas mineral rights held by lease or contract ("mineral
rights") should be recorded or disclosed as intangible assets. The issue
presents a view that these mineral rights are intangible assets as defined in
SFAS No. 141, "Business Combinations," and, therefore, should be classified
separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No.
142, "Goodwill and Other Intangible Assets," became effective for transactions
subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142
required as of January 1, 2002. SFAS No. 141 requires that all business
combinations initiated after June 30, 2001 be accounted for using the purchase
method and that intangible assets be disaggregated and reported separately from
goodwill. SFAS No. 142 established new accounting guidelines for both finite
lived intangible assets and indefinite lived intangible assets. Under the
statements, intangible assets should be separately reported on the face of the
balance sheet and accompanied by disclosure in the notes to financial
statements. SFAS No. 142 does not apply to accounting utilized by the oil and
gas industry as prescribed by SFAS No. 19, and is silent about whether or not
its disclosure provisions apply to oil and gas companies.
42
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In September 2004, the FASB posted FASB staff position ("FSP") SFAS 142-2,
"Application of SFAS 142 to Oil and Gas Producing Entities." The FSP
clarifies that the exception in paragraph 8(b) of SFAS No. 142, "Goodwill
and Other Intangible Assets," includes the balance sheet classification
and disclosures for drilling and mineral rights of oil and gas producing
entities. Accordingly, the FASB staff believes that the scope exception
extends to the disclosure provisions of SFAS No. 142 for drilling and
mineral rights of oil and gas producing entities. SFAS 142-2 is effective
for the first reporting period after September 2, 2004. The FSP had no
impact on our financial position, results of operations or cash flows.
In December, 2004, the FASB issued SFAS No. 123R, "Share-Based Payment,"
that addresses the accounting for share-based payment transactions in
which a company receives employee services in exchange for equity
instruments of the company, such as stock options and restricted stock.
SFAS No. 123R eliminates the ability to account for share-based
compensation transactions using APB Opinion No. 25 and requires instead
that such transactions be accounted for using a fair value-based method.
We currently account for stock-based compensation using the intrinsic
method pursuant to APB Opinion No. 25. SFAS No. 123R requires that all
stock-based payments to employees, including grants of employee stock
options and restricted stock, be recognized as compensation expense in the
financial statements based on their fair values. Public entities that file
as small business issuers will be required to apply Statement 123R in the
first interim or annual reporting period that begins after December 15,
2005. Accordingly, we will be required to apply SFAS No. 123R beginning in
the fiscal quarter ending March 31, 2006. We are currently assessing the
provisions of SFAS No. 123R and its impact on our consolidated financial
statements.
(2) LIQUIDITY AND GOING CONCERN
At December 31, 2004, our working capital was approximately $400,000. In
order to satisfy our working capital and capital expenditure requirements
for the year ending December 31, 2005, we believe that we will need to
raise approximately $500,000 of capital. Unless operating performance of
existing assets significantly improves or a significant acquisition of
earning assets is made, we will need to either, extend the payment terms
of our promissory notes, arrange external financing and/or sell assets to
raise the necessary capital.
Historically, we have relied on the proceeds from the sale of assets and
capital raised from the issuance of debt and equity securities to
individual investors and related parties to sustain our operations. There
can be no assurance that we will be able to obtain financing or sell
assets on commercially acceptable terms to meet our capital requirements.
Our inability to raise capital may have a material adverse effect on our
financial condition, ability to meet our obligations and operating needs,
and results of operations. Our financial statements contained herein have
been prepared assuming that we will continue as a going concern. Our
capital requirements raise substantial doubt about our ability to continue
as a going concern. Our financial statements do not include any
adjustments that might result from the outcome of this uncertainty.
(3) FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash and cash equivalents, receivables and accounts
payable approximate fair value due to the short-term maturities of these
instruments. The carrying value of the Note Payable approximates the fair
value due to the short-term nature of such notes.
43
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) INCOME TAXES
Income tax expense for both 2004 and 2003 was $0.
The income tax effects of temporary differences that give rise to
significant portions of deferred tax assets and deferred tax liabilities
at December 31, 2004 are presented below:
Deferred tax assets:
Net operating loss and capital loss carryforwards $ 5,959,916
Deferred tax liabilities: -
Basis differences in property and equipment (77,912)
-----------
Net deferred tax asset 5,882,004
Less: valuation allowance (5,882,004)
-----------
Deferred tax asset $ -
===========
In assessing the realisability of deferred tax assets, we apply SFAS No.
109 to determine whether it is more likely than not that some portion or
all of the deferred tax assets will not be realized. As a result, our
valuation allowance at December 31, 2004 reduced the net deferred tax
assets to $ 0.
Our effective tax rate applicable to continuing operations in 2004 and 2003
is as follows:
2004 2003
---- ----
Expected tax rate (34%) (34%)
State taxes, net of federal benefit - -
Expenses not deductible for tax purpose - -
Increase in valuation allowance recognized
in earnings 34% 34%
Other - -
--- ---
0% 0%
=== ===
For federal tax purposes, we have a net operating loss carryforward
("NOL") of approximately $17.5 million at December 31, 2004. These NOLs
must be utilized prior to their expiration, which is between 2005 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.
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
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
44
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 50% or more of our 83% interest in the Blue
Dolphin System is sold before December 31, 2006.
Long-term debt at December 31, 2004 is as follows:
Note payable, interest at $750,000
6% per annum payable out of 90%
of the net revenues from the 1/3 interest
acquired in the Blue Dolphin Pipeline
System, secured by the 1/3 interest
acquired, all remaining principal due
December 31, 2006
Less current maturities 130,000
--------
$620,000
========
(6) SHORT-TERM PROMISSORY NOTES AND WARRANTS
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
2,800,000 warrants (the "Warrants") to purchase shares of common stock at
a purchase price of $0.003 per warrant. 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 closing of 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. The
Promissory Notes mature on September 8, 2005, and accrue interest at a
rate of 12.0% per annum, of which 4% is payable monthly and 8% is payable
at maturity. The Promissory Notes are secured by a second lien on our 83%
interest in the Blue Dolphin System. All Warrants are immediately
exercisable and will expire five years after their date of issuance. Each
Warrant is exercisable for one share of common stock at an exercise price
of $0.25 per share. The Warrants contain standard antidilution provisions,
as well as provisions that will result in adjustments to the exercise
price of the Warrants if we issue common stock at a price below $0.25 per
share, subject to certain exceptions.
Pursuant to the terms of the Purchase Agreement, we appointed Laurence N.
Benz and F. Gardner Parker to our board of directors. Messrs. Benz and
Parker each purchased a Promissory Note in the principal amount of
$25,000. Messrs. Benz and Parker purchased 83,334 and 383,328 Warrants,
respectively. Michael S Chadwick, an existing director, purchased a
Promissory Note in the principal amount of $12,500 and 41,667 Warrants. In
addition Messrs. Benz, Chadwick and Parker were each granted 100,000
Warrants.
45
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In addition to serving on our board of directors, Mr. Chadwick is also a
Senior Vice President and Managing Director of Sanders Morris Harris
Group, Inc. ("SMH"), a financial services holding company headquartered in
Houston, Texas. The Company paid SMH a $25,000 fee in connection with the
Purchase Agreement and agreed to retain SMH to provide a fairness opinion,
if required.
We also entered into a consulting agreement with Mr. Parker. Mr. Parker's
consulting agreement with us has a term of up to eighteen months. We are
obligated to pay Mr. Parker a monthly fee of $2,000 and a bonus that will
accrue at the rate of $3,000 per month and be payable upon consummation of
a merger or acquisition by us.
(7) STOCKHOLDERS' EQUITY
In 2004, we issued shares of our common stock into our 401k Plan. In March
2004 we issued 50,000 shares into the 401k Plan as a 2003 contribution and
50,000 shares in January 2005, as a 2004 contribution. We recorded an
expense of $124,000 in 2004 for both contributions of common stock. We
issued 14,040 shares of our common stock in 2003 as a severance payment to
former employees and recorded compensation expense of $7,722. We also
issued 12,156 and 37,227 shares in 2004 and 2003, respectively, to the
board of directors and recorded an expense of $18,000 and $21,000 in 2004
and 2003, respectively.
(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.
At December 31, 2004 we had reserved a total of 346,942 shares of common
stock for issuance under the above mentioned stock option plans. The
outstanding stock options granted to key employees, officers and
directors, for the purchase of shares of common stock, are as follows:
46
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Exercise
price per share
-----------------
Shares From To
------- ---- ----
Balance, December 31, 2002 416,321 0.35 6.00
======= ==== ====
Granted 186,000 0.43 0.43
Expired 100,402 0.43 6.00
------- ---- ----
Balance, December 31, 2003 501,919 0.35 6.00
======= ==== ====
Exercised 117,142 0.35 0.43
Expired 37,835 1.55 6.00
------- ---- ----
Balance, December 31, 2004 346,942 0.35 6.00
======= ==== ====
As of December 31, 2004, options for 346,942 shares of common stock were
immediately exercisable. There were no options granted in 2004, and
186,000 options granted in 2003. Pursuant to the requirements of FASB No.
123, the weighted average fair market value of options granted during 2003
was $0.16 per share. The weighted average closing bid price for the
Company's common stock at the date the options were granted during 2003
was $0.43 per share. The weighted average exercise price for outstanding
options at December 31, 2004 and 2003 per share was $1.09 and $1.06,
respectively. The fair market value pursuant to FASB No. 123 of each
option granted is estimated on the date of grant using the Black-Scholes
options-pricing model. The model assumed expected volatility of 98%,
risk-free interest rate of 1.03% for grants in 2003, and an expected life
of one year. As we have not declared dividends on our common stock since
it became a public entity, no dividend yield was used. Actual value
realized, if any, is dependent on the future performance of our common
stock and overall stock market conditions. There is no assurance the value
realized by an optionee will be at or near the value estimated by the
Black-Scholes model. No compensation expense was recorded in 2004 or 2003
for stock options granted.
Outstanding options at December 31, 2004 expire between May 17, 2010 and
January 5, 2013.
(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 12.8% of the common stock of Drillmar, Inc. Our Chairman, Ivar
Siem, and one of our Directors, Harris A. Kaffie, own or control 33.9%,
and 30.3%, 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 collected $165,000 of
the accounts receivable from Drillmar and we have collected the remaining
balance of approximately $45,000 in 2005.
47
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 can be reduced
to less than 1%. However, 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, which if
converted along with all of Drillmar's outstanding convertible notes would
represent 5.5% of Drillmar's common stock. Messrs. Siem, Kaffie and
Trimble (one of our Directors) hold or control Drillmar convertible notes
which if converted along with all of Drillmar's outstanding convertible
notes would represent 30.2%, 28.7% and 1.5%, respectively, of Drillmar's
common stock.
We entered into a new agreement with Drillmar effective as of February 1,
2003, whereby we provide and charge for office space which is currently
$4,750 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 annually. 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, 2004:
Future Future
minimum Future minimum
Year ending lease sublease lease
December 31, payments payments payments, net
------------ ---------- --------- -------------
2005 198,153 78,552 119,601
2006 195,617 78,552 117,065
--------- --------- ----------
$ 393,770 $ 157,104 $ 236,666
========= ========= ==========
Rental expense on operating leases, net of sublease income, for the years
indicated are as follows:
Year ended
December 31,
--------------------
2004 $ 64,632
2003 $ 89,319
48
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 financial position,
results of operations or cash flows.
(12) BUSINESS SEGMENT INFORMATION
Our income producing operations are conducted in two principal business
segments: (i) oil and gas exploration and production and (ii) pipeline
operations, which includes mid-stream projects. The intercompany revenues
and expenses are eliminated in consolidation. Information concerning these
segments for the years ended December 31, 2004 and 2003 is as follows:
Depletion,
Operating Depreciation,
income Identifiable Amortization and
Revenues (loss) (1) assets (3) Impairment (2)
------------- ------------ ------------ ----------------
Year ended December 31, 2004
Oil and gas exploration and
production $ 395,700 (182,770) 295,916 94,025
Pipeline operations 1,014,137 (1,331,046) 5,743,418 327,418
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)
Year ended December 31, 2003:
Oil and gas exploration and
production $ 1,582,054 419,674 687,984 234,991
Pipeline operations 934,760 (1,100,096) 5,905,021 324,174
Other (531,141) 3,378,889 17,706
------------- ------------ ------------ ----------------
Consolidated 2,516,814 (1,211,563) 9,971,894 576,871
Other income 458,960
------------
Loss before income taxes (752,603)
----------
1. Consolidated loss from operations includes $1,194,911 and $513,435 in
unallocated general and administrative expenses, and unallocated
depletion, depreciation, amortization and impairment of $11,323 and
$17,706 for the years ended December 31, 2004 and 2003, respectively.
2. Pipeline depletion, depreciation and amortization includes a provision for
pipeline abandonment of $48,595 for the years ended December 31, 2004 and
2003. Oil and gas depletion, depreciation, amortization and impairment
includes a provision for abandonment costs of platforms and wells of
$24,497 and $50,723 for the years ended December 31, 2004 and 2003,
respectively.
49
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 $1075 and $875,777 (of which $874,753
was recorded for future asset retirement obligations) were recorded for
pipeline operations for the years ended December 31, 2004 and 2003,
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, 2004:
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
Year ended December 31, 2003:
Spinnaker Exploration Company $ 1,446,622 - $1,446,622
(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 ("SEC") and SFAS No.
69, Disclosures About Oil and Gas Producing Activities ("Statement 69").
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 84% and 91% of our oil
and gas sales for the years ended December 31, 2004 and 2003, respectively
and 23% and 57% of our total revenues for these periods.
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 accounted for
16% and 4% of our oil and gas sales for the years ended December 31, 2004,
and 2003 respectively, and 4% and 2% of our total revenues for these
periods.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Set forth below is a summary of the changes in the estimated quantities of
our crude oil and condensate, and gas reserves for the periods indicated,
as estimated by us as of December 31, 2004 and 2003. All of our reserves
are located within the United States. Proved reserves cannot be measured
exactly because the estimation of reserves involves numerous judgmental
determinations. Accordingly, reserve estimates must be continually revised
as a result of new information obtained
50
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
from drilling and production history, new geological and geophysical data and
changes in economic conditions.
Proved reserves are estimated quantities of gas, crude oil, and condensate which
geological and engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods.
Oil Gas
Quantity of Oil and Gas Reserves (Bbls) (Mcf)
-------------------------------- ------- --------
Total proved reserves at December 31, 2002 1,447 280,000
Reserve additions 70 11,702
Revisions to previous estimate 1,045 24,216
Production (2,271) (274,268)
------- --------
Total proved reserves at December 31, 2003 291 41,650
Revisions to previous estimate 884 60,984
Production (810) (66,491)
Reserves sold - (879)
------- --------
Total Proved Reserves at December 31, 2004 365 35,264
Proved developed reserves:
December 31, 2004 365 35,264
December 31, 2003 291 41,650
51
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, 2004:
Unproved properties and prospect generation
costs not being amortized $ 177,589
Proved properties being amortized 170,440
Asset retirement obligations 169,181
Less accumulated depletion, depreciation,
amortization and impairment (331,752)
-----------
Net capitalized costs $ 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:
Year Ended
December 31,
-----------------------------
2004 2003
----------- -------------
Exploration costs $ 26,197 $ 83,423
Development costs 394 107,087
Disposition of assets (9,305) -
Asset retirement obligations (25,764) 194,945
----------- -------------
$ (8,478) $ 385,455
=========== =============
We did not acquire any oil and gas properties in 2004.
52
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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,
------------------------------
2004 2003
--------- ---------
Future cash inflows $ 270,000 $ 227,000
Future development costs (13,000) (27,000)
Future production costs (108,000) (63,000)
Future Asset Retirement Costs (203,000) (195,000)
--------- ---------
Future net cash inflows (outflows) before income taxes (54,000) (58,000)
Future income taxes 18,360 19,720
--------- ---------
Future net cash flows (35,640) (38,280)
10% discount factor 23,760 13,200
--------- ---------
Standardized measure of discounted
future net cash inflows (outflows) $ (11,880) $ (25,080)
========= =========
Future net cash flows at each year end, as reported in the above schedule,
were determined by summing the estimated annual net cash flows computed by:
(1) multiplying estimated quantities of proved reserves to be produced during
each year by current prices and (2) deducting estimated expenditures to be
incurred during each year to develop and produce the proved reserves (based
on current costs).
Income taxes were computed by applying year-end statutory rates to pretax net
cash flows, reduced by the tax basis of the properties and available net
operating loss carryforwards. The annual future net cash flows were discounted,
using a prescribed 10% rate, and summed to determine the standardized measure of
discounted future net cash flow.
We caution readers that the standardized measure information which places a
value on proved reserves is not indicative of either fair market value or
present value of future cash flows. Other logical assumptions could have been
used for this computation which would likely have resulted in significantly
different amounts. Such information is disclosed solely in accordance with
Statement 69 and the requirements promulgated by the SEC to provide readers with
a common base for use in preparing their own estimates of future cash flows and
for comparing reserves among companies. We do not rely on these computations
when making investment and operating decisions. Principal changes in the
Standardized Measure of Discounted Future Net Cash Flows attributable to our
proved oil and gas reserves for the periods indicated are as follows:
53
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31
------------------------------
2004 2003
------------ --------------
Sales and transfers, net of production costs $ (261,387) $ (1,395,398)
Acquisition of reserves - -
Net change in estimated future development costs 1,869 8,598
Sales of minerals in place (4,119) -
Revisions in previous quantity estimates 190,537 159,067
Net changes in sales and transfer prices, - -
net of production costs 4,648 256,823
Accretion of discount (3,800) 74,757
Net change in income taxes (6,800) 267,092
Change in production rates (timing) and other 92,252 110,587
------------ --------------
Net change $ 13,200 $ (518,474)
============ ==============
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
ITEM 8A. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, we carried out an
evaluation, under the supervision and with the participation of our management,
including our Chief Executive Officer and Principal Accounting Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rules 13a - 14(c) and 15d - 14 (c) under the
Securities Exchange Act of 1934, as amended (the "Exchange Act")). Based upon
the evaluation, the Chief Executive Officer and Principal Accounting Officer
concluded that our disclosure controls and procedures are effective to ensure
that information required to be disclosed by us in reports that we file or
submit under the Exchange Act, are recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission rules
and forms. There were no significant changes in our internal controls or in
other factors that could significantly affect these controls subsequent to the
date of their evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
PART III
ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 9 is incorporated by reference to our
definitive proxy statement relating to our 2005 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 2005 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.
54
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 11 is incorporated by reference to our
definitive proxy statement relating to our 2005 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 2005 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, LISTS AND REPORTS ON FORM 8-K
(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
4.3 (6) Form of Warrant 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.
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 1, 2002.
* * 14.1 Code of ethics applicable to the Chairman, Chief
Executive Officer and Senior Financial Officer.
* * 21.1 List of subsidiaries of the Company.
55
No. Description
* * 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 G. Brian Lloyd Certification Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to section 302 of the
Sarbanes-Oxley Act of 2002.
* * 32.1 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 G. Brian Lloyd Certification Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to section 906 of the
Sarbanes-Oxley Act of 2002.
99.1 Voting Agreement between certain stockholders of Blue Dolphin
Energy Company and certain investors of Blue Dolphin Energy
Company, dated September 8, 2004.
* 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 field 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)
56
(9) Incorporated herin 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.
(b) Reports on Form 8-K
On December 6, 2004 we filed a current report on Form 8-K dated
November 30, 2004 reporting the sale of Warrants. The Item in such
current report was Item 3.02 (Unregistered Sales Of Equity
Securities).
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 2005 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.
57
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
BLUE DOLPHIN ENERGY COMPANY
(Registrant)
By: /s/ Ivar Siem
-----------------------------
Ivar Siem
(principal executive officer)
Date: March 25, 2005
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------------------------- ----------------------------------------- --------------
/s/ Ivar Siem Chairman March 25, 2005
--------------------------- (principal executive officer)
Ivar Siem
/s/ G. Brian Lloyd Vice President, Treasurer March 25, 2005
--------------------------- (principal accounting and financial officer)
G. Brian Lloyd
/s/ Laurence N. Benz Director March 25, 2005
---------------------------
Laurence N. Benz
/s/ Harris A. Kaffie Director March 25, 2005
---------------------------
Harris A. Kaffie
/s/ Michael S. Chadwick Director March 25, 2005
---------------------------
Michael S. Chadwick
/s/ James M. Trimble Director March 25, 2005
---------------------------
James M. Trimble
/s/ F. Gardner Parker Director March 25, 2005
---------------------------
F. Gardner Parker
58
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
4.3 (6) Form of Warrant 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.
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 1, 2002.
* * 14.1 Code of ethics applicable to the Chairman, Chief Executive Officer and Senior Financial
Officer.
* * 21.1 List of subsidiaries of the Company.
No. Description
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* * 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 G. Brian Lloyd Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
* * 32.1 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 G. Brian Lloyd Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
99.1 Voting Agreement between certain stockholders of Blue Dolphin Energy Company
and certain investors of Blue Dolphin Energy Company, dated September 8, 2004.
* Management Compensation Plan.
** Filed herewith.
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(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 field 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 herin 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.