e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|
|
|
þ |
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
or
|
|
|
o |
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For
the transition period from
to .
Commission File No. 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
|
|
|
Delaware
State or other jurisdiction
of incorporation or organization
|
|
73-1268729
(I.R.S. Employer
Identification No.) |
|
|
|
801 Travis Street, Suite 2100
Houston, Texas
(Address of principal executive offices)
|
|
77002
(Zip Code) |
(713) 568-4725
Registrants telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
|
|
|
Title of each class
|
|
Name of each exchange on which registered |
Common Stock, par value $0.01 per share
|
|
NASDAQ Capital Market |
Securities registered pursuant to Section 12(g) of the Act:
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
(§229.405 of this chapter)is not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definition of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Act.
|
|
|
|
|
|
|
Large accelerated filer o
|
|
Accelerated filer o
|
|
Non-accelerated filer o
(Do not check if a smaller reporting company)
|
|
Smaller Reporting Company þ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o No þ
Aggregate market value of voting stock held by non-affiliates of the registrant
as of June 30, 2009 was approximately $3.2 million based on the closing price of
$0.42 per share on the NASDAQ Capital Market.
Number of shares of common stock outstanding as of April 14, 2010 11,928,251
DOCUMENTS INCORPORATED BY REFERENCE
Certain sections of the registrants definitive proxy statement for the 2010 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 registrants fiscal year ended December
31, 2009, are incorporated by reference in Part III of this report.
BLUE
DOLPHIN ENERGY COMPANY
FORM 10-K REPORT INDEX
2
PART I
Forward Looking Statements. Certain of the statements included in this annual report
on Form 10-K, 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 results
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:
|
|
|
ability to continue as a going concern; |
|
|
|
|
collectability of a $2.0 million loan receivable; |
|
|
|
|
ability to regain compliance for continued listing on NASDAQ; |
|
|
|
|
ability to complete a combination with one or more target businesses; |
|
|
|
|
ability to improve pipeline utilization levels; |
|
|
|
|
ability to secure additional working capital to fund operations; |
|
|
|
|
performance of third party operators for properties where we have an interest; |
|
|
|
|
production from oil and gas properties that we have interests in; |
|
|
|
|
volatility of oil and gas prices; |
|
|
|
|
uncertainties in the estimation of proved reserves, in the projection of future rates of
production, the timing of development expenditures and the amount and timing of property
abandonment; |
|
|
|
|
costly changes in environmental and other government regulations for which Blue Dolphin
is subject; and |
|
|
|
|
adverse changes in the global financial markets. |
Additional factors that could cause actual results to differ materially from those indicated in the
forward-looking statements are discussed in Item 1A 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 Managements Discussion and Analysis of Financial Condition and
Results of Operations in this report.
The Company
Blue Dolphin Energy Company, a Delaware corporation formed in 1986, is a holding company and
conducts substantially all of its operations through its subsidiaries. We conduct our business
activities in two primary business segments: (i) pipeline transportation and related services for
producer/shippers, and (ii) oil and gas exploration and production. Substantially all of our
assets consist of equity interests in our subsidiaries. Our operating subsidiaries are:
|
|
|
Blue Dolphin Pipe Line Company, a Delaware corporation; |
|
|
|
|
Blue Dolphin Petroleum Company, a Delaware corporation; |
|
|
|
|
Blue Dolphin Exploration Company, a Delaware corporation; |
|
|
|
|
Blue Dolphin Services Co., a Texas corporation; and |
|
|
|
|
Petroport, Inc., a Delaware corporation. |
3
Our principal executive office is located at 801 Travis Street, Suite 2100, Houston, Texas, 77002,
and our telephone number is (713) 568-4725. All of our operations are in the Gulf of Mexico,
except our onshore facilities which we own and operate to process and store natural gas and liquids
to primarily serve our offshore operations. We have six (6) full-time employees and regularly use
the services of two (2) consultants. Our common stock, par value $0.01 per share (Common Stock)
is traded on the NASDAQ Capital Market under the ticker symbol BDCO. Our website address 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 interests in properties, are defined in the Glossary of
Certain Oil and Gas Terms of this Form 10-K.
Recent Developments
The Blue Dolphin Pipeline System (the BDPS) is currently transporting an aggregate of
approximately 16 Mcf of gas per day from 8 shippers and the GA 350 Pipeline is currently
transporting an aggregate of approximately 22 MMcf of gas per day from 6 shippers. Annual revenues
from pipeline operations were $1,866,971 in 2009. Throughput on the BDPS and the GA 350
decreased during 2009 due to normal production declines from the properties owned by companies that
use our pipelines to ship their production.
In our oil and gas exploration and production segment, we recognized net oil and gas sales revenues
of approximately $43,000 in 2009, associated with our approximate 2.8% working interest in one
active well in High Island Block 37. The A-2 Well was restarted in February 2009, after being
shut-in as a result of Hurricane Ike. We believe the A-2 Well could continue to produce until
early 2012; however, the well could deplete faster than currently projected or could develop
production problems resulting in the cessation of production.
We recognized net oil and gas sales revenues of approximately $57,000 in 2009 from our interest in
one active well in High Island Block 115. The B-1 ST2 Well first began production in late November
2007. It was shut-in in September 2008, due to damage resulting from Hurricane Ike. Although the
well resumed production in the first quarter of 2009, it was shut-in again in August 2009, and
currently remains shut-in, due to production handling problems on our downstream production
handling platform, High Island Block 71.
We recognized net oil and gas sales revenue of approximately $26,000 from our interest in one
active well in Galveston Area Block 321. The A-2 Well was drilled as an exploratory well in
December 2008. In January 2009, the well was determined to be economically successful and was
connected to the BDPS in the first quarter of 2009.
On March 16, 2010, we were notified by NASDAQ that our common stock is subject to delisting for
failure to comply with the minimum bid price listing requirement. We requested, and were granted,
a hearing before a NASDAQ Listing Qualifications Panel (the Panel) to appeal the delisting
determination. Our common stock will continue to be listed and traded on the NASDAQ Capital Market
until the Panel renders a written decision on the matter.
As a means to cure our NASDAQ minimum bid requirement deficiency, on March 16, 2010, our Board of
Directors (the Board) adopted, subject to stockholder approval, a Certificate of Amendment to our
Certificate of Incorporation, as amended and restated, to implement a reverse stock split of our
Common Stock at a ratio within a range from 1 for 5 (1:5) to 1 for 10 (1:10), at the discretion of
Board, at any time prior to September 1, 2010.
On July 31, 2009, we issued a $2.0 million non-interest bearing loan (the Loan) to Lazarus
Louisiana Refinery II, LLC (LLRII or the Borrower). The Loan, which was due on January 31,
2010, is secured by (i) a first lien on property owned by Lazarus Environmental, LLC (LEN), (ii)
a second lien on
4
property owned by LLRII and (iii) a guarantee from Lazarus Energy Holdings, LLC (LEH). We agreed
to forbear the loan receivable until June 11, 2010, provided the Borrower satisfies certain
conditions set forth in the forbearance agreement. Those certain conditions were not met, and on
April 9, 2010, we called on the full value of the Loan to be paid by April 13, 2010. As of the
date of this report, the Loan is in default and remains unpaid. However, management believes the
Loan will be paid at a date in the future. Management is currently pursuing a plan that would
include selling the note to a third party. In addition, management plans to begin the necessary
steps associated with collection on the collateral. Although this may take time, management feels
the Company will recover the full amount of the Loan through this process.
Pipeline Operations and Activities
All of our pipeline assets are held in, and operations conducted by, Blue Dolphin Pipe Line
Company.
The table below provides more information on our pipeline segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline |
|
|
|
|
|
|
|
|
|
Miles of |
|
|
Capacity |
|
|
Storage |
|
|
Average Throughput |
|
Segment |
|
Market |
|
|
Ownership |
|
|
Pipeline |
|
|
(MMcf/d) |
|
|
(Bbls)(1) |
|
|
(MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
BDPS |
|
Gulf of Mexico |
|
|
83.3 |
% |
|
|
34 |
|
|
|
160 |
|
|
|
85,000 |
|
|
|
15.5 |
|
|
|
22.6 |
|
|
|
22.3 |
|
GA 350 |
|
Gulf of Mexico |
|
|
83.3 |
% |
|
|
13 |
|
|
|
65 |
|
|
|
|
|
|
|
19.0 |
|
|
|
23.8 |
|
|
|
22.6 |
|
Omega(2) |
|
Gulf of Mexico |
|
|
83.3 |
% |
|
|
18 |
|
|
|
110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Storage facility connected in Freeport, Texas. |
|
(2) |
|
Inactive. |
The economic return on our pipeline system investments and the fees chargeable for the
services provided are dependent upon the amounts of gas and condensate gathered and transported.
Currently, the level of throughput on our pipeline systems is significantly below maximum capacity.
Competition for provision of gathering and transportation services similar to ours is intense in
the market areas we serve. See Markets & Competition for additional information. Since
contracts for gathering and transportation services with third party producer/shippers may be for
specified time periods, there can be no assurance that current or future producer/shippers will not
subsequently tie-in to alternative transportation systems or that current rates charged will be
maintained in the future. We actively market our gathering and transportation services to
producer/shippers operating in the vicinity of our pipeline systems. Future utilization of the
pipelines and related facilities will depend upon the success of drilling programs around our
pipelines, and the attraction, and retention, of producer/shippers to the systems. Various fees
are charged to producer/shippers for provision of transportation and onshore facility services.
Unless otherwise stated, all gas an liquids volumes transported are attributable to production from
third party producer/shippers.
|
|
Blue Dolphin Pipeline System The BDPS 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
systems onshore facilities, pipeline easements and rights-of-way are located. We own an 83%
undivided interest in the BDPS. The BDPS gathers and transports gas and condensate from
various offshore fields in the Galveston Area of the Gulf of Mexico to our onshore 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. |
5
|
|
The Blue Dolphin Pipeline consists of two segments, an offshore segment and an onshore segment.
The offshore segment transports both gas and condensate and is comprised of approximately 34
miles of 20-inch pipeline originating at an offshore platform in Galveston Area Block 288 and
running to shore. The offshore segment also includes the platform in Galveston Area Block 288
and 5 field gathering lines totaling approximately 27 miles connected to the main 20-inch line.
An additional 2 miles of 20-inch pipeline onshore connects the offshore segment to the onshore
facility at Freeport, Texas. The onshore segment also includes approximately 2 miles of
16-inch pipeline for transportation of gas from the onshore facility to a sales point at a
chemical plant complex and intrastate pipeline system tie-in in Freeport, Texas. The Buccaneer
Pipeline, an approximate 2 mile, 8-inch liquids pipeline, transports condensate from the
onshore facility storage tanks to our barge-loading terminal on the Intracoastal Waterway near
Freeport, Texas for sale to third parties. The Blue Dolphin Pipeline has an aggregate capacity
of approximately 160 MMcf of gas and 7,000 Bbls of crude oil and condensate per day. |
|
|
Galveston Area Block 350 Pipeline We own an 83% undivided interest in the
Galveston Area Block 350 Pipeline (the GA 350 Pipeline). The GA 350 Pipeline is an 8-inch,
13 mile offshore pipeline extending from Galveston Area Block 350 to an interconnect with a
transmission pipeline in Galveston Area Block 391 located approximately 14 miles south of the
Blue Dolphin Pipeline. Current system capacity on the GA 350 Pipeline is 65 MMcf of gas per
day. |
|
|
Other We also own an 83% undivided interest in a third offshore pipeline, the
Omega Pipeline, which is currently inactive. The Omega Pipeline originates in the High Island
Area, East Addition Block A-173 and extends to West Cameron Block 342, where it was previously
connected to the High Island Offshore System. Reactivation of the Omega Pipeline will be
dependent upon future drilling activity in the vicinity and successfully attracting
producer/shippers to the system. |
Oil and Gas Exploration and Production Activities
Although we sold substantially all of our producing oil and gas properties in 2002, we
continue our oil and gas exploration and production activities, which include the exploration,
acquisition, development, operation and, when appropriate, disposition of oil and gas properties.
We focus our oil and gas activities in the western Gulf of Mexico off the Texas coast. We
currently own seismic and other data that may be used to evaluate and develop prospects, including
a non-exclusive license to approximately 200 blocks of 3-D seismic data covering 1,152,000 acres in
the western Gulf of Mexico and a substantial inventory of close grid 2-D seismic data. Our oil and
gas assets are held by Blue Dolphin Petroleum Company.
The leasehold interests we hold in properties are subject to royalty, overriding royalty and
interests of others.
Oil and Gas Exploration and Production Assets and Activities. The following is a
description of our oil and gas exploration and production assets and activities:
|
|
Galveston Area Block 321 Galveston Area Block 321 is located approximately 32
miles southeast of Galveston in an average water depth of approximately 66 feet. The block
contains one active well, the A-4 Well, which began production in March 2009. The well is
currently commingled in the 5,400 and 5,300 sands. Once this commingled completion
depletes, there are two upper zones up the hole with booked reserves. We own a 0.5%
overriding royalty interest in the well. The lease is operated by Maritech Resources. |
|
|
High Island Block 115 High Island Block 115 is located approximately 30 miles
southeast of Bolivar Peninsula in an average water depth of approximately 38 feet. The block
contains one active well, the B-1 ST2 Well. The well has been shut-in since August 2009 due
to production handling problems on our downstream production handling platform, High Island
Block 71. We are exploring |
6
|
|
options with the lease operator to resolve the production handling issues. We own a 2.5%
working interest in a single production zone in the well. The lease is operated by Republic
Petroleum. |
|
|
High Island Block 37 High Island Block 37 is located approximately 15 miles
south of Sabine Pass, in an average water depth of approximately 36 feet. The block contains
one active well, the A-2 Well, and one inactive well, the B-1 Well. Production from the A-2
Well was restarted in February 2009, after being shut-in as a result of Hurricane Ike. The
B-1 Well is currently shut-in following an unsuccessful workover in September 2009. We own an
approximate 2.8% working interest in this lease that covers 5,760 acres. The lease is
operated by Hilcorp Energy Company. |
Productive Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Wells |
|
|
Non-Producing Wells |
|
Region |
|
Gross Wells |
|
|
Net Wells |
|
|
Gross Wells |
|
|
Net Wells |
|
Gulf of Mexico
Oil and gas |
|
|
2.0 |
|
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2.0 |
|
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
|
|
|
|
|
|
|
|
Non-Producing Wells |
|
Region |
|
Gross Acreage |
|
|
Net Acreage |
|
Gulf of Mexico
Oil and gas |
|
|
11,520 |
|
|
|
310 |
|
|
|
|
|
|
|
|
Total |
|
|
11,520 |
|
|
|
310 |
|
|
|
|
|
|
|
|
We have no undeveloped oil and gas leases.
See Note (8), Business Segment Information, in the Notes to Consolidated Financial Statements for
additional information on revenues, operating income (loss), assets and depreciation, depletion and
amortization on our business segments.
Proved Oil and Gas Reserves. Our proved reserve estimates for oil and natural gas were
prepared by William J. Driscoll, an independent geologist, in accordance with the generally
accepted petroleum engineering and evaluation principles and most recent definitions and guidelines
established by the SEC. A copy of Mr. Driscolls summary reserve report is attached as an exhibit
to this report. All reserve definitions comply with the definitions of Rules 4-10(a)(1)-(32) of
SEC Regulation X.
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.
7
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. See Note (9), Supplemental Oil and Gas
Information, in the Notes to Consolidated Financial Statements 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.
The following table presents the estimates of proved reserves, proved developed reserves (as
hereinafter defined) and the discounted present value of future net revenues or expenses from
proved reserves after income taxes (in thousands) to our net interest in oil and gas properties as
of December 31, 2009. The discounted present value of future net revenues or expenses is
calculated using the SEC Method (defined below) and is not intended to represent the current market
value of the oil and gas reserves we own.
Proved Reserves
As of December 31, 2009(1) (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present Value |
|
|
|
|
|
|
|
|
|
|
|
of Future Net |
|
|
|
Net Oil |
|
|
Net Gas |
|
|
Cash Inflows |
|
|
|
Reserves |
|
|
Reserves |
|
|
(Outflows)(1) |
|
|
|
(Mbbls) |
|
|
(MMcf) |
|
|
(in thousands) |
|
Proved Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Galveston Area Block 321 |
|
|
0.1 |
|
|
|
4 |
|
|
$ |
19 |
|
High Island Block 115 |
|
|
0.6 |
|
|
|
112 |
|
|
|
293 |
|
High Island Block 37 |
|
|
0.1 |
|
|
|
12 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved Reserves |
|
|
0.8 |
|
|
|
128 |
|
|
$ |
336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
|
|
|
|
|
|
|
|
|
|
|
Galveston Area Block 321 |
|
|
0.1 |
|
|
|
4 |
|
|
$ |
19 |
|
High Island Block 115 |
|
|
0.6 |
|
|
|
112 |
|
|
|
293 |
|
High Island Block 37 |
|
|
0.1 |
|
|
|
12 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved Developed |
|
|
0.8 |
|
|
|
128 |
|
|
$ |
336 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The estimated present value of future net cash outflows from our proved reserves has
been determined by using prices of $61.08 per barrel of oil and $3.78 per Mcf of gas,
representing the 12-month average price for oil and natural gas, respectively,
calculated as the unweighted arithmetic average of the first-day-of-the-month price for
each month within the 12-month prior period to the end of the reporting period and
discounted at a 10% annual rate in accordance with requirements for reporting oil and
gas reserves pursuant to regulations promulgated by the Securities and Exchange
Commission (the SEC Method). |
|
(2) |
|
As of December 31, 2009, we reported no proved undeveloped reserves. |
Internal Controls over Reserve Estimates
Our policies regarding internal controls over reserve estimates require reserves to be in
compliance with the SEC definitions and guidance and for reserves to be prepared by an independent
geologist under the supervision of our President. We provide the geologist with estimate
preparation material such as property interests, production, current operation costs, current production prices and other information.
This information is reviewed by our President and Principal Financial and Accounting Officer to
ensure
8
accuracy and completeness of the data prior to submission to our third party geologist. A
letter which identifies the professional qualifications of the individual who was responsible for
overseeing the preparation of our reserve estimates as of December 31, 2009 has been filed as
Exhibit 99.1 to this report.
Capital Expenditures for Proved Reserves. The following table presents information
regarding the costs we expect to incur in activities associated with our proved reserves. These
expenditures represent costs associated with 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 (amounts in thousands).
Estimated Undiscounted Capital Expenditures
Associated with Plugging and Abandonment of Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ending December 31, |
|
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
2014 |
Galveston Area Block 321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High Island Block A-7 |
|
|
|
|
|
$ |
238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
High Island Block 37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
68 |
|
|
|
|
|
High Island Block 115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
37 |
|
Remainder of Page Intentionally Left Blank
9
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Gas: |
|
|
|
|
|
|
|
|
|
|
|
|
Production (Mcf) |
|
|
33,630 |
|
|
|
44,700 |
|
|
|
72,788 |
|
Revenue |
|
$ |
108,576 |
|
|
$ |
526,522 |
|
|
$ |
476,224 |
|
Average production per day (Mcf) (*) |
|
|
92.1 |
|
|
|
122.5 |
|
|
|
199.4 |
|
Average sales price per Mcf |
|
$ |
3.23 |
|
|
$ |
11.78 |
|
|
$ |
6.54 |
|
Condensate: |
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls) |
|
|
250 |
|
|
|
117 |
|
|
|
177 |
|
Revenue |
|
$ |
17,401 |
|
|
$ |
14,057 |
|
|
$ |
10,345 |
|
Average production per day (Bbls) (*) |
|
|
0.7 |
|
|
|
0.3 |
|
|
|
0.5 |
|
Average sales price per Bbl |
|
$ |
69.60 |
|
|
$ |
120.25 |
|
|
$ |
58.45 |
|
NGLs: |
|
|
|
|
|
|
|
|
|
|
|
|
Production (gallons) |
|
|
|
|
|
|
|
|
|
|
36,372 |
|
Revenue |
|
$ |
|
|
|
$ |
|
|
|
$ |
30,842 |
|
Average production per day (gallons) (*) |
|
|
|
|
|
|
|
|
|
|
99.7 |
|
Average sales price per gallon |
|
$ |
|
|
|
$ |
|
|
|
$ |
0.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs (**): |
|
|
|
|
|
|
|
|
|
|
|
|
Per Mcfe: |
|
$ |
2.71 |
|
|
$ |
5.36 |
|
|
$ |
3.04 |
|
(*) |
|
Average production is based on a 365 day year. |
(**) |
|
Production costs, exclusive of work-over costs, are costs incurred to operate
and maintain wells and equipment and to pay production taxes. |
Drilling Activity. There was no drilling activity in 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Exploratory(1) |
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Wells Drilled |
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico |
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
|
|
|
|
|
|
|
|
|
|
Dry |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gross interest reflects the total wells we participated in, regardless of our
ownership interest. |
10
Customers
We generated revenues from both of our business segments. Gryphon Exploration, W&T Offshore,
Helis Oil & Gas and Maritech Resources for approximately 20%, 18%, 12% and 10%, respectively, of
our revenues in 2009. Revenues from customers exceeding 10% of revenues were as follows for 2009
and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas |
|
|
Pipeline |
|
|
|
|
|
|
Sales |
|
|
Operations |
|
|
Total |
|
Year Ended December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Gryphon Exploration Co. |
|
$ |
|
|
|
$ |
379,828 |
|
|
$ |
379,828 |
|
W&T Offshore |
|
$ |
|
|
|
$ |
332,396 |
|
|
$ |
332,396 |
|
Helis Oil & Gas |
|
$ |
|
|
|
$ |
216,047 |
|
|
$ |
216,047 |
|
Maritech Resources |
|
$ |
|
|
|
$ |
191,512 |
|
|
$ |
191,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Arena Offshore |
|
$ |
|
|
|
$ |
513,634 |
|
|
$ |
513,634 |
|
W&T Offshore |
|
$ |
|
|
|
$ |
488,083 |
|
|
$ |
488,083 |
|
Gryphon Exploration Co. |
|
$ |
|
|
|
$ |
367,153 |
|
|
$ |
367,153 |
|
Apex Oil & Gas |
|
$ |
|
|
|
$ |
338,836 |
|
|
$ |
338,836 |
|
Markets & Competition
The availability of a ready market for oil and natural gas, and the prices of oil and natural
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, transshipment and other means of transportation; |
|
|
|
|
the availability and marketing of other competitive fuels; |
|
|
|
|
fluctuating and seasonal demand for oil, natural gas and refined products; and |
|
|
|
|
the extent of governmental regulation and taxation (under both present and future
legislation) of the production, importation, refining, transportation, pricing, use and
allocation of oil, gas, refined products and alternative fuels. |
In view of the many uncertainties affecting the supply and demand for crude oil, condensate,
natural gas and refined petroleum products, it is not possible to predict accurately the prices or
marketability of the oil and natural gas 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.
Vigorous competition occurs among oil, gas and other energy sources, and between producers,
transporters, and distributors of oil and gas. Our pipeline business faces competition from other
pipelines in the markets that we serve. The principal elements of competition among pipelines are
rates, terms of service, access to markets, flexibility and reliability of service. Our oil and
natural gas business competes for the acquisition of oil and natural gas properties with numerous
entities, including major oil companies, independent oil and natural gas concerns and individual
producers and operators, primarily on the basis of the price to be paid for such properties. Many
of these competitors are large, well-established companies
11
that have financial and other resources that are substantially greater than ours, which give them
an advantage over us in evaluating and obtaining properties and prospects. Our ability to acquire
additional pipelines and oil and natural gas properties and to discover reserves in the future will
depend upon our ability to evaluate and select suitable properties and consummate transactions in a
highly competitive environment. There is also competition for the hiring of experienced personnel
to manage and operate our assets. Several highly competitive alternative transportation and
delivery options exist for current and potential customers of our traditional gas and oil gathering
and transportation business. Competition also exists with other industries in supplying the energy
and fuel needs of consumers.
Governmental Regulation
The production, processing, marketing, and transportation of oil and gas by us are subject to
federal, state and local regulations which can have a significant impact upon our overall
operations.
Federal Regulation of Natural Gas Transportation. The transportation and resale of gas in
interstate commerce have been regulated by the Natural Gas Act (NGA), the Natural Gas Policy Act
(NGPA), and the rules and regulations promulgated by the Federal Energy Regulatory Commission
(FERC). In the past, the federal government has regulated the prices at which gas could be sold.
In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining NGA
and NGPA price and non-price controls affecting producer sales of gas, effective January 1, 1993.
The Energy Policy Act of 2005 did not alter our non-FERC-jurisdictional status, but has greatly
expanded FERCs authority, including enforcement authority against market manipulation in
connection with FERC-jurisdictional transactions. FERC has undertaken vigorous enforcement actions
against a number of entities, including those not subject to direct FERC regulation, and, to
increase transparency in natural gas markets, has taken steps to require reporting by interstate,
major non-interstate and potentially certain intrastate pipelines. Additionally, energy pricing has
attracted renewed political interest. Thus Congress could reenact regulatory controls in the
future. The rates, terms and conditions applicable to interstate transportation of gas by
pipelines are regulated by FERC under the NGA, as well as under Section 311 of the NGPA. In
February 2007, FERC issued a policy order acknowledging its lack of jurisdiction over offshore
gathering, but stating that FERC would intervene in the event that interstate pipelines with
affiliated offshore gathering lines engage in anticompetitive behavior, such conditioning access to
interstate pipeline service upon use of the affiliated gathering line.
All of our pipelines located offshore in federal waters are subject to the requirements of the
Outer Continental Shelf Lands Act (OCSLA). FERC has stated that non-jurisdictional gathering
lines, as well as interstate pipelines, are fully subject to the open access and nondiscrimination
requirements of OCSLAs Section 5, which generally authorizes 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. 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 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.
12
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, FERC and/or various state
agencies. In addition, the OCSLA authorizes regulations relating to safety and environmental
protection applicable to leases and permittees operating on the OCS. Specific design and
operational standards may apply to OCS vessels, rigs, platforms and structures. Violations of
lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations and the
cancellation of leases. Such enforcement liabilities can result from either governmental or
private prosecution. Currently, we believe that we are in material compliance with the various
safety and operational regulations that we are subject to. However, as safety and operational
regulations are frequently changed, we are unable to predict the future effect changes in these
regulations will have on our operations, if any.
Federal Oil and Gas Leases. All of our exploration and production operations are currently
located on federal oil and gas leases in the OCS, which are administered by the MMS. Such leases
are issued through competitive bidding, contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA that are subject to
interpretation and change by the MMS. For offshore operations, lessees must obtain MMS approval
for exploration plans and development and production plans prior to the commencement of such
operations. In addition to permits required from other agencies such as the Coast Guard, the Army
Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the
MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore
production facilities located on the OCS to meet stringent engineering and construction
specifications. To cover the various obligations of lessees on the OCS, the MMS generally requires
that lessees have substantial net worth or post bonds or other acceptable assurance that such
obligations will be met. The cost of these bonds or other surety can be substantial, and there is
no assurance that bonds or other surety can be obtained in all cases. We are currently in
compliance with the bonding requirements of the MMS. Under some circumstances, the MMS may require
any of our operations on federal leases to be suspended or terminated. Any such suspension or
termination could materially adversely affect our financial condition and results of operations.
With respect to our operations conducted on offshore federal leases, liability may generally be
imposed under OCSLA for costs of clean-up and damages caused by pollution resulting from such
operations, other than damages caused by acts of war or the negligence of third parties. Under
certain circumstances, including but not limited to conditions deemed a threat or harm to the
environment, the MMS may also require any of our operations on federal leases to be suspended or
terminated in the affected area. Furthermore, the MMS generally requires that offshore facilities
be dismantled and removed within one year after production ceases or the lease expires.
Environmental Regulation. Our activities with respect to (1) exploration, development and
production of oil and natural gas and (2) the operation and construction of pipelines, plants, and
other facilities for the transportation and processing, and storage of oil and natural gas are
subject to stringent environmental regulation by local, state and federal authorities, including
the U.S. Environmental Protection Agency (the 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 effect 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.
13
The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) imposes
liability, without regard to fault or the legality of the original conduct, on responsible parties
with respect to the release or threatened release of a hazardous substance into the environment. Responsible
parties, which include the present owner or operator of a site where the release occurred, the
owner or operator of the site at the time of disposal of the hazardous substance, and persons that
disposed or arranged for the disposal of a hazardous substance at the site, are liable for response
and remediation costs and for damages to natural resources. Petroleum and natural gas are excluded
from the definition of hazardous substances; however, this exclusion does not apply to all
materials used in our operations. At this time, neither we nor any of our predecessors have been
designated as a potentially responsible party under CERCLA.
The federal Resource Conservation and Recovery Act (RCRA) and its state counterparts regulate
solid and hazardous wastes and impose civil and criminal penalties for improper handling and
disposal of such wastes. EPA and various state agencies have promulgated regulations that limit
the disposal options for such wastes. Certain wastes generated by our oil and gas operations are
currently exempt from regulation as hazardous wastes, but in the future could be designated as
hazardous wastes under RCRA or other applicable statutes and therefore may become subject to more
rigorous and costly requirements.
We currently own or lease, or have in the past owned or leased, various properties used for the
exploration and production of oil and gas or used to store and maintain equipment regularly used in
these operations. Although our past operating and disposal practices at these properties were
standard for the industry at the time, hydrocarbons or other substances may have been disposed of
or released on or under these properties or on or under other locations. In addition, many of
these properties have been operated by third parties whose waste handling activities were not under
our control. These properties and any waste disposed thereon may be subject to CERCLA, RCRA, and
state laws which could require us to remove or remediate wastes and other contamination or to
perform remedial plugging operations to prevent future contamination.
The Oil Pollution Act of 1990 (OPA) and regulations promulgated thereunder include a variety of
requirements related to the prevention of oil spills and impose liability for damages resulting
from such spills. OPA imposes liability on owners and operators of onshore and offshore facilities
and pipelines for removal costs and certain public and private damages arising from a spill. OPA
establishes a liability limit for onshore facilities of $350 million and for offshore facilities of
all removal costs plus $75 million, and lesser liability limits for vessels depending upon their
size. A party cannot take advantage of the liability limits if the spill is caused by gross
negligence or willful misconduct or resulted from a violation of federal safety, construction, or
operating regulations. If a party fails to report a spill or cooperate in the cleanup, liability
limits likewise do not apply. OPA imposes ongoing requirements on responsible parties, including
proof of financial responsibility for potential spills. The amount of financial responsibility
required depends upon a variety of factors including the type of facility or vessel, its size,
storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of
discharges, worst-case spill potential and other factors. We believe we have established adequate
financial responsibility. While the financial responsibility requirements under OPA may be amended
to impose additional costs on us, the 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
14
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
ground waters. We believe we are in substantial compliance with the requirements of the CWA, OPA,
and state laws, and that any non-compliance would not have a material adverse effect on us.
Various federal and state programs regulate the conservation and development of coastal resources.
The federal Coastal Zone Management Act was passed to preserve and, where possible, restore the
natural resources of the coastal zone of the United States of America and to provide for federal
grants for state management programs that regulate land use, water use and coastal development.
Under the Louisiana Coastal Zone Management Program, coastal use permits are required for certain
activities, even if the activity only partially infringes on the coastal zone. Among other things,
projects involving use of state lands and water bottoms, dredge or fill activities that intersect
with more than one body of water, mineral activities, including the exploration and production of
oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other
minerals require such permits. General permits, which entail a reduced administrative burden, are
available for a number of routine oil and gas activities. The Texas Coastal Coordination Act
(CCA) establishes the Texas Coastal Management Program that applies in the nineteen Texas
counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review of
state and federal agency rules and agency actions for consistency with the goals and policies of
the Coastal Management Plan. These coastal programs may affect agency permitting of our
facilities.
Legislation and Rulemaking. In October 1996, the U.S. Congress enacted the Coast Guard
Authorization Act of 1996 (P.L. 104-324) which amended the OPA to establish requirements for
evidence of financial responsibility for certain offshore facilities. The amount required is $35
million for certain types of offshore facilities located seaward of the seaward boundary of a
state, including properties used for oil transportation. We currently maintain this statutory $35
million coverage.
Federal and state legislative rules and regulations are pending that, if enacted, could
significantly affect the oil and gas industry. It is impossible to predict which of those federal
and state proposals and rules, if any, will be adopted and what effect, if any, they would have on
our operations.
In addition, various federal, state and local laws and regulations covering the discharge of
materials into the environment, occupational health and safety issues, or otherwise relating to the
protection of public health and the environment, may affect our operations, expenses and costs.
The trend in such regulation has been to place more restrictions and limitations on activities that
may impact the general or work environment, such as emissions of pollutants, generation and
disposal of wastes, and use and handling of chemical substances. It is not anticipated that, in
response to such regulation, we will be required in the 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.
Employees
We have six (6) full-time employees and regularly use the services of two (2) consultants. Our
employees, along with the engineering and geological expertise provided by our consultants,
supervise and coordinate the operation and administration of our oil and gas properties, pipelines
and other assets. From time to time, major maintenance, engineering and construction projects are
contracted to third-party engineering and service companies.
15
Environmental
A description of our environmental activities is included in Part II, Item 8, Financial
Statements and Supplementary Data.
Executive Officers of the Registrant
Our executive officers as of April 15, 2010 are listed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Officer |
|
|
Name |
|
Office |
|
Since |
|
Age |
Ivar Siem
|
|
Chairman of the Board and Chief Executive Officer
|
|
|
1989 |
|
|
|
63 |
|
Thomas W. Heath
|
|
President, Secretary and Assistant Treasurer
|
|
|
2007 |
|
|
|
47 |
|
T. Scott Howard
|
|
Treasurer and Assistant Secretary
|
|
|
2008 |
|
|
|
38 |
|
Ivar Siem, has served as Chairman of the Board of Directors of the Company
since 1989 and was appointed as Chief Executive Officer in 2004. Since 2000,
he has also served as Chairman of the Board of Directors and Chief Executive
Officer of Drillmar Energy Inc., a subsidiary of which filed for Chapter 11
bankruptcy reorganization in November 2009. From 1995 to 2000, he served as
Chairman and director and interim President of DI Industries, which later
became Grey Wolf, Inc. From 1996 to 1997, Mr. Siem also served as Chief
Executive Officer of Seateam Technology ASA. From 1981 to 1995, Mr. Siem was an
international consultant to companies in the energy, technology and finance
industries. From 1974 to 1981, Mr. Siem held a variety of progressively
responsible management positions within the Fred. Olsen group of companies,
including President of Dolphin International, Inc. until it was sold in 1981.
Mr. Siem began his career as a petroleum engineer for Amoco Corporation. He
currently serves or has previously served on the Boards of Directors of several
public and privately-held companies, including Avenir ASA, The Classical
Theatre, Frupor SA, TI A/S, Siem Industries, Inc. and two of its affiliates.
Mr. Siem holds a Bachelor of Science in Mechanical Engineering from the
University of California, Berkeley, and has completed an executive MBA program
at Amos Tuck School of Business, Dartmouth University.
Thomas W. Heath was appointed as President and Secretary of the Company in
2009, having previously served as Executive Vice President since 2007. From
2004 to 2007 he served as a Vice President of Union Bank of California, N.A.,
an affiliate of Bank of Tokyo-Mitsubishi UFJ, Ltd., where he developed and
implemented an energy derivatives desk supporting Energy Capital Services.
From 1988 to 2004 Mr. Heath held a variety of management and executive level
positions with the evolving marketing units of Acadian Gas Pipeline System,
Coral Energy, L.P. (formerly Shell Trading Gas & Power), Sempra Energy Trading
Corp. and Tejas Gas Corporation. Mr. Heath began his career in 1983 with
Columbia Gulf Transmission Company where he served in various operational and
commercial positions until 1988. He is an alumnus of the University of
Houston.
T. Scott Howard was appointed as Treasurer of the Company in 2009 and Assistant
Secretary of the Company in April 2008. He joined the Company as Accounting
Manager in 2006. From 1996 to 2006 he held a variety of management level
positions: Audit Manager with DRDA, P.C., an independent public accounting firm
in Houston, Texas from 2002 to 2006, Trust Officer with Frost National Bank in
Houston, Texas from 2000 to 2002 and Controller for Halls Insurance Agency,
Inc. in Dickinson, Texas from 1996 to 2000. He began his career as a Staff
Accountant for Griffin, Iles, Masel & Duval, LLP, a public accounting firm,
where he was employed from 1994 to 1996. Mr. Howard, who is a Certified Public
Accountant in Texas, received his Bachelor of Business Administration in
Accounting from St. Edwards University.
16
Available Information
We make available, free of charge on or through our website (http://www.blue-dolphin.com), our
annual, quarterly and current reports, and any amendments to those reports, as soon as is
reasonably possible after these reports are filed with the Securities and Exchange Commission
(SEC). Information about each of our Board members, as well as each of our Boards standing
committee charters, our Corporate Governance Guidelines and our Code of Business Conduct are also
available, free of charge, through our website. Information contained on our website is not part
of this report.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and
gas industry.
Back-in After Payout Interest. A contractual right of a non-participating partner to participate
in a well or wells after the wells have produced enough for the participating partners to recover
their capital costs of drilling, completing, and operating the wells.
Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other
liquid hydrocarbons.
Bcf. One billion cubic feet of gas.
Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound
of water by one degree Fahrenheit.
Condensate. Liquid hydrocarbons associated with the production of a primarily gas reserve.
Development Well. A well drilled within the proved area of a gas or oil reservoir to the depth of
a stratigraphic horizon known to be productive.
Exploratory Well. A well drilled to find and produce gas or oil in an unproved area, to find a new
reservoir in a field previously found to be productive of gas or oil in another reservoir or to
extend a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related
to the same individual geological structural feature and/or stratigraphic condition.
Leasehold Interest. The interest of a lessee under an oil and gas lease.
Mbbls. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one
barrel of oil, condensate or gas liquids.
MMbtu. One million British Thermal Units.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl
of oil, condensate or gas liquids.
17
Net Revenue Interest. The percentage of production to which the owner of a working interest is
entitled.
Non-operating 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 Interest. 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, which include shut-in
and behind pipe reserves. Shut-in reserves are expected to be recovered from: (i) completion
intervals which are open at the time of the estimate but which have not started producing, (ii)
wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or
(iii) wells not capable of producing for mechanical reasons.
Proved Reserves. The estimated quantities of oil, gas and condensate that geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells or from
existing wells where a relatively significant 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.
Risks Related to our Business
Based on our historical financials, there is uncertainty as to our ability to continue as a going
concern.
We incurred a net loss of $4,136,892 for the year ended December 31, 2009, and a net loss of
$1,966,240 for the year ended December 31, 2008. We have not had a profitable year since 2006. As
of December 31, 2009, we had an accumulated deficit of $30,107,651. We anticipate that we will
continue to incur substantial operating losses and may require additional financing in the
foreseeable future. These matters raise substantial doubt as to our ability to continue as a going
concern. Existing and anticipated working
18
capital needs, lower than anticipated revenues, increased expenses or the inability to collect on
an outstanding Loan to the Borrower could all affect our ability to continue as a going concern.
As described in the report of our independent registered public accounting firm and in Note (1),
Organization and Significant Accounting Policies, in the Notes to Consolidated Financial
Statements included in this annual report, these circumstances raise substantial doubt about our
ability to continue as a going concern. Our consolidated financial statements, which have been
prepared in accordance with generally accepted accounting principles (GAAP), contemplate that we
will continue as a going concern and do not contain any adjustments that might result if we were
unable to continue as a going concern. This report may make it more difficult for us to raise
additional capital necessary to operate our business.
If the $2.0 million loan receivable remains unpaid, we could deplete our cash reserves by the end
of the third quarter of this year.
On July 31, 2009, we issued a Loan to the Borrower. The Loan, which was due on January 31, 2010,
is secured by (i) a first lien on property owned by LEN, (ii) a second lien on property owned by
LLRII and (iii) a guarantee from LEH. We agreed to forbear the loan receivable until June 11,
2010, provided the Borrower satisfies certain conditions set forth in the forbearance agreement.
Those certain conditions were not met, and on April 9, 2010, we called on the full value of the
Loan to be paid by April 13, 2010. As of the date of this report, the Loan is in default and
remains unpaid. However, management believes the Loan will be paid at a date in the future.
Management is currently pursuing a plan that would include selling the note to a third party. In
addition, management plans to begin the necessary steps associated with collection on the
collateral. Although this may take time, management feels the Company will recover the full amount
of the Loan through this process.
Our cash flow projections suggest that, should the Loan remain unpaid, we could deplete our cash
reserves by the end of the third quarter of this year.
We are primarily dependent on revenues from our pipeline systems and our working interests in three
oil and gas producing properties.
For the year ended December 31, 2009, approximately 94% of our revenues were derived from our
pipeline operations and the limited amount of reserves on properties we currently own interests in.
We expect that our future revenues will continue to be primarily dependent on the level of use of
our pipeline systems. Various factors can influence the level of use of our pipeline systems,
including the success of drilling programs in the areas near our pipelines and our ability to
attract new producer/shippers. There are various pipelines in and around our pipeline systems that
we vigorously compete with to attract new producer/shippers to our pipeline systems. There can be
no assurance that we will be successful in attracting new producer/shippers to our pipeline
systems.
The rate of production from oil and gas properties generally declines as reserves are depleted.
Our working interests are in properties in the Gulf of Mexico where, generally, the rate of
production declines more rapidly than in many other producing areas of the world. As the level of
production from these properties continues to decline, our revenue from oil and gas sales will
decrease. Revenues from oil and gas sales accounted for approximately 6% of our total revenues in
2009 and 18% in 2008. Unless we are able to replace production revenue with revenue from interests
in other oil and gas properties, increase the level of utilization of our pipelines or acquire
other revenue generating assets at an acceptable cost, our revenues and cash flow from operations
will decrease and our financial condition will be materially adversely affected.
19
A significant decrease in exploration and production activity in areas where our pipelines are, the
decline in production from existing wells, depressed commodity prices or otherwise, would adversely
affect our revenues and cash flow.
The profitability of our pipeline operations is materially impacted by the volume of throughput. A
material decrease in production in our areas of operation would result in a further decline in our
throughput volumes. We have no control over many factors affecting production activity, including
prevailing and projected commodity prices, demand for oil and gas, the level of reserves,
geological considerations, governmental regulation and the availability and cost of capital. The
level of throughput on our pipelines is significantly below maximum capacity. Failure to connect
new wells to our pipelines would result in the amount of throughput being reduced further over
time. Our ability to connect to new wells will be dependent on the level of drilling activity in
our areas of operations, the success of that drilling activity and competitive market factors. The
effect of any decrease in the throughput handled by our pipelines would reduce our revenues and
operating income.
If we are not able to generate sufficient funds from our operations and other financing sources, we
may not be able to finance our operations.
In the past three years, we have used a portion of our cash reserves to fund our working capital
requirements that were not funded from operations.
Continued underutilization of our pipelines, low commodity prices, production problems, declines in
production, disappointing drilling results and other factors beyond our control could further
reduce our funds from operations. Additionally, we project that our current cash reserves will be
sufficient to meet our obligations through the third quarter of this year. As a result we may have
to seek debt and equity financing to meet our working capital requirements. Our history of losses
may affect our ability to raise additional capital, or increase the cost of obtaining financing.
In addition, additional capital at acceptable terms may not be available to us in the future. In
the event we are not able to raise additional capital, we may be forced to sell some, or all, of
our assets at unfavorable terms or on an untimely basis.
The global financial crisis may have impacts on our business and financial condition that we
currently cannot predict.
The continued credit crisis and related turmoil in the global financial system may have an impact
on our business and our financial condition, and we may face challenges if conditions in the
financial markets do not improve. Our ability to access the capital markets may be restricted at a
time when we would like, or need, to raise capital, which could have an impact on our financial
condition. Additionally, the current economic situation could lead to reduced demand for oil and
natural gas, or lower prices for oil and natural gas, or both, which could have a negative impact
on our revenues.
If our common stock fails to meet the listing requirements of NASDAQ and is delisted from trading
on the NASDAQ, the market price of our common stock could be adversely affected.
Our common stock is currently listed on the NASDAQ Capital Market under the symbol BDCO. The
NASDAQs listing requirements include a requirement that, for continued listing, an issuers common
shares trade at a minimum bid price of $1.00 per share. This requirement is deemed breached when
the bid price of an issuers common shares closes below $1.00 per share for 30 consecutive trading
days. On September 16, 2009, we were notified by the NASDAQ Listing Qualifications Department
(Listing Qualifications) that our shares failed to meet the requirement for the specified time
period and they could initiate steps to delist our common stock from trading on the NASDAQ anytime
after March 15, 2010, unless our closing bid price exceeds $1.00 per share for at least 10
consecutive trading days prior to that date. As a result of not regaining compliance within the
specified compliance period, on March 16, 2010 Listing Qualifications notified us that, unless we
requested a hearing before the Panel to appeal Listing Qualifications delisting determination, our
common stock would be suspended from trading and cease
20
being listed on the NASDAQ Capital Market on March 25, 2010. We timely requested a hearing before
the Panel, which stayed the delisting determination, pending a final written decision by the Panel.
There can be no assurance that we will be successful in maintaining our listing on NASDAQ or the
trading market for our common stock. A delisting of our common stock from the NASDAQ could
adversely affect the liquidity of the trading market for our stock and therefore the market price
of our common stock. If NASDAQ determines to delist our common stock and our common stock is not
eligible for quotation on another market or exchange, trading of ours common stock could be
conducted in the over-the-counter market or on an electronic bulletin board established for
unlisted securities such as the Pink Sheets or the OTC Bulletin Board. In such event, it could
become more difficult to dispose of, or obtain accurate quotations for the price of our common
stock, and there would likely also be a reduction in our coverage by security analysts and the news
media, which could cause the price of our common stock to decline further. If an active trading
market for our common stock is not sustained, it will be difficult for our shareholders to sell
shares of our common stock without further depressing the market price of our common stock or at
all. A delisting of our common stock also could make it more difficult for us to obtain financing
for the continuation of our operations.
The geographic concentration of our assets may have a greater effect on us as compared to other
companies.
All of our assets are located in the Western Gulf of Mexico and the onshore Gulf Coast of Texas.
Because our assets are not as diversified geographically as many of our competitors, our business
is subject to local conditions more than other, more geographically diversified companies. Any
regional event, including price fluctuations, natural disasters and restrictive regulations that
increase costs may adversely impact our business more than if our assets were geographically
diversified.
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 extremely volatile
natural gas prices, and this volatility in natural gas prices is expected to continue. Our
revenues, profitability, operating cash flow and our potential for growth are largely dependent on
prevailing oil and natural gas prices. Prices for oil and natural gas are subject to large
fluctuations in response to relatively minor changes in the supply and demand for oil and natural
gas, uncertainties within the market and a variety of other factors beyond our control. These
factors include:
|
|
|
weather conditions in the United States; |
|
|
|
|
the condition of the United States economy; |
|
|
|
|
the actions of the Organization of Petroleum Exporting Countries; |
|
|
|
|
governmental regulation; |
|
|
|
|
political stability in the Middle East, South America and elsewhere; |
|
|
|
|
the foreign supply of oil and natural gas; |
|
|
|
|
the price of foreign imports; |
|
|
|
|
the availability of alternate fuel sources; and |
|
|
|
|
the value of the U.S. dollar in relation to other currencies. |
In addition, low or declining oil and natural 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. |
21
We face strong competition from larger companies that may negatively affect our ability to carry on
operations.
We operate in a highly competitive industry. Our competitors include major integrated oil
companies, substantial independent energy companies, affiliates of major interstate and intrastate
pipelines and national and local gas gatherers, many of which possess greater financial and other
resources than we do. Our ability to successfully compete in the marketplace is affected by many
factors including:
|
|
|
most of our competitors have greater financial resources than we do, which gives them
better access to capital to acquire assets; and |
|
|
|
|
we sometimes establish a higher standard for the minimum projected rate of return on
invested capital than some of our competitors since we cannot afford to absorb certain
risks. We believe this puts us at a competitive disadvantage in acquiring pipelines and
oil and gas properties. |
Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material
inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net
present value of our reserves to be overstated.
Estimating reserves of oil and gas is complex. The process relies on interpretations of available
geologic, geophysical, engineering and production data. The extent, quality and reliability of
this data can vary. The process also requires certain economic assumptions, some of which are
mandated by the SEC regarding oil and natural gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function
of:
|
|
|
the quality and quantity of available data; |
|
|
|
|
the interpretation of that data; |
|
|
|
|
the accuracy of various mandated economic assumptions; and |
|
|
|
|
the judgment of the persons preparing the estimate. |
The proved reserve information set forth in this report is based on estimates we prepared.
Estimates prepared by others might differ materially from our estimates.
Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices,
taxes, development expenditures, abandonment costs and operating expenses most likely will vary
from our estimates. Any significant variance could materially affect the quantities and net present
value of our reserves. In addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development and prevailing oil and gas prices. Our
reserves also may be susceptible to drainage by operators on adjacent properties.
The present value of future net cash flows will most likely not equate to the current market value
of our estimated proved oil and gas reserves. In accordance with SEC requirements, we base the
estimated discounted future net cash flows from proved reserves on the historical 12-month average
price (based on the first of the month pricing for the most recently ended fiscal year) and costs
in effect at December 31, 2009. Actual future prices and costs may be materially different from the
prices and costs we used.
We cannot control the activities on properties we do not operate.
Currently, other companies operate or control the development of the oil and gas properties in
which we have an interest. As a result, we depend on the operator of the wells or leases to
properly conduct lease acquisition, drilling, completion and production operations. The failure of
an operator, or the drilling contractors and other service providers selected by the operator to
properly perform services, or an operators failure to act in ways that are in our best interest,
could adversely affect us, including the amount and timing of revenues, if any, we receive from our
interests.
22
We own and generally anticipate that we will continue to own substantially less than a 50% working
interest in our oil and gas prospects and properties 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, decisions affecting our interest could be made by the owners of a majority of the working interest. For
instance, if we are unwilling or unable to participate in the costs of operations approved by
owners of a majority of the working interests in a well, our working interest in the well (and
possibly other wells on the property) 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; |
|
|
|
|
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.
Operating hazards, including those specific to the marine environment, may adversely affect our
ability to conduct business.
Our operations are subject to inherent risks normally associated with those operations, such as:
|
|
|
pipeline ruptures; |
|
|
|
|
sudden violent expulsions of oil, gas and mud while drilling a well, commonly referred
to as a blowout; |
|
|
|
|
a cave in and collapse of the earths structure surrounding a well, commonly referred to
as cratering; |
|
|
|
|
explosions; |
|
|
|
|
fires; |
|
|
|
|
pollution; and |
|
|
|
|
other environmental risks. |
If any of these events were to occur, we could suffer substantial losses from injury and loss of
life, damage to and destruction of property and equipment, pollution and other environmental damage
and suspension of operations. Our offshore operations are also subject to a variety of operating
risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions
and more extensive governmental regulation. These regulations may, in certain circumstances,
impose strict liability for pollution damage or result in the interruption or termination of
operations.
23
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 employers
liability and comprehensive general liability. Amounts over base coverages are provided by primary
and excess umbrella liability policies. We also maintain operators extra expense coverage, which
covers the control of drilled or producing wells as well as re-drilling expenses and pollution
coverage for wells out of control.
We may not be able to maintain adequate insurance in the future at rates we consider reasonable or
losses may exceed the maximum coverage amounts under our insurance policies. We do not maintain
property insurance coverage on our pipelines. If a significant event that is not fully insured or
indemnified against occurs, it could materially and adversely affect our financial condition and
results of operations.
Business requires the retention and recruitment of a skilled workforce and the loss of employees
could result in the failure to implement our business plan.
We currently have six (6) full-time employees and regularly use the services of two (2)
consultants, both of whom are former employees. Success within our existing two business segments
pipeline operations and activities and oil and gas exploration and production activities will
depend largely upon the efforts of certain of our executive officers, one of which has been
employed by us since the early stages of our business, and continued access to the two (2)
consultants we use regularly, both of whom are also former employees with a long history with the
Company. The loss of services of any one of these individuals could seriously harm our business
opportunities and prospects. Given our small size, our success also depends on the recruitment and
retention of qualified personnel in key areas. We may not be able to attract and retain required
personnel on acceptable terms due to the competition for experienced personnel from other companies
in the industry.
Compliance with environmental and other government regulations could be costly and could negatively
impact our operations.
Our operations are subject to numerous laws and regulations governing the discharge of materials
into the environment or otherwise relating to environmental protection. These laws and regulations
may:
|
|
|
require the acquisition of a permit before operations can be commenced; |
|
|
|
|
restrict the types, quantities and concentration of various substances that can be
released into the environment from drilling and production activities; |
|
|
|
|
limit or prohibit drilling and pipeline activities on certain lands lying within
wilderness, wetlands and other protected areas; |
|
|
|
|
require remedial measures to mitigate pollution from former operations, such as plugging
abandoned wells and abandoning pipelines; and |
|
|
|
|
impose substantial liabilities for pollution resulting from our operations. |
The recent trend toward stricter standards in environmental legislation and regulation is likely to
continue. The enactment of stricter legislation or the adoption of stricter regulations could have
a significant impact on our operating costs, as well as on the oil and gas industry in general.
Our operations could result in liability for personal injuries, property damage, oil spills,
discharge of hazardous materials, remediation and clean-up costs and other environmental damages.
We could also be liable for environmental damages caused by previous property owners. As a result,
substantial liabilities to third parties or governmental entities may be incurred which could have
a material adverse effect on our financial condition and results of operations. We maintain
insurance coverage for our operations, including limited coverage for sudden
24
and accidental environmental damages, but we do not believe that insurance coverage for all environmental damages
that occur over time or complete coverage for sudden and accidental environmental damages is
available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue to operate 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.
|
|
|
ITEM 1B. |
|
UNRESOLVED STAFF COMMENTS |
None.
ITEM 2. PROPERTIES
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 April 30, 2017.
Our average annual lease payment under this lease is approximately $108,000.
|
|
|
ITEM 3. |
|
LEGAL PROCEEDINGS |
We are a party to litigation that is incidental to our business; however, neither we nor any
of our property is subject to any material pending legal proceedings.
PART II
|
|
|
ITEM 5. |
|
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES |
Market Price for Common Stock
Our common stock is quoted on the NASDAQ Capital Market under the ticker symbol BDCO. As of
April 14, 2010, we had 492 stockholders of record. Based on information collected with respect to
our annual meeting of stockholders held on May 14, 2009, we estimate that there are approximately
2,000 beneficial holders of our common stock.
Remainder of Page Intentionally Left Blank
25
The following table sets forth, for the periods indicated, the high and low prices for our common
stock as reported by NASDAQ. NASDAQ quotations reflect inter-dealer prices, without adjustment for
retail mark-ups, markdowns or commissions and may not represent actual transactions.
|
|
|
|
|
|
|
|
|
Quarter Ended |
|
High |
|
Low |
2009 |
|
|
|
|
|
|
|
|
December 31, 2009 |
|
$ |
0.62 |
|
|
$ |
0.29 |
|
September 30, 2009 |
|
$ |
0.58 |
|
|
$ |
0.39 |
|
June 30, 2009 |
|
$ |
0.79 |
|
|
$ |
0.36 |
|
March 31, 2009 |
|
$ |
0.45 |
|
|
$ |
0.26 |
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
December 31, 2008 |
|
$ |
0.85 |
|
|
$ |
0.32 |
|
September 30, 2008 |
|
$ |
2.20 |
|
|
$ |
0.75 |
|
June 30, 2008 |
|
$ |
2.57 |
|
|
$ |
1.25 |
|
March 31, 2008 |
|
$ |
1.95 |
|
|
$ |
1.15 |
|
On March 16, 2010, we were notified by NASDAQ that our common stock is subject to delisting for
failure to comply with the minimum bid price listing requirement. We requested, and were granted,
a hearing before the Panel to appeal the delisting determination. Our common stock will continue
to be listed and traded on the NASDAQ Capital Market until the Panel renders a written decision on
the matter.
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. We expect that any
loan agreements we 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 will also be
dependent upon the cash flow of our subsidiaries.
Remainder of Page Intentionally Left Blank
26
Compensation Plan Information
The following table provides information for all equity compensation plans as of the fiscal
year ended December 31, 2009, under which our equity securities were authorized for issuance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
|
|
|
|
|
Securities |
|
|
|
Number of |
|
|
|
|
|
|
Remaining Available |
|
|
|
Securities to be |
|
|
|
|
|
|
for Future Issuance |
|
|
|
Issued Upon |
|
|
Weighted Average |
|
|
Under Equity |
|
|
|
Exercise of |
|
|
Exercise Price of |
|
|
Compensation Plans |
|
|
|
Outstanding |
|
|
Outstanding |
|
|
(Excluding |
|
|
|
Options, Warrants |
|
|
Options, Warrants |
|
|
Securities |
|
|
|
and Rights |
|
|
and Rights |
|
|
Reflected in Column (a)) |
|
Plan Category |
|
(a) |
|
|
(b) |
|
|
(c) |
|
Equity compensation plans approved by
security holders |
|
|
424,559 |
|
|
$ |
2.53 |
|
|
|
351,040 |
|
Equity compensation plans not approved
by security holders |
|
|
|
|
|
$ |
0.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
424,559 |
|
|
$ |
2.53 |
|
|
|
351,040 |
|
|
|
|
|
|
|
|
|
|
|
Remainder of Page Intentionally Left Blank
27
Item 6. SELECTED FINANCIAL DATA
Financial information by quarter is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ended |
|
|
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
|
Total |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operations |
|
$ |
514,759 |
|
|
$ |
548,636 |
|
|
$ |
442,249 |
|
|
$ |
361,327 |
|
|
$ |
1,866,971 |
|
Oil and gas sales |
|
|
21,946 |
|
|
|
44,075 |
|
|
|
42,269 |
|
|
|
17,687 |
|
|
|
125,977 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from operations |
|
|
536,705 |
|
|
|
592,711 |
|
|
|
484,518 |
|
|
|
379,014 |
|
|
|
1,992,948 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operating expenses |
|
|
466,260 |
|
|
|
491,461 |
|
|
|
309,695 |
|
|
|
247,946 |
|
|
|
1,515,362 |
|
Lease operating expenses |
|
|
48,031 |
|
|
|
674 |
|
|
|
29,731 |
|
|
|
16,705 |
|
|
|
95,141 |
|
Depletion, depreciation and amortization |
|
|
128,913 |
|
|
|
134,227 |
|
|
|
133,362 |
|
|
|
120,840 |
|
|
|
517,342 |
|
Impairment of oil and gas properties |
|
|
203,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
203,110 |
|
Allowance
for doubtful note receivable, net of consulting agreement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
General and administrative expenses |
|
|
602,194 |
|
|
|
650,754 |
|
|
|
372,159 |
|
|
|
364,925 |
|
|
|
1,990,032 |
|
Stock based compensation |
|
|
62,644 |
|
|
|
40,320 |
|
|
|
62,562 |
|
|
|
39,320 |
|
|
|
204,846 |
|
Accretion expense |
|
|
27,918 |
|
|
|
27,919 |
|
|
|
27,586 |
|
|
|
27,420 |
|
|
|
110,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of operations |
|
|
1,539,070 |
|
|
|
1,345,355 |
|
|
|
935,095 |
|
|
|
2,317,156 |
|
|
|
6,136,676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense),
including income tax expense |
|
|
2,356 |
|
|
|
2,395 |
|
|
|
129,191 |
|
|
|
(127,106 |
) |
|
|
6,836 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(1,000,009 |
) |
|
$ |
(750,249 |
) |
|
$ |
(321,386 |
) |
|
$ |
(2,065,248 |
) |
|
$ |
(4,136,892 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
|
$ |
(0.09 |
) |
|
$ |
(0.06 |
) |
|
$ |
(0.03 |
) |
|
$ |
(0.17 |
) |
|
$ |
(0.35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operations |
|
$ |
547,817 |
|
|
$ |
695,402 |
|
|
$ |
561,171 |
|
|
$ |
644,441 |
|
|
$ |
2,448,831 |
|
Oil and gas sales |
|
|
130,720 |
|
|
|
293,553 |
|
|
|
120,108 |
|
|
|
(3,802 |
) |
|
|
540,579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from operations |
|
|
678,537 |
|
|
|
988,955 |
|
|
|
681,279 |
|
|
|
640,639 |
|
|
|
2,989,410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline operating expenses |
|
|
415,956 |
|
|
|
402,096 |
|
|
|
415,581 |
|
|
|
489,009 |
|
|
|
1,722,642 |
|
Lease operating expenses |
|
|
50,173 |
|
|
|
83,094 |
|
|
|
40,710 |
|
|
|
69,473 |
|
|
|
243,450 |
|
Depletion, depreciation and amortization |
|
|
131,338 |
|
|
|
117,690 |
|
|
|
164,689 |
|
|
|
114,255 |
|
|
|
527,972 |
|
Impairment of oil and gas properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
213,563 |
|
|
|
213,563 |
|
General and administrative expenses |
|
|
561,625 |
|
|
|
489,364 |
|
|
|
426,342 |
|
|
|
476,165 |
|
|
|
1,953,496 |
|
Stock based compensation |
|
|
72,184 |
|
|
|
72,184 |
|
|
|
75,222 |
|
|
|
78,685 |
|
|
|
298,275 |
|
Accretion expense |
|
|
28,576 |
|
|
|
26,733 |
|
|
|
26,356 |
|
|
|
26,355 |
|
|
|
108,020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of operations |
|
|
1,259,852 |
|
|
|
1,191,161 |
|
|
|
1,148,900 |
|
|
|
1,467,505 |
|
|
|
5,067,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense),
including income tax expense |
|
|
55,941 |
|
|
|
26,727 |
|
|
|
24,884 |
|
|
|
4,216 |
|
|
|
111,768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(525,374 |
) |
|
$ |
(175,479 |
) |
|
$ |
(442,737 |
) |
|
$ |
(822,650 |
) |
|
$ |
(1,966,240 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
|
$ |
(0.05 |
) |
|
$ |
(0.02 |
) |
|
$ |
(0.04 |
) |
|
$ |
(0.07 |
) |
|
$ |
(0.17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
ITEM 7. MANAGEMENTS 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 Item 1, BUSINESS, and Item 8, Financial
Statements and Supplementary Data Notes to Consolidated Financial Statements.
Executive Summary
We are engaged in two lines of business: (i) pipeline transportation services to
producer/shippers, and (ii) oil and gas exploration and production. Our assets are located
offshore and onshore in the Texas Gulf Coast area. Our goal is to create greater long-term value
for our stockholders by increasing the utilization of our existing pipeline assets and acquiring
additional strategic assets that diversify our asset base, improve our competitive position and are
accretive to earnings. Although we are primarily focused on acquisitions of pipeline assets and
maximizing our current facilities, we also continue to review, evaluate opportunities and acquire
additional oil and gas properties.
Pipeline Transportation. The BDPS is currently transporting an aggregate of approximately
16 MMcf of gas per day from 8 shippers. The GA 350 Pipeline is currently transporting an aggregate
of approximately 22 MMcf of gas per day from 6 shippers.
Oil and Gas Exploration and Production
|
|
Galveston Area Block 321 The well is currently commingled in the 5,400 and
5,300 sands. Once this commingled completion depletes, there are two upper zones up the hole
with booked reserves. We own a 0.5% overriding royalty interest in the well. The lease is
operated by Maritech Resources. |
|
|
|
High Island Block 115 The block contains one active well, the B-1 ST2 Well, which
has been shut-in since August 2009 due to production problems on our downstream production
handling platform, High Island Block 71. We are exploring options with the lease operator to
resolve the production handling issues. We own a 2.5% working interest in a single production
zone in the well. The lease is operated by Republic Petroleum. |
|
|
|
High Island Block 37 The block contains one active well, the A-2 Well, and one
inactive well, the B-1 Well. Production from the A-2 Well was restarted in February 2009,
after being shut-in as a result of Hurricane Ike. The B-1 Well is currently shut-in following
an unsuccessful workover in September 2009. We own an approximate 2.8% working interest in
this lease that covers 5,760 acres. The lease is operated by Hilcorp Energy Company. |
Our pipeline assets remain significantly under-utilized. The BDPS is currently operating at
approximately 10% of capacity, the GA 350 Pipeline is currently operating at approximately 34% of
capacity and the Omega Pipeline remains inactive. Production declines, temporary stoppages or
cessations of production from wells tied into our pipelines or from our working and overriding
royalty interests in wells in Galveston Area and High Island blocks as noted herein could have a
material adverse effect on our cash flows and liquidity if the resulting revenue declines are not
offset by revenues from other sources. Due to our small size, geographically concentrated asset
base and limited capital resources, any negative event has the potential to have a material adverse
impact on our financial condition. We are continuing our efforts to increase the utilization of
our existing assets and acquire additional assets that will diversify the risks to our cash flows
and be accretive to earnings.
29
Results of Operations
For the year ended December 31, 2009 (current period), we reported a net loss of $4,136,892,
compared to a net loss of $1,966,240 for the year ended December 31, 2008 (previous period). For
the three months ended December 31, 2009 (the current quarter), we reported a net loss of
$2,065,248 compared to a net loss of $822,650 for the three months ended December 31, 2008 (the
previous quarter).
2009 Compared to 2008
Revenue from Pipeline Operations. Revenues from pipeline operations decreased by $581,860,
or 24%, in the current period to $1,866,971 primarily due to decreases in volumes transported.
Revenues in the current period from the BDPS totaled approximately $1,498,000 compared to
approximately $2,042,000 in the previous period primarily due to natural production declines.
Daily gas volumes transported through the BDPS averaged approximately 16 MMcf of gas per day in the
current period compared to approximately 23 MMcf of gas per day in the previous period. Revenues
on the GA 350 Pipeline decreased by approximately $38,000 to approximately $369,000 in the current
period primarily due to natural production declines. Average daily gas volumes for GA 350
transported decreased to approximately 19 MMcf of gas per day in the current period from
approximately 24 MMcf of gas per day in the previous period.
Revenue from Oil and Gas Sales. Revenues from oil and gas sales decreased by $414,602, or
77%, to $125,977 in the current period primarily due to lower commodity prices and one of our
producing wells, the B-1 ST-2 in High Island Block 115, being off production for five months.
Our average realized gas price per Mcf in the current period was $3.23 compared to $11.78 in the
previous period. The sales mix by product was 86% gas and 14% condensate. Our average realized
price per barrel of condensate was $69.60 in the current period compared to $120.25 in the previous
period. Revenue breakdown for the current period by field was approximately $43,000 for High
Island Block 37, $57,000 for High Island Block 115 and $26,000 for Galveston Area Block 321.
Pipeline Operating Expenses. Pipeline operating expenses decreased by $207,280 to
$1,515,362 in the current period. The decrease was primarily due to a decrease in storage tank
repairs and lower compressor repair, insurance, chemical, legal and salt water transportation
expenses. These decreases were partially offset by increases in other repairs primarily as a
result of Hurricane Ike and crane repair expense.
Lease Operating Expenses. Lease operating expenses decreased $148,309, or 61%, in the
current period to $95,141 primarily due to one of our producing wells, the B-1 ST-2 in High Island
Block 115, being off production for five months and a reclassification of lease operating expense
to plugging and abandonment costs.
Impairment of Oil and Gas Properties. During the first quarter of the current period we
recorded a full cost ceiling impairment of $203,110. A variety of economic and other factors
caused significant declines in oil and gas prices. We utilize the full cost method of accounting
to account for our oil and natural gas exploration and development activities. Under this method
of accounting, we are required on a quarterly basis to determine whether the book value of our oil
and natural gas properties (excluding unevaluated properties) is less than or equal to the
ceiling, based upon the expected after tax present value (discounted at 10%) of the future net
cash flows from our proved reserves, calculated using prevailing oil and natural gas prices on the
last day of the period, or a subsequent higher price under certain circumstances. Any excess of
the net book value of our oil and natural gas properties over the ceiling must be recognized as a
non-cash impairment expense. Our ceiling was calculated using prices of $47.19 per barrel of oil
and $3.65 per MMbtu. Accordingly, at March 31, 2009, our costs exceeded our ceiling limitation,
resulting in a write-down of our oil and natural gas properties.
30
General and Administrative Expenses, and Stock Based Compensation. These expenses
decreased $56,893 in the current period to $2,194,878 primarily due to decreases in officer
salaries, other salaries, property and directors and officers insurance. These decreases were
partially offset by increases in legal fees and office expenses.
Interest and Other Income. Other income decreased by $108,262 in the current period due to
a decrease in interest income.
Three Months Ended December 31, 2009 Compared to Three Months Ended December 31, 2008
Revenue from Pipeline Operations. Revenues from pipeline operations decreased by $283,114,
or 44%, in the current quarter to $361,327 primarily due to decreases in volumes transported.
Revenues in the current quarter from the BDPS decreased to approximately $280,000 compared to
approximately $548,000 in the previous quarter. Daily gas volumes transported on the BDPS averaged
13 MMcf of gas per day in the current quarter compared to 25 MMcf of gas per day in the previous
quarter. Revenues on the GA 350 Pipeline decreased to approximately $81,000 compared to
approximately $97,000 in the previous quarter due to a decrease in average daily gas volumes
transported of 16 MMcf of gas per day in the current quarter from 22 MMcf of gas per day in the
previous quarter.
Revenue from Oil and Gas Sales. Revenues from oil and gas sales increased by $21,489 in
the current quarter primarily due to the interruption of production at our producing properties in
the previous quarter as a result of Hurricane Ike.
Pipeline Operating Expenses. Pipeline operating expenses in the current quarter decreased
by $241,063 to $247,946 primarily due to decreases in storage tank repairs, barge dock repairs,
consulting expense, insurance expense and other repairs.
Lease Operating Expenses. Lease operating expenses decreased in the current quarter by
$52,768 to $16,705 due to decreased production at our producing properties.
General and Administrative Expenses and Stock Based Compensation. These expenses decreased
by $150,605 to $404,245 in the current quarter primarily due decreases in officer salaries, legal
fees and consulting expense.
Interest and Other Income, Including Income Tax. Interest and other income decreased by
$131,322 primarily due to the reverse against the previously recorded consulting income associated
with a one year consulting agreement with Lazarus Energy Holdings, LLC.
Liquidity and Capital Resources
Sources and Uses of Cash. Our primary source of cash is cash flow from operations.
During 2009, we had negative cash flow from operations of approximately $1.5 million, excluding
working capital changes, mainly due to low utilization of our pipeline systems and decreased
production at our producing properties.
We do not enter into any hedges or any type of derivatives to offset changes in commodity
prices. We also do not have any outstanding debt or a credit facility with a bank or institution
that may restrict us from issuing debt or common stock. Our current available cash is $1.0 million
at December 31, 2009.
31
|
|
|
|
|
|
|
|
|
|
|
For Year Ended December 31, |
|
|
|
(in millions) |
|
|
|
2009 |
|
|
2008 |
|
Cash flow from operations |
|
|
|
|
|
|
|
|
Loss from operations |
|
$ |
(1.5 |
) |
|
$ |
(0.7 |
) |
Change in current assets and liabilities |
|
|
0.4 |
|
|
|
0.1 |
|
|
|
|
|
|
|
|
Total cash flow from operations |
|
|
(1.1 |
) |
|
|
(0.6 |
) |
|
|
|
|
|
|
|
|
|
Cash outflows |
|
|
|
|
|
|
|
|
Capital expenditures and advance of loan
receivable |
|
|
(1.5 |
) |
|
|
(0.8 |
) |
Payments on note payable |
|
|
(0.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total cash outflows |
|
|
(1.7 |
) |
|
|
(0.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total change in cash flows |
|
$ |
(2.8 |
) |
|
$ |
(1.4 |
) |
|
|
|
|
|
|
|
In the past three years, we have used a portion of our cash reserves to fund our working
capital requirements that were not funded from operations.
Going Concern. Our consolidated financial statements, which have been prepared in
accordance with GAAP, contemplate that we will continue as a going concern and do not contain any
adjustments that might result if we were unable to continue as a going concern. We incurred a net
loss of $4,136,892 for the year ended December 31, 2009. As of December 31, 2009, we had an
accumulated deficit of $30,107,651. We anticipate that we will continue to incur substantial
operating losses unless and until we are able to achieve or sustain profitability. Our cash flow
deficiencies raise substantial doubt as to our ability to continue as a going concern. Existing
and anticipated working capital needs, lower than anticipated revenues, increased expenses or the
inability to collect on an outstanding loan receivable could all affect our ability to continue as
a going concern.
As described in the report of our independent registered public accounting firm and in Note (1),
Organization and Significant Accounting Policies, to the Notes to Consolidated Financial
Statements included in this annual report, these circumstances raise substantial doubt about our
ability to continue as a going concern.
We intend to raise additional working capital through private placements, public offerings, bank
financing and/or advances from related parties or shareholder loans, as well as to continue
evaluating potential merger and/or acquisition opportunities.
The continuation of our business is dependent upon obtaining additional financing. The issuance of
additional equity securities could result in a significant dilution in the equity interests of
current or future stockholders. Obtaining commercial loans, assuming those loans would be
available, will increase liabilities and future cash commitments. There are no assurances that we
will be able to raise additional capital through private placement, public offerings and/or bank
financing necessary to support our working capital requirements. We do not currently have any
agreements in place to raise any additional capital.
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 changed.
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 accounting rules is critical. However, not all situations are
32
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
registered independent accounting firm 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 well as the
evaluation and collection of the note receivable, as of December 31, 2009 and the accounting for
future asset retirement costs.
Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with Financial
Accounting Standards Board (FASB) guidance on accounting for the impairment or disposal of
long-lived assets, we initiate a review for impairment of our long-lived assets whenever events or
changes in circumstances indicate that the carrying amount of a long-lived asset may not be
recoverable. Recoverability of an asset is measured by comparison of its carrying amount to the
expected future undiscounted cash flows expected to result from the use and eventual disposition of
that asset, excluding future interest costs that would be recognized as an expense when incurred.
Any impairment to be recognized is measured by the amount by which the carrying amount of the asset
exceeds its fair market value. Significant management judgment is required in the forecasting of
future operating results which are used in the preparation of projected cash flows and, should
different conditions prevail or judgments be made, material impairment charges could be necessary.
Currently, our pipeline assets are significantly under utilized and such underutilization is an
indicator of possible impairment at December 31, 2009. Accordingly, we developed future cash flows
as of December 31, 2009 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 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, 2009.
Asset Retirement Obligations. The accounting for future abandonment costs changed in August 2001
with the adoption of FASBs guidance on accounting for asset retirement obligations. This guidance
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, plugging and abandonment of
wells and restoration costs of land and seabed. We develop estimates of these costs for each of our
assets based upon regulatory requirements, 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.
Accounting for Uncertainty in Income Taxes. We adopted FASBs accounting for uncertainty in income
taxes effective January 1, 2007. The guidance clarifies the accounting for uncertainty in income
taxes recognized in an enterprises financial statements. It also prescribes a recognition
threshold and measurement attribute for the financial statement recognition and measurement of a
tax position taken or
expected to be taken in a tax return. The standard also provides guidance on de-recognition,
classification, interest and penalties, accounting in interim periods, disclosure, and transition.
The evaluation of a tax position in accordance with the guidance is a two-step process. The first
step is a recognition process whereby the enterprise determines whether it is more likely than not
that a tax position
33
will be sustained upon examination, including resolution of any related appeals
or litigation processes, based on the technical merits of the position. In evaluating whether a
tax position has met the more-likely-than-not recognition threshold, the enterprise should presume
that the position will be examined by the appropriate taxing authority that has full knowledge of
all relevant information. The second step is a measurement process whereby a tax position that
meets the more-likely-than-not recognition threshold is calculated to determine the amount of
benefit to recognize in the financial statements. The tax position is measured at the largest
amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The
provisions of the guidance are to be applied to all tax positions. Only tax positions that meet
the more-likely-than-not recognition are recognized.
The provisions of the guidance have been applied to all of our material tax positions taken from
January 1, 2007 through the fiscal year ended December 31, 2009. We have determined that all of
our material tax positions taken in our income tax returns and the positions we expect to take in
our future income tax filings meet the more likely-than-not recognition threshold prescribed by the
guidance. In addition, we determined that, based on our judgment, none of these tax positions meet
the definition of uncertain tax positions that are subject to the non-recognition criteria set
forth in the pronouncement.
Fair Value Measurements. On January 1, 2008, we adopted FASBs guidance on fair value
measurements, which clarifies the definition of fair value, establishes a framework for measuring
fair value, and expands the disclosures on fair value measurements. In February 2008, FASB issued a
staff position that deferred the effective date of the guidance for one year for nonfinancial
assets and liabilities recorded at fair value on a non-recurring basis. The effect of adoption of
the guidance for financial assets and liabilities recognized at fair value on a recurring basis did
not have a material impact on our financial position and results of operations.
Fair Value Option for Financial Assets and Financial Liabilities. On January 1, 2008, we adopted
FASBs guidance on the fair value option for financial assets and financial liabilities. The
guidance permits companies to choose an irrevocable election to measure certain financial assets
and financial liabilities at fair value. Unrealized gains and losses on items for which the fair
value option has been elected are reported in earnings at each subsequent reporting date. We did
not elect the fair value option under the guidance for any of our financial assets or liabilities
upon adoption.
Recently Adopted Accounting Pronouncements
Generally Accepted Accounting Principles. In June 2009, the FASB issued guidance that established
the Accounting Standards Codification as the sole source of authoritative GAAP. We updated
references to GAAP in our financial statements pursuant to the provisions of FASBs guidance. The
adoption of FASBs guidance did not impact our financial position or results of operations.
Recently Issued Accounting Pronouncements and Accounting Developments
Fair Value Measurements. In January 2010, the FASB issued guidance that requires reporting
entities to make new disclosures about recurring or nonrecurring fair-value measurements including
significant transfers into and out of Level 1 and Level 2 fair value measurements and information
on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3
fair value measurements. The guidance is effective for annual reporting periods beginning after
December 15, 2009, except for Level 3 reconciliation disclosures that are effective for annual
periods beginning after December 15, 2010. We do not expect the adoption of this guidance to have
a material impact on our consolidated financial statements.
34
|
|
|
ITEM 7A. |
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
None.
|
|
|
ITEM 8. |
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Index to Financial Statements:
Remainder of Page Intentionally Left Blank
35
Report of Independent Registered Public Accounting Firm
The Board of Directors and
Stockholders of Blue Dolphin Energy Company
Houston, Texas
We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and
Subsidiaries (the Company) as of December 31, 2009 and 2008, 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, 2009. These consolidated financial statements are the responsibility of
the Companys 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 consolidated financial statements are free of material
misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
Companys internal control over financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated financial statements, assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall consolidated 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, 2009 and 2008, and the consolidated results of their operations and
their cash flows for each of the years in the two-year period ended December 31, 2009 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 (1), Organization and Significant
Accounting Policies, to the notes to consolidated financial statements, the Company has suffered
recurring losses and negative cash flows from operations that raise substantial doubt about its
ability to continue as a going concern. Managements plans in regard to these matters are also
described in Note (1), as referenced herein. The consolidated financial statements do not include
any adjustments that might result from the outcome of this uncertainty.
/s/ UHY LLP
Houston, Texas
April 15, 2010
36
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
ASSETS
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
1,016,483 |
|
|
$ |
3,864,876 |
|
Accounts receivable, net of allowance for doubtful accounts |
|
|
428,124 |
|
|
|
442,715 |
|
Loan receivable, net of allowance for loan receivable |
|
|
|
|
|
|
|
|
Prepaid expenses and other current assets |
|
|
359,850 |
|
|
|
436,242 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
1,804,457 |
|
|
|
4,743,833 |
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
Oil and gas properties (full-cost method) |
|
|
1,086,733 |
|
|
|
1,286,700 |
|
Pipelines |
|
|
4,659,686 |
|
|
|
4,659,686 |
|
Onshore separation and handling facilities |
|
|
1,919,402 |
|
|
|
1,919,402 |
|
Land |
|
|
860,275 |
|
|
|
860,275 |
|
Other property and equipment |
|
|
302,813 |
|
|
|
290,313 |
|
|
|
|
|
|
|
|
|
|
|
8,828,909 |
|
|
|
9,016,376 |
|
Less: Accumulated depletion, depreciation and amortization |
|
|
5,011,401 |
|
|
|
4,494,059 |
|
|
|
|
|
|
|
|
Total property and equipment, net |
|
|
3,817,508 |
|
|
|
4,522,317 |
|
|
|
|
|
|
|
|
|
|
Other assets |
|
|
9,463 |
|
|
|
9,463 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
5,631,428 |
|
|
$ |
9,275,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
372,275 |
|
|
$ |
389,268 |
|
Note payable insurance |
|
|
173,479 |
|
|
|
|
|
Accrued expenses and other liabilities |
|
|
8,136 |
|
|
|
9,593 |
|
Other long-term liabilities current portion |
|
|
25,996 |
|
|
|
25,996 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
579,886 |
|
|
|
424,857 |
|
|
|
|
|
|
|
|
|
|
Long-term liabilities: |
|
|
|
|
|
|
|
|
Asset retirement obligations, net of current portion |
|
|
2,262,018 |
|
|
|
2,183,190 |
|
Other long-term liabilities, net of current portion |
|
|
|
|
|
|
25,996 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
2,262,018 |
|
|
|
2,209,186 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
2,841,904 |
|
|
|
2,634,043 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock ($.01 par value, 100,000,000 shares authorized, 11,876,967 and
11,691,243 shares issued and outstanding at December 31, 2009 and 2008, respectively) |
|
|
118,770 |
|
|
|
116,912 |
|
Additional paid-in capital |
|
|
32,778,405 |
|
|
|
32,495,417 |
|
Accumulated deficit |
|
|
(30,107,651 |
) |
|
|
(25,970,759 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
2,789,524 |
|
|
|
6,641,570 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
5,631,428 |
|
|
$ |
9,275,613 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
37
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Revenue from operations: |
|
|
|
|
|
|
|
|
Pipeline operations |
|
$ |
1,866,971 |
|
|
$ |
2,448,831 |
|
Oil and gas sales |
|
|
125,977 |
|
|
|
540,579 |
|
|
|
|
|
|
|
|
Total revenue from operations |
|
|
1,992,948 |
|
|
|
2,989,410 |
|
|
|
|
|
|
|
|
|
|
Cost of operations: |
|
|
|
|
|
|
|
|
Pipeline operating expenses |
|
|
1,515,362 |
|
|
|
1,722,642 |
|
Lease operating expenses |
|
|
95,141 |
|
|
|
243,450 |
|
Depletion, depreciation and amortizaton |
|
|
517,342 |
|
|
|
527,972 |
|
Impairment of oil and gas properties |
|
|
203,110 |
|
|
|
213,563 |
|
Allowance for doubtful note receivable, net of consulting agreement |
|
|
1,500,000 |
|
|
|
|
|
General and administrative expenses |
|
|
1,990,032 |
|
|
|
1,953,496 |
|
Stock-based compensation |
|
|
204,846 |
|
|
|
298,275 |
|
Accretion expense |
|
|
110,843 |
|
|
|
108,020 |
|
|
|
|
|
|
|
|
Total cost of operations |
|
|
6,136,676 |
|
|
|
5,067,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations |
|
|
(4,143,728 |
) |
|
|
(2,078,008 |
) |
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
Interest and other income |
|
|
9,921 |
|
|
|
120,069 |
|
Loss on disposal of assets |
|
|
|
|
|
|
(1,886 |
) |
|
|
|
|
|
|
|
Total other income (expense) |
|
|
9,921 |
|
|
|
118,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes |
|
|
(4,133,807 |
) |
|
|
(1,959,825 |
) |
|
|
|
|
|
|
|
|
|
Income tax expense |
|
|
(3,085 |
) |
|
|
(6,415 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(4,136,892 |
) |
|
$ |
(1,966,240 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.35 |
) |
|
$ |
(0.17 |
) |
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.35 |
) |
|
$ |
(0.17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding: |
|
|
|
|
|
|
|
|
Basic |
|
|
11,785,747 |
|
|
|
11,642,391 |
|
|
|
|
|
|
|
|
Diluted |
|
|
11,785,747 |
|
|
|
11,642,391 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
38
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common |
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
Total |
|
|
|
Stock |
|
|
Common |
|
|
Paid-In |
|
|
Accumulated |
|
|
Stockholders |
|
|
|
Shares |
|
|
Stock |
|
|
Capital |
|
|
Deficit |
|
|
Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007 |
|
|
11,610,363 |
|
|
$ |
116,104 |
|
|
$ |
32,117,950 |
|
|
$ |
(24,004,519 |
) |
|
$ |
8,229,535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for services |
|
|
80,880 |
|
|
|
808 |
|
|
|
79,192 |
|
|
|
|
|
|
|
80,000 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
298,275 |
|
|
|
|
|
|
|
298,275 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,966,240 |
) |
|
|
(1,966,240 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008 |
|
|
11,691,243 |
|
|
$ |
116,912 |
|
|
$ |
32,495,417 |
|
|
$ |
(25,970,759 |
) |
|
$ |
6,641,570 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock issued for services |
|
|
185,724 |
|
|
|
1,858 |
|
|
|
78,142 |
|
|
|
|
|
|
|
80,000 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
204,846 |
|
|
|
|
|
|
|
204,846 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,136,892 |
) |
|
|
(4,136,892 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
|
11,876,967 |
|
|
$ |
118,770 |
|
|
$ |
32,778,405 |
|
|
$ |
(30,107,651 |
) |
|
$ |
2,789,524 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
Remainder of Page Intentionally Left Blank
39
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(4,136,892 |
) |
|
$ |
(1,966,240 |
) |
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities: |
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
517,342 |
|
|
|
527,972 |
|
Impairment of oil and gas properties |
|
|
203,110 |
|
|
|
213,563 |
|
Accretion expense |
|
|
110,843 |
|
|
|
108,020 |
|
Stock-based compensation |
|
|
204,846 |
|
|
|
298,275 |
|
Common stock issued for services |
|
|
80,000 |
|
|
|
80,000 |
|
Allowance for doubtful note receivable, net of consulting agreement |
|
|
1,500,000 |
|
|
|
|
|
Bad debt expense |
|
|
|
|
|
|
26,699 |
|
Loss on disposal of assets |
|
|
|
|
|
|
1,886 |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
14,591 |
|
|
|
224,563 |
|
Prepaid expenses and other current assets |
|
|
450,013 |
|
|
|
73,452 |
|
Abandonment costs incurred |
|
|
(32,015 |
) |
|
|
(18,537 |
) |
Accounts payable, accrued expenses and other liabilities |
|
|
(44,446 |
) |
|
|
(169,737 |
) |
|
|
|
|
|
|
|
Net cash used in operating activities |
|
|
(1,132,608 |
) |
|
|
(600,084 |
) |
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Advance of loan receivable, net of consulting agreement |
|
|
(1,500,000 |
) |
|
|
|
|
Exploration and development costs |
|
|
(3,143 |
) |
|
|
(749,088 |
) |
Capital expenditures |
|
|
(12,500 |
) |
|
|
(12,731 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(1,515,643 |
) |
|
|
(761,819 |
) |
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
Payments on notes payable |
|
|
(200,142 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(200,142 |
) |
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents |
|
|
(2,848,393 |
) |
|
|
(1,361,903 |
) |
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
|
|
3,864,876 |
|
|
|
5,226,779 |
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR |
|
$ |
1,016,483 |
|
|
$ |
3,864,876 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing and financing activities: |
|
|
|
|
|
|
|
|
Financing of insurance premiums |
|
$ |
373,621 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Consulting agreement associated with loan receivable |
|
$ |
500,000 |
|
|
$ |
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
40
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(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 consolidated
assets and liabilities and to the disclosure of contingent assets and liabilities to prepare
these consolidated financial statements in conformity with accounting principles generally
accepted in the United States of America. This includes assessing the realization of the
note receivable, the estimated useful life of pipeline assets, valuation of stock-based
payments and reserve information, which affects the depletion calculation as well as the
full cost ceiling limitation. While we believe current estimates are reasonable and
appropriate, actual results could differ from those estimated. |
|
|
|
Going Concern |
|
|
|
Our consolidated financial statements, which have been prepared in accordance with generally
accepted accounting principles (GAAP), contemplate that we will continue as a going
concern and do not contain any adjustments that might result if we were unable to continue
as a going concern. We incurred a net loss of $4,136,892 for the year ended December 31,
2009. As at December 31, 2009, we had an accumulated deficit of $30,107,651. We anticipate
that we will continue to incur substantial operating losses unless and until we are able to
achieve or sustain profitability or are otherwise able to secure external financing. Our
cash flow deficiencies raise substantial doubt as to our ability to continue as a going
concern. Existing and anticipated working capital needs, lower than anticipated revenues,
increased expenses or the inability to collect on an outstanding loan receivable could all
affect our ability to continue as a going concern. |
|
|
|
We intend to raise additional working capital through private placements, public offerings,
bank financing and/or advances from related parties or shareholder loans, as well as to
continue evaluating potential merger and/or acquisition opportunities. |
|
|
|
The continuation of our business is dependent upon obtaining such further financing. The
issuance of additional equity securities could result in a significant dilution in the
equity interests of current or future stockholders. Obtaining commercial loans, assuming
those loans would be available, will increase liabilities and future cash commitments.
There are no assurances that we will be able to obtain additional financing through private
placement, public offerings and/or bank financing necessary to support our working capital
requirements. We do not currently have any arrangements in place to raise any additional
funds. |
41
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
Cash and Cash Equivalents |
|
|
|
Cash equivalents include liquid investments with an original maturity of three months or
less. We maintain cash and cash equivalent balances at one financial institution that is
insured by the Federal Deposit Insurance Corporation. 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. |
|
|
|
In October 2008, the Federal Deposit Insurance Corporation increased its insurance from
$100,000 to $250,000 per depositor. The coverage increase, which is temporary, extends
through December 13, 2013. Additionally, coverage for non-interest bearing accounts, which
is temporary, is unlimited and extends through June 30, 2010. |
|
|
|
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 cost center
basis. We utilize one cost center for all of our properties. Amortization of such costs and
estimated future development costs is determined using the unit-of-production method. Costs
directly associated with the acquisition and evaluation of unproved properties are excluded
from the amortization computation until it is determined whether or not proved reserves can
be assigned to the properties or impairment has occurred. |
|
|
|
Estimated proved oil and gas reserves are based upon reports prepared internally by us. The
net carrying value of oil and gas properties, less related deferred income taxes, is limited
to the lower of unamortized cost or the cost center ceiling, defined as the sum of the
present value (10% discount rate applied) of estimated future net revenues from proved
reserves, after giving effect to income taxes, and the lower of cost or estimated fair value
of unproved properties. In 2009, our unamortized cost exceeded the present value of
estimated future net revenues and we recorded an impairment to our oil and gas properties of
$203,110. 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. |
|
|
|
We capitalize interest on expenditures made in connection with significant exploration and
development projects that are not subject to current amortization. Interest is capitalized
only for the period that activities are in progress to bring these projects to their
intended use. No interest has been capitalized for the years reflected herein. |
|
|
|
Pipelines and Facilities |
|
|
|
Pipelines and facilities are recorded at cost. Depreciation is computed using the
straight-line method over estimated useful lives ranging from 10 to 22 years. |
|
|
|
In accordance with Financial Accounting Standards Board (FASB) standards on 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. |
42
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
Other Property and Equipment |
|
|
|
Depreciation of furniture, fixtures and other equipment is computed using the straight-line
method over estimated useful lives ranging from 3 to 10 years. |
|
|
|
Asset Retirement Obligations |
|
|
|
In August 2001, FASB issued amended guidance on 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. |
|
|
|
The guidance requires that the fair value of a liability for an asset retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of fair value
can be made. The fair value of the liability is added to the carrying amount of the
associated asset and this additional carrying amount is depreciated over the life of
the asset. If the obligation is settled for other than the carrying amount of the
liability, a gain or loss on settlement is recognized. |
|
|
|
We have asset retirement obligations associated with the future abandonment of pipelines and
related facilities and offshore oil and gas properties. The following table summarizes our
asset retirement obligation transactions during the years ended December 31, 2009 and 2008
(in thousands). |
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Beginning asset retirement obligations |
|
$ |
2,183 |
|
|
$ |
2,094 |
|
Liabilities incurred |
|
|
|
|
|
|
|
|
Liabilities settled |
|
|
(32 |
) |
|
|
(19 |
) |
Accretion expense |
|
|
111 |
|
|
|
108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligations |
|
$ |
2,262 |
|
|
$ |
2,183 |
|
|
|
|
|
|
|
|
|
|
Stock-Based Compensation |
|
|
|
Stock-based compensation is recognized in our consolidated financial statements based on the
fair value, on the date of grant or modification, of the equity instrument awarded.
Stock-based compensation expense is recognized in the consolidated financial statements on a
straight-line basis over the vesting period for the entire award. |
|
|
|
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, 2009 was not material. |
43
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Recognition of Pipeline Transportation Revenue
|
|
Revenues from our pipelines are derived from fee-based contracts and are typically based on
transportation fees per unit of volume transported multiplied by the volume delivered.
Revenue is recognized when volumes have been physically delivered for the customer through
the pipeline. |
|
|
|
Subsequent Events |
|
|
|
In May 2009, the FASB established general standards of accounting for and disclosures of
events that occur subsequent to the balance sheet date but before financial statements are
issued or available to be issued. The guidance is effective for interim and annual periods
ending after June 15, 2009. The adoption of this guidance did not have a material impact on
our consolidated financial statements. We evaluated all subsequent events through the
issuance date of our consolidated financial statements as of and for the 12 month period
ended December 31, 2009, and during this subsequent period no material subsequent events
occurred that would require recognition or disclosure in these consolidated financial
statements, except for the allowance for the loan receivable. |
|
|
|
Allowance for Doubtful Accounts |
|
|
|
Accounts receivable are customer obligations due under normal trade terms. The allowance
for doubtful accounts represents our estimate of the amount of probable credit losses
existing in our accounts receivable. We have a limited number of customers with
individually large amounts due at any given date. Any unanticipated change in any one of
these customers credit worthiness or other matters affecting the collectability of amounts
due from such customers could have a material effect on the results of operations in the
period in which such changes or events occur. The Company regularly reviews all aged
accounts receivables for collectability and establishes an allowance as necessary for
individual customer balances. As of December 31, 2009 and 2008, we had recorded an
allowance for doubtful accounts of $0 and $26,699, respectively, related to accounts
receivable. |
|
|
|
Income Taxes |
|
|
|
We provide for income taxes using the asset and liability method of accounting for income
taxes. Under the asset and liability method, 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 carry-forwards. 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. |
|
|
|
We evaluate our tax positions in a two-step process. The first step is to determine whether
it is more likely than not that a tax position will be sustained upon examination. The
second step is a measurement process whereby a tax position that meets the
more-likely-than-not threshold is calculated to determine the amount of benefit to recognize
in the financial statements. |
44
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
|
Earnings Per Share |
|
|
|
|
We apply the provisions of FASBs guidance on earnings per share. The guidance requires the
presentation of basic earnings per share (EPS) which excludes dilution and is computed by
dividing net income (loss) available to common stockholders by the weighted-average number
of shares of common stock outstanding for the period. The guidance requires dual
presentation of basic EPS and diluted EPS on the face of the consolidated statement of
operations and requires a reconciliation of the numerators and denominators of basic EPS and
diluted EPS. Diluted EPS is computed by dividing net income (loss) available to common
shareholders by the diluted weighted average number of common shares outstanding, which
includes the potential dilution that could occur if securities or other contracts to issue
common stock were converted to common stock that then shared in the earnings of the entity. |
|
|
|
|
Employee stock options and stock warrants outstanding were not included in the computation
of diluted earnings per share for the years ended December 31, 2009 and 2008, because their
assumed exercise and conversion would have an anti-dilutive effect on the computation of
diluted loss per share. |
|
|
|
|
The following table provides reconciliation between basic and diluted loss per share: |
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
Basic and Diluted |
|
2009 |
|
|
2008 |
|
Net loss |
|
$ |
(4,136,892 |
) |
|
$ |
(1,966,240 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares of common
stock outstanding and potential dilutive shares
of common stock |
|
|
11,785,747 |
|
|
|
11,642,391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share amount |
|
$ |
(0.35 |
) |
|
$ |
(0.17 |
) |
|
|
|
|
|
|
|
|
|
|
Environmental |
|
|
|
|
We are subject to extensive federal, state and local environmental laws and regulations.
These laws, which are constantly changing, regulate the discharge of materials into the
environment and may require us to remove or mitigate the environmental effects of the
disposal or release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for expenditures of a noncapital nature
are recorded when environmental assessment and/or remediation is probable, and the costs can
be reasonably estimated. Such liabilities are generally recorded at their undiscounted
amounts unless the amounts and timing of payments is fixed or reliably determinable. |
45
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
|
Recently Adopted Accounting Pronouncements |
|
|
|
|
Generally Accepted Accounting Principles. In June 2009, the FASB issued guidance that
established the Accounting Standards Codification as the sole source of authoritative GAAP.
We updated references to GAAP in our financial statements pursuant to the provisions of
FASBs guidance. The adoption of FASBs guidance did not impact our consolidated financial
position or results of operations. |
|
|
|
|
Recently Issued Accounting Pronouncements |
|
|
|
|
Fair Value Measurements. In January 2010, the FASB issued guidance that requires reporting
entities to make new disclosures about recurring or nonrecurring fair-value measurements
including significant transfers into and out of Level 1 and Level 2 fair value measurements
and information on purchases, sales, issuances, and settlements on a gross basis in the
reconciliation of Level 3 fair value measurements. The guidance is effective for annual
reporting periods beginning after December 15, 2009, except for Level 3 reconciliation
disclosures that are effective for annual periods beginning after December 15, 2010. We do
not expect the adoption of this guidance to have a material impact on our consolidated
financial statements. |
(2) |
|
Fair Value of Financial Instruments |
|
|
|
The carrying values of cash and cash equivalents, accounts receivable and accounts
payable, accrued liabilities and other current liabilities approximate fair value due to the
short-term maturities of these instruments. |
(3) |
|
Loan Receivable |
|
|
|
On July 31, 2009, we issued a $2.0 million non-interest bearing loan (the Loan) to
Lazarus Louisiana Refinery II, LLC (LLRII or the Borrower). The Loan, which was due on
January 31, 2010, is secured by (i) a first lien on property owned by Lazarus Environmental,
LLC (LEN), (ii) a second lien on property owned by LLRII and (iii) a guarantee from
Lazarus Energy Holdings, LLC (LEH). We agreed to forbear the loan receivable until June
11, 2010, provided the Borrower satisfies certain conditions set forth in the forbearance
agreement. Those certain conditions were not met, and on April 9, 2010, we called on the
full value of the Loan to be paid by April 13, 2010. As of the date of this report, the
Loan is in default and remains unpaid. Although management believes the Loan could be paid
in full at a date in the future, we reserved an allowance for the entire $2.0 million
balance of the Loan as of December 31, 2009, and expensed $1.5 million (net of $500,000 for
the consulting agreement). |
|
|
|
A $500,000 one year consulting agreement that commenced on July 1, 2009, was also associated
with the loan receivable. As of December 31, 2009, we reserved the remaining $250,000 of
deferred consulting revenue and reserved against the $250,000 of previously recognized
consulting revenue. |
(4) |
|
Income Taxes |
|
|
|
Income tax expense consisted of $3,085 and $6,415 and was related to state income tax
for the years ended 2009 and 2008, respectively. |
46
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
|
The income tax effects of temporary differences that give rise to significant portions of
deferred tax assets and deferred tax liabilities at December 31, 2009 and 2008 are presented
below: |
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Net operating loss and capital loss carryforwards |
|
$ |
7,029,596 |
|
|
$ |
5,881,885 |
|
AMT credit carryforward |
|
|
11,564 |
|
|
|
11,564 |
|
Basis differences in property and equipment |
|
|
470,908 |
|
|
|
314,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
7,512,068 |
|
|
|
6,207,641 |
|
Less: valuation allowance |
|
|
(7,512,068 |
) |
|
|
(6,207,641 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets, net |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
In assessing the recoverability of deferred tax assets, we determine whether it is more
likely than not that some portion or all of the deferred tax assets will be realized. A
full valuation allowance against our deferred tax asset was recognized at December 31, 2009
and 2008 due to our uncertainty as to the utilization of the deferred tax assets in the
foreseeable future. The net change in the total valuation allowance for the years ended
December 31, 2009 and 2008 was an increase of $1,304,427 and $343,660, respectively. |
|
|
|
|
Our effective tax rate applicable to continuing operations in 2009 and 2008 is as
follows: |
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Expected tax rate |
|
|
(34.00 |
%) |
|
|
(34.00 |
%) |
Change in valuation allowance recognized
in earnings |
|
|
34.07 |
% |
|
|
34.33 |
% |
|
|
|
|
|
|
|
|
|
|
0.07 |
% |
|
|
0.33 |
% |
|
|
|
|
|
|
|
|
|
|
For federal tax purposes, we have net operating loss carry-forwards (NOLs) of
approximately $20.7 million at December 31, 2009. These NOLs must be utilized prior to
their expiration, which will occur between 2011 and 2029. |
|
|
|
|
We adopted FASBs guidance on accounting for uncertainty in income taxes effective January
1, 2007. The guidance clarifies the accounting for uncertainty in income taxes recognized in
an enterprises financial statements in accordance with FASBs guidance on accounting for
income taxes. The guidance also prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. The standard also provides guidance on
de-recognition, classification, interest and penalties, accounting in interim periods,
disclosure, and transition. |
|
|
|
|
The evaluation of a tax position is a two-step process. The first step is a recognition
process whereby the enterprise determines whether it is more likely than not that a tax
position will be sustained upon examination, including resolution of any related appeals or
litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met
the more-likely-than-not recognition threshold, the enterprise should presume that the
position will be examined by the appropriate taxing authority that has full knowledge of all
relevant information. The second step is a measurement process whereby a tax position that
meets the more-likely-than- |
47
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
|
not recognition threshold is calculated to determine the amount of benefit to recognize in
the financial statements. The tax position is measured at the largest amount of benefit
that is greater than 50% likely of being realized upon ultimate settlement. |
|
|
|
|
The provisions of the guidance on accounting for uncertainty in income taxes have been
applied to all of our material tax positions taken through the date of adoption and through
the fiscal year ended December 31, 2009. We have determined that all of our material tax
positions taken in our income tax returns and the positions we expect to take in our future
income tax filings meet the more likely-than-not recognition threshold. In addition, we
have determined that, based on our judgment, none of these tax positions meet the definition
of uncertain tax positions that are subject to the non-recognition criteria set forth in
the new pronouncement. |
|
|
|
|
In May 2006, the State of Texas enacted a new business tax that is imposed on gross revenues
to replace the States current franchise tax regime. Although the Texas margins tax (TMT)
is imposed on an entitys gross revenues rather than on its net income, certain aspects of
the tax make it similar to an income tax. In accordance with the FASB guidance, we have
properly determined the impact of the newly-enacted legislation in the determination of our
reported state current and deferred income tax liability. |
|
|
|
|
As part of the adoption of this guidance, the Company records income tax related interest
and penalties, if applicable, as a component of the provision for income tax expense.
However, there were no amounts recognized relating to interest and penalties in the
consolidated statements of operations for the years ended December 31, 2009 and 2008.
Furthermore, none of the Companys federal and state income tax returns are currently under
examination by the Internal Revenue Service (IRS) or state authorities, but fiscal years
2005 and later remain subject to examination by the IRS and the State of Texas. The Company
believes that it has no uncertain tax positions for both federal and state income taxes. |
(5) |
|
Stock Options |
|
|
|
Effective April 14, 2000, after approval by our stockholders, we adopted the 2000 Stock
Incentive Plan (the 2000 Plan). Under the 2000 Plan, we are able to make awards of
stock-based compensation. The number of shares of common stock reserved for grants of
incentive stock options (ISOs) and other stock-based awards was increased to 1,200,000
shares after approval by our stockholders during 2007. As of December 31, 2009, we had
341,040 shares of common stock remaining available for future grants. Options granted under
the 2000 Plan have contractual terms from six to ten years. The exercise price of ISOs
cannot be less than 100% of the fair market value of a share of our common stock determined
on the grant date. All ISO awards granted in previous years vested immediately, however,
200,000 ISOs granted in May 2007 and 75,000 ISOs granted in August 2008 have a three year
vesting period and 150,000 ISOs granted in October 2007 have a two year vesting period. An
additional 28,500 options were granted in October 2007 that vested immediately. Although
the 2000 Plan provides for the granting of other incentive awards, only ISOs and
non-statutory stock options have been issued under the 2000 Plan. The 2000 Plan is
administered by the Compensation Committee of our Board of Directors. |
|
|
|
A tax deduction is permitted for stock options exercised during the period, generally for
the excess of the price at which stock issued from exercise of the options are sold over the
exercise price of the options. Tax benefits are to be shown on the Statement of Cash Flows as financing cash
inflows. Any tax deductions we receive from the exercise of stock options for the
foreseeable future will be applied to the valuation allowance in determining our net
operating loss carry forward. |
48
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
|
Additionally, we utilized the alternate transition method (simplified method) for
calculating the beginning balance in the pool of excess tax benefits in accordance with
FASBs guidance on transition election related to accounting for the tax effects of
share-based payment awards. |
|
|
|
|
We estimate the fair value of stock options granted on the date of grant using the
Black-Scholes-Merton option-pricing model. The following assumptions were used to determine
the fair value of stock options granted during the years ended December 31, 2009 and 2008.
There were no options granted during the year ended December 31, 2009. |
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
Stock options granted |
|
|
75,000 |
|
Risk-free interest rate |
|
|
3.23 |
% |
Expected term, in years |
|
|
6.00 |
|
Expected volatility |
|
|
90.70 |
% |
Dividend yield |
|
|
0.00 |
% |
|
|
|
Expected volatility used in the model is based on the historical volatility of our common
stock and is weighted 50% for the historical volatility over a past period equal to the
expected term and 50% for the historical volatility over the past two years prior to the
grant date. This weighting method was chosen to account for the significant changes in our
financial condition beginning approximately three years ago. These changes include the
decrease in our working capital, decreased pipeline throughput and the reduction and
ultimate elimination of our outstanding debt. |
|
|
|
|
The expected term of options granted used in the model represents the period of time that
options granted are expected to be outstanding. The method used to estimate the expected
term is the simplified method as allowed under the provisions of the SECs Staff
Accounting Bulletin No. 107. This number is calculated by taking the average of the sum of
the vesting period and the original contract term. The risk-free interest rate for periods
within the contractual life of the option is based on the U.S. Treasury yield curve in
effect at the date of the grant. As we have not declared dividends on our common stock
since we became a public entity, no dividend yield was used. No forfeiture rate was assumed
due to the forfeiture history for this type of award. Actual value realized, if any, is
dependent on the future performance of our common stock and overall stock market conditions.
There is no assurance that the value realized by an optionee will be at or near the value
estimated by the Black-Scholes-Merton option-pricing model. |
Remainder of Page Intentionally Left Blank
49
BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
At December 31, 2009, there were a total of 424,559 shares of common stock reserved for
issuance upon exercise of outstanding options under the 2000 Plan. A summary of the status
of our stock options granted to key employees, officers and directors, for the purchase of shares of common stock, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Average |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Intrinsic |
|
|
|
Shares |
|
|
Exercise Price |
|
|
Contractual Life |
|
|
Value |
|
Options outstanding at December 31, 2007 |
|
|
491,559 |
|
|
$ |
2.61 |
|
|
|
|
|
|
|
|
|
Options granted |
|
|
75,000 |
|
|
$ |
1.36 |
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
|
|
|
$ |
0.00 |
|
|
|
|
|
|
|
|
|
Options expired or cancelled |
|
|
(11,000 |
) |
|
$ |
3.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at December 31, 2008 |
|
|
555,559 |
|
|
$ |
2.43 |
|
|
|
|
|
|
|
|
|
Options granted |
|
|
|
|
|
$ |
0.00 |
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
|
|
|
$ |
0.00 |
|
|
|
|
|
|
|
|
|
Options expired or cancelled |
|
|
(131,000 |
) |
|
$ |
2.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at December 31, 2009 |
|
|
424,559 |
|
|
$ |
2.53 |
|
|
|
5.4 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at December 31, 2009 |
|
|
356,559 |
|
|
$ |
2.44 |
|
|
|
5.0 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes additional information about stock options outstanding at
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
|
Options Exercisable |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Remaining |
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
|
Number |
|
|
Contractual Life |
|
|
Average |
|
|
Number |
|
|
Exercise |
|
Range of Exercise Prices |
|
Outstanding |
|
|
(Years) |
|
|
Exercise Price |
|
|
Exercisable |
|
|
Price |
|
$0.35 to $0.80 |
|
|
70,830 |
|
|
|
3.3 |
|
|
$ |
0.44 |
|
|
|
70,830 |
|
|
$ |
0.44 |
|
$1.36 to $1.90 |
|
|
23,429 |
|
|
|
2.1 |
|
|
$ |
1.71 |
|
|
|
23,429 |
|
|
$ |
1.71 |
|
$2.81 to $2.99 |
|
|
318,500 |
|
|
|
6.3 |
|
|
$ |
2.92 |
|
|
|
250,500 |
|
|
$ |
2.90 |
|
$6.00 |
|
|
11,800 |
|
|
|
0.4 |
|
|
$ |
6.00 |
|
|
|
11,800 |
|
|
$ |
6.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
424,559 |
|
|
|
|
|
|
|
|
|
|
|
356,559 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
The following summarizes the net change in non-vested stock options for the years shown:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Grant Date |
|
|
|
Shares |
|
|
Fair Value |
|
Non-vested at December 31, 2007 |
|
|
350,000 |
|
|
$ |
2.05 |
|
Granted |
|
|
75,000 |
|
|
$ |
1.03 |
|
Canceled or expired |
|
|
|
|
|
$ |
0.00 |
|
Vested |
|
|
(141,000 |
) |
|
$ |
2.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2008 |
|
|
284,000 |
|
|
$ |
1.83 |
|
Granted |
|
|
|
|
|
$ |
0.00 |
|
Canceled or expired |
|
|
(100,000 |
) |
|
$ |
1.20 |
|
Vested |
|
|
(116,000 |
) |
|
$ |
2.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2009 |
|
|
68,000 |
|
|
$ |
2.35 |
|
|
|
|
|
|
|
|
|
As of December 31, 2009, there was $52,582 of unrecognized compensation cost related to
68,000 non-vested stock options granted under the 2000 Plan. The weighted average period
over which the unrecognized compensation cost will be recognized is 4 months.
(6) Leases
We have various operating leases that extend through April 2017. Certain of these
operating leases are non-cancelable through May 2010. The following is a schedule of future
minimum lease payments under non-cancelable operating leases exceeding one year at December
31, 2009:
|
|
|
|
|
|
|
Future Minimum Lease |
|
Years Ending December 31, |
|
Payments |
|
2010 |
|
172,646 |
|
|
|
$ |
172,646 |
|
|
|
|
|
Rent expense on operating leases for the years indicated are as follows:
|
|
|
|
|
Years Ended December 31, |
|
Lease Expense |
|
2009 |
|
$ |
115,557 |
|
2008 |
|
$ |
116,117 |
|
51
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(7) Commitments and Contingencies
We are involved in various claims and legal actions arising in the ordinary course of
business. In our opinion, the ultimate disposition of these matters will not have a
material effect on our consolidated financial position, results of operations or cash flows.
Pursuant to the terms of a letter agreement dated October 9, 2009, the initial term of an
employment agreement effective May 1, 2007, was extended from three years to four years.
The employment agreement provides for a base salary of $175,000 per year.
(8) Business Segment Information
Our operations are conducted in two principal business segments: (i) pipeline
transportation services and (ii) oil and gas exploration and production. Our segments are
managed jointly mainly due to the size of the Company. Our management uses earnings before
interest expense and income taxes (EBIT) to assess the operating results and effectiveness
of our business segments, which consist of our consolidated businesses and investments. We
believe EBIT is useful to our investors because it allows them to evaluate our operating
performance using the same performance measure analyzed internally by our management. We
define EBIT as net income (loss) adjusted for (i) items that do not impact our income or
loss from continuing operations, such as the impact of accounting changes, (ii) income taxes
and (iii) interest expense (income). We exclude interest expense (income) and other expense
or income not pertaining to the operations of our segments from this measure so that
investors may evaluate our current operating results without regard to our financing methods
or capital structure. We understand that EBIT may not be comparable to measurements used by
other companies. Additionally, EBIT should be considered in conjunction with net income and
other performance measures such as operating cash flows.
Below is a reconciliation of our EBIT (by segment) for each of the years ended December 31,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
|
Segment |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas |
|
|
|
|
|
|
|
|
|
Pipeline |
|
|
Exploration & |
|
|
Corporate & |
|
|
|
|
|
|
Transportation |
|
|
Production |
|
|
Other(1) |
|
|
Total |
|
Revenues |
|
$ |
1,866,971 |
|
|
$ |
125,977 |
|
|
$ |
|
|
|
$ |
1,992,948 |
|
Operation cost(2) |
|
|
4,740,912 |
|
|
|
307,692 |
|
|
|
367,620 |
|
|
|
5,416,224 |
|
Depletion, depreciation
and amortization(4) |
|
|
420,171 |
|
|
|
292,809 |
|
|
|
7,472 |
|
|
|
720,452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBIT |
|
$ |
(3,294,112 |
) |
|
$ |
(474,524 |
) |
|
$ |
(375,092 |
) |
|
$ |
(4,143,728 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
12,500 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
12,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets(3) |
|
$ |
4,634,238 |
|
|
$ |
267,713 |
|
|
$ |
729,477 |
|
|
$ |
5,631,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes unallocated G&A costs associated with corporate maintenance costs and legal
expenses. It also includes as identifiable assets corporate available cash of $0.7
million. |
|
(2) |
|
Allocable G&A costs are allocated based on revenues. |
|
(3) |
|
Identifiable assets contain related legal obligations of each segment including
cash, accounts receivable and payable and recorded net assets. |
|
(4) |
|
Includes an impairment charge. |
52
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
Segment |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas |
|
|
|
|
|
|
|
|
|
Pipeline |
|
|
Exploration & |
|
|
Corporate & |
|
|
|
|
|
|
Transportation |
|
|
Production |
|
|
Other(1) |
|
|
Total |
|
Revenues |
|
$ |
2,448,831 |
|
|
$ |
540,579 |
|
|
$ |
|
|
|
$ |
2,989,410 |
|
Operation cost(2) |
|
|
3,389,058 |
|
|
|
594,247 |
|
|
|
342,578 |
|
|
|
4,325,883 |
|
Depletion, depreciation
and amortization |
|
|
417,384 |
|
|
|
317,618 |
|
|
|
6,534 |
|
|
|
741,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBIT |
|
$ |
(1,357,611 |
) |
|
$ |
(371,286 |
) |
|
$ |
(349,112 |
) |
|
$ |
(2,078,009 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
1,033 |
|
|
$ |
749,088 |
|
|
$ |
11,698 |
|
|
$ |
761,819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets(3) |
|
$ |
5,073,147 |
|
|
$ |
560,221 |
|
|
$ |
3,642,245 |
|
|
$ |
9,275,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes unallocated G&A costs associated with corporate maintenance costs and legal
expenses. It also includes as identifiable assets corporate available cash of $3.5
million. |
|
(2) |
|
Allocable G&A costs are allocated based on revenues. |
|
(3) |
|
Identifiable assets contain related legal obligations of each segment including
cash, accounts receivable and payable and recorded net assets. |
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, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Gryphon Exploration Co. |
|
$ |
|
|
|
$ |
379,828 |
|
|
$ |
379,828 |
|
W&T Offshore |
|
$ |
|
|
|
$ |
332,396 |
|
|
$ |
332,396 |
|
Helis Oil & Gas |
|
$ |
|
|
|
$ |
216,047 |
|
|
$ |
216,047 |
|
Maritech Resources |
|
$ |
|
|
|
$ |
191,512 |
|
|
$ |
191,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Arena Offshore |
|
$ |
|
|
|
$ |
513,634 |
|
|
$ |
513,634 |
|
W&T Offshore |
|
$ |
|
|
|
$ |
488,083 |
|
|
$ |
488,083 |
|
Gryphon Exploration Co. |
|
$ |
|
|
|
$ |
367,153 |
|
|
$ |
367,153 |
|
Apex Oil & Gas |
|
$ |
|
|
|
$ |
338,836 |
|
|
$ |
338,836 |
|
As of December 31, 2009, we recorded an allowance for doubtful note receivable of
$1,500,000, net of a consulting agreement.
53
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(9) Supplemental Oil and Gas Information
The following supplemental information regarding our oil and gas activities is
presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.
Associated with our non-operating interest in High Island Block 37, we recognized gas and
oil sales revenues of approximately $43,000 and $250,000 in 2009 and 2008, respectively, and
lease operating expenses of approximately $42,000 and $127,000 in 2009 and 2008,
respectively. We have a working interest of approximately 2.8% in the block.
Associated with our non-operated interest in High Island Block 115, we recognized gas and
oil sales revenues of approximately $57,000 and $290,000 in 2009 and 2008, respectively, and
lease operating expenses of approximately $53,000 and $116,000 in 2009 and 2008,
respectively. We have a working interest of 2.5% in one zone of a single well in the lease.
Associated with our non-operated interest in Galveston Area Block 321, we recognized gas and
oil sales revenues of approximately $26,000 and $0 in 2009 and 2008, respectively, and lease
operating expenses of approximately $0 and $0 in 2009 and 2008, respectively. We have an
overriding royalty interest of 0.5% in an exploratory well in the lease.
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
The Company retains an independent geologist to provide year-end estimates of the
Companys future net recoverable oil and natural gas. Estimated proved net recoverable
reserves as shown below include only those quantities that can be expected to be
commercially recoverable. Estimated reserves for the year ended December 31, 2009 were
computed using benchmark prices based on the unweighted arithmetic average of the
first-day-of-the-month prices for oil and natural gas during each month of 2009, as required
by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting, effective December 31,
2009. Costs were estimated using costs in effect at the balance sheet dates under existing
regulatory practices and with conventional equipment and operating methods.
Set forth below is a summary of the changes in the estimated quantities of our crude oil and
condensate, and gas reserves for the periods indicated, as estimated by us at December 31,
2009 and 2008. All of our reserves are located within the United States of America. Proved
reserves cannot be measured exactly because the estimation of reserves involves numerous
judgmental determinations. Accordingly, reserve estimates must be continually revised as a
result of new information obtained from drilling and production history, new geological and
geophysical data and changes in economic conditions.
Proved reserves are estimated quantities of gas, crude oil, and condensate which
geological and engineering data demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under existing economic and operating conditions. Proved
developed reserves are proved reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
54
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
Quantity of Oil and Gas Reserves |
|
(Bbls) |
|
|
(Mcf) |
|
Total proved reserves at December 31, 2007 |
|
|
846 |
|
|
|
177,671 |
|
|
|
|
|
|
|
|
|
|
Revisions to previous estimates |
|
|
(297 |
) |
|
|
10,827 |
|
Extensions, discoveries, improved recovery and other additions |
|
|
337 |
|
|
|
14,440 |
|
Purchase of reserves in place |
|
|
|
|
|
|
|
|
Sales of reserves in place |
|
|
|
|
|
|
|
|
Production |
|
|
(117 |
) |
|
|
(44,720 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves at December 31, 2008 |
|
|
769 |
|
|
|
158,218 |
|
|
|
|
|
|
|
|
|
|
Revisions to previous estimates |
|
|
239 |
|
|
|
3,162 |
|
Extensions, discoveries, improved recovery and other additions |
|
|
|
|
|
|
|
|
Purchase of reserves in place |
|
|
|
|
|
|
|
|
Sales of reserves in place |
|
|
|
|
|
|
|
|
Production |
|
|
(250 |
) |
|
|
(33,531 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved reserves at December 31, 2009 |
|
|
758 |
|
|
|
127,849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
758 |
|
|
|
127,849 |
|
December 31, 2008 |
|
|
769 |
|
|
|
158,218 |
|
|
|
|
|
|
|
|
|
|
Total proved reserves: |
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
758 |
|
|
|
127,849 |
|
December 31, 2008 |
|
|
769 |
|
|
|
158,218 |
|
Remainder of Page Intentionally Left Blank
55
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Capitalized Costs of Oil and Gas Producing Activities
|
|
The following table sets forth the aggregate amounts of capitalized costs relating to our
oil and gas producing activities and the aggregate amount of related accumulated depletion,
depreciation, amortization as of: |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Unproved properties and prospect generation
costs not being amortized |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
Proved properties being amortized |
|
|
1,086,733 |
|
|
|
1,286,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized costs |
|
|
1,086,733 |
|
|
|
1,286,700 |
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation, depletion and amortization |
|
|
(868,041 |
) |
|
|
(776,467 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
218,692 |
|
|
$ |
510,233 |
|
|
|
|
|
|
|
|
Costs Incurred in Oil and Gas Producing Activities
The following table reflects the costs incurred in oil and gas property acquisition,
disposition, exploration and development activities during the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Costs incurred: |
|
|
|
|
|
|
|
|
Acquisition of proved properties |
|
$ |
|
|
|
$ |
|
|
Acquisition of unproved properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs |
|
|
3,143 |
|
|
|
749,088 |
|
Development costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
3,143 |
|
|
$ |
749,088 |
|
|
|
|
|
|
|
|
We did not incur costs in the acquisition of oil and gas properties in 2009 or 2008.
56
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Results of Operations for Oil and Gas Producing Activities
The results of operations from oil and gas producing activities below exclude non-oil and
gas revenues, general and administrative expenses, interest expense and interest income.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Revenues from oil and gas producing activities |
|
$ |
125,977 |
|
|
$ |
540,579 |
|
Production costs |
|
|
(95,141 |
) |
|
|
(243,450 |
) |
Depreciation, depletion, and amortization |
|
|
(89,699 |
) |
|
|
(104,055 |
) |
Impairment of oil and gas properties |
|
|
(203,110 |
) |
|
|
(213,563 |
) |
|
|
|
|
|
|
|
Pretax income from producing activities |
|
|
(261,973 |
) |
|
|
(20,489 |
) |
|
|
|
|
|
|
|
|
|
Income tax expense/estimated loss carryforward benefit |
|
|
4,139 |
|
|
|
324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of oil and gas producing activities (excluding
corporate overhead and interest costs) |
|
$ |
(257,834 |
) |
|
$ |
(20,165 |
) |
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The following table reflects the Standardized Measure of Discounted Future Net Cash Flows
relating to our interest in proved oil and gas reserves for:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Future cash inflows |
|
$ |
529,376 |
|
|
$ |
866,563 |
|
Future development costs |
|
|
|
|
|
|
|
|
Future production costs |
|
|
(164,100 |
) |
|
|
(267,932 |
) |
Future income taxes |
|
|
|
|
|
|
|
|
10% discount factor |
|
|
(28,980 |
) |
|
|
(88,398 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash inflows (outflows) |
|
$ |
336,296 |
|
|
$ |
510,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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: (i) multiplying
estimated quantities of proved reserves to be produced during each year by year-end
prices and (ii) deducting estimated expenditures to be incurred during each year to
develop and produce the proved reserves (based on year-end 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
carry-forwards. 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.
57
BLUE
DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
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 authoritative guidance and the requirements promulgated by the
Securities Exchange Commission to provide readers with a common base for use in preparing
their own estimates of future cash flows and for comparing reserves among companies. We do
not rely on these computations when making investment and operating decisions. Principal
changes in the Standardized Measure of Discounted Future Net Cash Flows attributable to our
proved oil and gas reserves for the periods indicated are as follows:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
Sales and transfers, net of production costs |
|
$ |
(30,836 |
) |
|
$ |
(297,129 |
) |
Net change in sales and transfer prices, net of
production costs |
|
|
(31,511 |
) |
|
|
(377,061 |
) |
Extension, discoveries and improved recovery, net
of future production and development costs |
|
|
|
|
|
|
404,129 |
|
Development costs incurred during the period that
reduced future development costs |
|
|
(32,000 |
) |
|
|
18,500 |
|
Changes in estimated future development cost |
|
|
(29,461 |
) |
|
|
67,296 |
|
Revisions of quantity estimates |
|
|
(1,872 |
) |
|
|
(27,964 |
) |
Accretion of discount |
|
|
51,023 |
|
|
|
10,700 |
|
Net change in income taxes |
|
|
|
|
|
|
241,740 |
|
Change in production rates (timing) and other |
|
|
(99,280 |
) |
|
|
762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change |
|
$ |
(173,937 |
) |
|
$ |
40,973 |
|
|
|
|
|
|
|
|
Remainder of Page Intentionally Left Blank
58
|
|
|
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE |
None.
|
|
|
ITEM 9A(T). CONTROLS AND PROCEDURES |
Evaluation of Disclosure Controls and Procedures
As of the end of the year 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
our Principal Financial and Accounting Officer, of the effectiveness of the design and operation of
our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
Exchange Act). Based upon this evaluation, as of December 31, 2009, the Chief Executive Officer
and Principal Financial and Accounting Officer concluded that our disclosure controls and
procedures were 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 the SECs rules and forms and that such information is accumulated
and communicated to our management, including the Chief Executive Officer and Principal Financial
and Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.
Managements Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting (as defined in Rules 13a-15(f) and 15d-5(f) under the Exchange Act). Our
management assessed the effectiveness of our internal control over financial reporting as of
December 31, 2009. In making this assessment, our management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control
Integrated Framework. Our management has concluded that, as of December 31, 2009, our internal
control over financial reporting is effective based on these criteria. This annual report does not
include an attestation report of our registered public accounting firm regarding internal control
over financial reporting. Managements report was not subject to attestation by our registered
public accounting firm pursuant to temporary rules of the SEC that permit us to provide only
managements report in this annual report.
Our management, including our Chief Executive Officer and Principal Financial and Accounting
Officer, does not expect our internal control over financial reporting to prevent all error or
fraud. A control system, no matter how well designed and operated, can provide only reasonable,
not absolute, assurance that the objectives of the control system are met. Further, the design of
a control system must take into account resource constraints. The benefits of controls must be
considered relative to their costs. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues and instances of
fraud, if any, have been detected. Our internal control over financial reporting, however, is
designed to provide reasonable assurance that the objectives of internal control over financial
reporting are met.
Changes in Internal Control over Financial Reporting
There have been no changes made in our internal control over financial reporting that materially
affected, or is reasonably likely to materially affect, the internal control over financial
reporting, during the period covered by this report.
59
|
|
|
ITEM 9B. OTHER INFORMATION |
None.
PART III
|
|
|
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The information required by Item 10 is incorporated by reference to our definitive proxy
statement relating to our 2010 annual meeting of stockholders, which proxy statement will be filed
pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
|
|
|
ITEM 11. EXECUTIVE COMPENSATION |
The information required by Item 11 is incorporated by reference to our definitive proxy
statement relating to our 2010 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. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS |
The information required by Item 12 is incorporated by reference to our definitive proxy
statement relating to our 2010 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. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
The information required by Item 13 is incorporated by reference to our definitive proxy
statement relating to our 2010 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 14. PRINCIPAL ACCOUNTING FEES AND SERVICES |
The information required by Item 14 is incorporated by reference to our definitive proxy
statement relating to our 2010 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.
Remainder of Page Intentionally Left Blank
60
PART IV
|
|
|
ITEM 15. |
|
EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a) List of documents filed as part of this report
3. Exhibits. We hereby file as part of this Annual Report on Form 10-K the Exhibits listed
in the attached Exhibit Index.
|
|
|
No. |
|
Description |
3.1
|
|
Amended and Restated Certificate of Incorporation of the Company (1) |
|
|
|
3.2
|
|
Amended and Restated By-Laws of the Company (9) |
|
|
|
4.1
|
|
Specimen Stock Certificate (2) |
|
|
|
4.2
|
|
Form of Promissory Note issued pursuant to the Note and Warrant Purchase
Agreement dated September 8, 2004 (7) |
|
|
|
4.3
|
|
Promissory Note of Lazarus Louisiana Refinery II, LLC, payable to Blue Dolphin
Energy Company dated July 31, 2009 (15) |
|
|
|
10.1
|
|
Blue Dolphin Energy Company 2000 Stock Incentive Plan (3) * |
|
|
|
10.2
|
|
First Amendment to the Blue Dolphin Energy Company 2000 Stock Incentive Plan (4) * |
|
|
|
10.3
|
|
Second Amendment to the Blue Dolphin Energy Company 2000 Stock Incentive Plan (5) |
|
|
|
10.4
|
|
Purchase and Sale Agreement by and between Blue Dolphin Pipe Line Company and MCNIC,
dated February 1, 2002 (6) |
|
|
|
10.5
|
|
Sale of American Resources Offshore, Inc. Common Stock Agreement between Blue Dolphin
Exploration Co. and Ivar Siem, dated September 8, 2004 (7) |
|
|
|
10.6
|
|
Purchase and Sale Agreement by and between Blue Dolphin Energy Company, WBI
Pipeline & Storage Group, Inc. and SemGas LP, dated October 29, 2004 (8) |
|
|
|
10.7
|
|
Amendment to the Asset Purchase Agreement by and among MCNIC Offshore
Pipeline and Processing Company and Blue Dolphin Pipe Line Company dated February 28, 2005 (10) |
|
|
|
10.8
|
|
Placement Agency Agreement by and between Blue Dolphin Energy Company and Starlight
Investments, LLC dated May 27, 2005 (12) |
|
|
|
10.9
|
|
Form of Stock Purchase Agreement between Blue Dolphin Energy Company and Osler
Holdings Limited, Gilbo Invest AS, Spencer Energy AS, Spencer Finance Corp., Hudson Bay
Fund, LP, Don Fogel and SIBEX Capital Fund, Inc. dated March 8, 2006
(13) |
|
|
|
10.10
|
|
Loan and Option Agreement by and among Lazarus Energy Holdings, LLC, Lazarus
Louisiana Refinery II, LLC, Lazarus Energy, LLC, Lazarus Environmental, LLC, and Blue
Dolphin Energy Company dated July 31, 2009 (14) |
|
|
|
14.1
|
|
Code of Ethics applicable to the Chairman, Chief Executive Officer and Senior
Financial Officer (11) |
|
|
|
* |
|
Management Compensation Plan. |
|
** |
|
Filed herewith. |
61
|
|
|
No. |
|
Description |
21.1
|
|
List of Subsidiaries of the Company ** |
|
|
|
23.1
|
|
Consent of UHY LLP ** |
|
|
|
23.2
|
|
Consent of William J. Driscoll, Geologist ** |
|
|
|
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
|
|
T. Scott Howard 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
|
|
T. Scott Howard Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to section 906 of the Sarbanes-Oxley Act of 2002 ** |
|
|
|
99.1
|
|
Memo from William J. Driscoll, Geologist, regarding Estimated Prove Reserves and
Future Revenue ** |
|
|
|
(1) |
|
Incorporated herein by reference to Exhibit 3.1 filed in connection with
the Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934,
dated June 2, 2009 (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 Appendix 1 filed in connection with the
Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934,
dated April 20, 2000 (Commission File No. 000-15905). |
|
(4) |
|
Incorporated herein by reference to Appendix B 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 Appendix A filed in connection with the
definitive Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange
Act of 1934, dated April 27, 2006 (Commission File No. 000-15905). |
|
(6) |
|
Incorporated herein by reference to Exhibit 10.20 filed in connection with Form
10-KSB of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated
March 23, 2003 (Commission File No. 000-15905). |
|
(7) |
|
Incorporated herein by reference to Exhibit 10.4 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). |
|
(8) |
|
Incorporated herein by reference to Exhibit 10.1 filed in connection with
Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated
November 3, 2004 (Commission File No. 000-15905). |
|
(9) |
|
Incorporated herein by reference to Exhibit 3.1 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated
December 26, 2007 (Commission File No. 000-15905). |
|
(10) |
|
Incorporated herein by reference to Exhibit 10.1 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated March
3, 2005 (Commission File No. 000-15905). |
|
(11) |
|
Incorporated herein by reference to Exhibit 14.1 filed
in connection with Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31,
2004 under the Securities Exchange Act of 1934, dated March 25, 2005 (Commission File No.
000-15905). |
|
|
|
|
|
|
* |
|
Management Compensation Plan. |
|
** |
|
Filed herewith. |
62
|
|
|
(12) |
|
Incorporated herein by reference to Exhibit 10.9 filed in connection with Form
10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2005 under the
Securities Exchange Act of 1934, dated March 30, 2006 (Commission File No. 000-15905). |
|
(13) |
|
Incorporated herein by reference to Exhibit 10.10 filed in connection with
Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2005 under the
Securities Exchange Act of 1934, dated March 30, 2006 (Commission File No. 000-15905). |
|
(14) |
|
Incorporated herein by reference to Exhibit 10.1 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities Exchange Act of 1934, dated August 6,
2009 (Commission File No. 000-15905). |
|
(15) |
|
Incorporated herein by reference to Exhibit 10.2 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities Exchange Act of 1934, dated August 6,
2009 (Commission File No. 000-15905). |
Remainder of Page Intentionally Left Blank
63
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 |
|
|
|
(Chairman and CEO) |
|
|
|
|
|
|
|
Date: April 15, 2010 |
|
|
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 |
|
|
|
|
|
|
|
Chairman and CEO
(Principal Executive Officer)
|
|
April 15, 2010 |
|
|
|
|
|
/s/ T. Scott Howard
T. Scott Howard
|
|
Treasurer and Assistant Secretary
(Principal Financial and Accounting Officer)
|
|
April 15, 2010 |
|
|
|
|
|
/s/ Laurence N. Benz
Laurence N. Benz
|
|
Director
|
|
April 15, 2010 |
|
|
|
|
|
/s/ John N. Goodpasture
John N. Goodpasture
|
|
Director
|
|
April 15, 2010 |
|
|
|
|
|
/s/ Harris A. Kaffie
Harris A. Kaffie
|
|
Director
|
|
April 15, 2010 |
|
|
|
|
|
/s/ Erik Ostbye
Erik Ostbye
|
|
Director
|
|
April 15, 2010 |
64
Exhibit Index
|
|
|
No. |
|
Description |
3.1
|
|
Amended and Restated Certificate of Incorporation of the Company (1) |
|
|
|
3.2
|
|
Amended and Restated By-Laws of the Company (9) |
|
|
|
4.1
|
|
Specimen Stock Certificate (2) |
|
|
|
4.2
|
|
Form of Promissory Note issued pursuant to the Note and Warrant Purchase
Agreement dated September 8, 2004 (7) |
|
|
|
4.3
|
|
Promissory Note of Lazarus Louisiana Refinery II, LLC, payable to Blue Dolphin Energy
Company dated July 31, 2009 (15) |
|
|
|
10.1
|
|
Blue Dolphin Energy Company 2000 Stock Incentive Plan (3) * |
|
|
|
10.2
|
|
First Amendment to the Blue Dolphin Energy Company 2000 Stock Incentive Plan (4) * |
|
|
|
10.3
|
|
Second Amendment to the Blue Dolphin Energy Company 2000 Stock Incentive Plan (5) |
|
|
|
10.4
|
|
Purchase and Sale Agreement by and between Blue Dolphin Pipe Line Company and MCNIC,
dated February 1, 2002 (6) |
|
|
|
10.5
|
|
Sale of American Resources Offshore, Inc. Common Stock Agreement between Blue Dolphin Exploration Co. and Ivar
Siem, dated September 8, 2004 (7) |
|
|
|
10.6
|
|
Purchase and Sale Agreement by and between Blue Dolphin Energy Company, WBI
Pipeline & Storage Group, Inc. and SemGas LP, dated October 29, 2004 (8) |
|
|
|
10.7
|
|
Amendment to the Asset Purchase Agreement by and among MCNIC Offshore
Pipeline and Processing Company and Blue Dolphin Pipe Line Company dated February 28, 2005
(10) |
|
|
|
10.8
|
|
Placement Agency Agreement by and between Blue Dolphin Energy Company and Starlight Investments, LLC dated May
27, 2005 (12) |
|
|
|
10.9
|
|
Form of Stock Purchase Agreement between Blue Dolphin Energy Company and Osler Holdings Limited, Gilbo Invest
AS, Spencer Energy AS, Spencer Finance Corp., Hudson Bay Fund, LP, Don Fogel and SIBEX Capital Fund, Inc. dated
March 8, 2006 (13) |
|
|
|
10.10
|
|
Loan and Option Agreement by and among Lazarus Energy Holdings, LLC, Lazarus
Louisiana Refinery II, LLC, Lazarus Energy, LLC, Lazarus Environmental, LLC, and
Blue Dolphin Energy Company dated July 31, 2009 (14) |
|
|
|
14.1
|
|
Code of Ethics applicable to the Chairman, Chief Executive Officer and Senior
Financial Officer (11) |
|
|
|
21.1
|
|
List of Subsidiaries of the Company ** |
|
|
|
23.1
|
|
Consent of UHY LLP ** |
|
|
|
23.2
|
|
Consent of William J. Driscoll, Geologist ** |
|
|
|
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
|
|
T. Scott Howard Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to section 302 of the Sarbanes-Oxley Act of 2002 ** |
65
|
|
|
No. |
|
Description |
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
|
|
T. Scott Howard Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to section 906 of the Sarbanes-Oxley Act of 2002 ** |
|
|
|
99.1
|
|
Memo from William J. Driscoll, Geologist, regarding Estimated Prove Reserves and
Future Revenue** |
|
|
|
(1) |
|
Incorporated herein by reference to Exhibit 3.1 filed in connection with
the Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934,
dated June 2, 2009 (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 Appendix 1 filed in connection with
the Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange Act of
1934, dated April 20, 2000 (Commission File No. 000-15905). |
|
(4) |
|
Incorporated herein by reference to Appendix B 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 Appendix A filed in connection with the
definitive Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange
Act of 1934, dated April 27, 2006 (Commission File No. 000-15905). |
|
(6) |
|
Incorporated herein by reference to Exhibit 10.20 filed in connection with Form
10-KSB of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated
March 23, 2003 (Commission File No. 000-15905). |
|
(7) |
|
Incorporated herein by reference to Exhibit 10.4 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). |
|
(8) |
|
Incorporated herein by reference to Exhibit 10.1 filed in connection with
Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated
November 3, 2004 (Commission File No. 000-15905). |
|
(9) |
|
Incorporated herein by reference to Exhibit 3.1 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated
December 26, 2007 (Commission File No. 000-15905). |
|
(10) |
|
Incorporated herein by reference to Exhibit 10.1 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated March
3, 2005 (Commission File No. 000-15905). |
|
(11) |
|
Incorporated herein by reference to Exhibit 14.1 filed in connection with Form
10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2004 under the
Securities Exchange Act of 1934, dated March 25, 2005 (Commission File No. 000-15905). |
|
(12) |
|
Incorporated herein by reference to Exhibit 10.9 filed in connection with Form
10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2005 under the
Securities Exchange Act of 1934, dated March 30, 2006 (Commission File No. 000-15905). |
|
(13) |
|
Incorporated herein by reference to Exhibit 10.10 filed in connection with
Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2005 under the
Securities Exchange Act of 1934, dated March 30, 2006 (Commission File No. 000-15905). |
|
(14) |
|
Incorporated herein by reference to Exhibit 10.1 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities Exchange Act of 1934, dated August 6,
2009 (Commission File No. 000-15905). |
|
(15) |
|
Incorporated herein by reference to Exhibit 10.2 filed in connection with Form
8-K of Blue Dolphin Energy Company under the Securities Exchange Act of 1934, dated August 6,
2009 (Commission File No. 000-15905). |
66