UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
|
|
x |
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934 For the fiscal year ended December 31,
2006
|
OR
|
|
¨ |
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934 For the transition period from
to
|
Commission
file number: 000-21467
PACIFIC
ETHANOL, INC.
(Exact
name of registrant as specified in its charter)
|
Delaware
|
41-2170618
|
|
(State
or other jurisdiction of incorporation or
organization)
|
(I.R.S.
Employer Identification
No.)
|
|
400
Capitol Mall, Suite 2060, Sacramento, California
|
95814
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
Registrant’s
telephone number, including area code: (916) 403-2123
Securities
registered pursuant to Section 12(b) of the Act: Common Stock, $.001 par value
Securities
registered pursuant to Section 12(g) of the Act: None
(Title
of class)
Indicate
by check mark whether the registrant is a well-known seasoned issuer, as defined
in Rule 405 of the Securities Act. Yes ¨ No x
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 ¨ No x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. Yes x No ¨
Indicate
by check mark if disclosure of delinquent filers in response to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this
Form 10-K. x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
|
Large
accelerated filer x
|
Accelerated
filer ¨
|
Non-accelerated
filer ¨
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes ¨ No x
The
aggregate market value of the voting common equity held by nonaffiliates of
the
registrant computed by reference to the closing sale price of such stock, was
approximately $725.0 million as of June 30, 2006, the last business day of
the
registrant’s most recently completed second fiscal quarter. The registrant has
no non-voting common equity.
The
number of shares of the registrant’s common stock, $.001 par value, outstanding
as of March 7, 2007 was 40,285,227.
DOCUMENTS
INCORPORATED BY REFERENCE:
Part
III
incorporates by reference certain information from the registrant’s definitive
proxy statement (the “Proxy Statement”) for the 2007 Annual Meeting of
Stockholders to be filed on or before April 30, 2007.
TABLE
OF CONTENTS
| |
|
Page
|
| |
PART I
|
|
|
Item
1.
|
Business
|
1
|
|
Item
1A.
|
Risk
Factors.
|
13
|
|
Item
1B.
|
Unresolved
Staff Comments.
|
24
|
|
Item
2.
|
Properties.
|
24
|
|
Item
3.
|
Legal
Proceedings.
|
24
|
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders.
|
26
|
| |
|
|
|
|
PART
II
|
|
|
Item
5.
|
Market
For Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.
|
27
|
|
Item
6.
|
Selected
Financial Data.
|
30
|
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
|
31
|
|
Item
7A.
|
Quantitative
and Qualitative Disclosures About Market Risk.
|
49
|
|
Item
8.
|
Financial
Statements and Supplementary Data.
|
51
|
|
Item
9.
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure.
|
51
|
|
Item
9A.
|
Controls
and Procedures
|
51
|
|
Item
9B.
|
Other
Information.
|
59
|
| |
|
|
|
|
PART
III
|
|
|
Item
10.
|
Directors,
Executive Officers and Corporate Governance
|
60
|
|
Item
11.
|
Executive
Compensation
|
60
|
|
Item
12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
60
|
|
Item
13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
60
|
|
Item
14.
|
Principal
Accounting Fees and Services
|
60
|
|
|
PART
IV
|
|
|
Item
15.
|
Exhibits,
Financial Statement Schedules
|
60
|
| |
|
|
Index
to Financial Statements
|
|
|
Index
to Exhibits
|
|
Signatures
|
|
Exhibits
Filed With This Report
|
|
CAUTIONARY
STATEMENT
All
statements included or incorporated by reference in this Annual Report on Form
10-K, other than statements or characterizations of historical fact, are
forward-looking statements. Examples of forward-looking statements include,
but
are not limited to, statements concerning projected net sales, costs and
expenses and gross margins; our accounting estimates, assumptions and judgments;
our success in pending litigation; the demand for ethanol and its co-products;
the competitive nature of and anticipated growth in our industry; production
capacity and goals; our ability to consummate acquisitions and integrate their
operations successfully; and our prospective needs for additional capital.
These
forward-looking statements are based on our current expectations, estimates,
approximations and projections about our industry and business, management’s
beliefs, and certain assumptions made by us, all of which are subject to change.
Forward-looking statements can often be identified by words such as
“anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,”
“estimates,” “may,” “will,” “should,” “would,” “could,” “potential,” “continue,”
“ongoing,” similar expressions, and variations or negatives of these words.
These statements are not guarantees of future performance and are subject to
risks, uncertainties and assumptions that are difficult to predict. Therefore,
our actual results could differ materially and adversely from those expressed
in
any forward-looking statements as a result of various factors, some of which
are
listed under “Risk Factors” in Item 1A of this Report. These forward-looking
statements speak only as of the date of this Report. We undertake no obligation
to revise or update publicly any forward-looking statement for any reason,
except as otherwise required by law.
PART
I
Business Overview
Our
primary goal is to become the leading marketer and producer of renewable fuels
in the Western United States.
We
produce and sell ethanol and its co-products and provide transportation, storage
and delivery of ethanol through third-party service providers in the Western
United States, primarily in California, Nevada, Arizona, Washington, Oregon
and
Colorado. We have extensive customer relationships throughout the Western United
States and extensive supplier relationships throughout the Western and
Midwestern United States.
In
October 2006, we completed construction of an ethanol production facility with
nameplate annual production capacity of 35 million gallons located in Madera,
California, and began producing ethanol. In October 2006, we also acquired
approximately 42% of the outstanding membership interests of Front Range Energy,
LLC, or Front Range, which owns and operates an ethanol production facility
with
nameplate annual production capacity of 40 million gallons located in Windsor,
Colorado. In addition, we are currently constructing or in advanced stages
of
development of four additional ethanol production facilities. We also intend
to
construct or otherwise acquire additional ethanol production facilities as
financial resources and business prospects make the construction or acquisition
of these facilities advisable. See “—Production Facilities” below.
Total
annual gasoline consumption in the United States is approximately 140 billion
gallons. Total annual ethanol consumption currently represents less than 4%
of
annual gasoline consumption, or approximately 5.1 billion gallons of ethanol.
We
believe that the domestic ethanol industry has substantial potential for growth
to reach what we estimate is an achievable level of at least 10% of the total
annual gasoline consumption in the United States, or approximately 14 billion
gallons of ethanol. In California alone, an increase in the consumption of
ethanol from California’s current level of 5.7%, or approximately 1.0 billion
gallons of ethanol per year, to at least 10% of total annual gasoline
consumption would result in consumption of approximately 700 million additional
gallons of ethanol, representing an increase in annual ethanol consumption
in
California alone of approximately 75% and an increase in annual ethanol
consumption in the entire United States of approximately 13%.
We
intend
to achieve our goal of becoming the leading marketer and producer of renewable
fuels in the Western United States in part by expanding our production capacity
to 220 million gallons of annual production capacity by the second quarter
of
2008 and 420 million gallons of annual production capacity by the end of 2010.
We intend to achieve this goal in part also by expanding our relationships
with
third-party ethanol producers to market higher volumes of ethanol throughout
the
Western United States, expanding our relationships with animal feed distributors
and end users to build local markets for wet distillers grains, or WDG, the
primary co-product of our ethanol production, and expanding the market for
ethanol by continuing to work with state governments to encourage the adoption
of policies and standards that promote ethanol as a fuel additive and ultimately
as a primary transportation fuel. We also intend to expand our distribution
infrastructure by expanding our ability to provide transportation, storage
and
related logistical services to our customers throughout the Western United
States.
Company History
We
are a
Delaware corporation formed in February 2005. Following our incorporation,
in
March 2005, we completed a share exchange transaction, or Share Exchange
Transaction, with the shareholders of Pacific Ethanol, Inc., a California
corporation, or PEI California, and the holders of the membership interests
of
each of Kinergy, LLC, or Kinergy, and ReEnergy, LLC, or ReEnergy. Upon
completion of the Share Exchange Transaction, we acquired all of the issued
and
outstanding shares of capital stock of PEI California and all of the outstanding
membership interests of each of Kinergy and ReEnergy. Immediately prior to
the
consummation of the Share Exchange Transaction, our predecessor, Accessity
Corp., a New York corporation, or Accessity, reincorporated in the State of
Delaware under the name Pacific Ethanol, Inc.
Our
main
Internet address is http://www.pacificethanol.net.
Our
annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports
on
Form 8-K, amendments to those reports and other Securities and Exchange
Commission, or SEC, filings are available free of charge through our website
as
soon as reasonably practicable after these reports are electronically filed
with, or furnished to, the SEC. Our common stock trades on the Nasdaq Global
Market under the symbol PEIX. The inclusion of our website address in this
Report does not include or incorporate by reference into this Report any
information contained on our website.
Competitive Strengths
We
believe that our competitive strengths include the following:
· Our customer and supplier relationships.
We have
developed strong business relationships with our customers and suppliers. In
particular, we have developed strong business relationships with major and
independent un-branded gasoline suppliers who collectively control the majority
of all gasoline sales in California and other Western states. In addition,
we
have developed strong business relationships with ethanol and grain suppliers
throughout the Western and Midwestern United States.
· Our ethanol distribution network.
We
believe that we have a competitive advantage due to our experience in marketing
to the segment of customers in major metropolitan and rural markets in the
Western United States. We have developed an ethanol distribution network for
delivery of ethanol by truck to virtually every significant fuel terminal as
well as to numerous smaller fuel terminals throughout California and other
Western states. Fuel terminals have limited storage capacity and we have been
successful in securing storage tanks at many of the terminals we service. In
addition, we have an extensive network of third-party delivery trucks available
to deliver ethanol throughout the Western United States.
· Our
strategic
locations.
We
believe that our focus on developing and acquiring ethanol production facilities
in markets where local characteristics create the opportunity to capture a
significant production and shipping cost advantage over competing ethanol
production facilities provides us with significant competitive advantages,
including transportation cost and delivery timing and logistical advantages
and
higher margins associated with the local sale of WDG and other co-products.
· Our
modern technologies.
Our
existing production facilities use the latest production technologies to take
advantage of state-of-the-art technical and operational efficiencies in order
to
achieve lower operating costs and more efficient production of ethanol and
its
co-products, and reduce our use of carbon-based fuels. We expect to implement
these technologies in new production facilities currently under development
and
other planned production facilities.
· Our
experienced management.
Neil M.
Koehler, our President and Chief Executive Officer, has over 20 years of
experience in the ethanol production, sales and marketing industry.
Mr. Koehler is the Director of the California Renewable Fuels Partnership,
a Director of the Renewable Fuels Association, or RFA, and is a frequent speaker
on the issue of renewable fuels and ethanol marketing and production. We believe
that the experience of our management over the past two decades and our ethanol
marketing operations have enabled us to establish valuable relationships in
the
ethanol industry and understand the business of marketing and producing ethanol.
We
believe that these advantages will allow us to capture an increasing share
of
the total market for ethanol and its co-products and earn favorable margins
on
ethanol and its co-products that we produce.
Business and Growth Strategy
Our
primary goal is to become the leading marketer and producer of renewable fuels
in the Western United States. Key elements of our business and growth strategy
to achieve this objective include:
· Expand ethanol marketing revenues, ethanol markets and distribution infrastructure.
We plan
to increase our ethanol marketing revenues by expanding our relationships with
third-party ethanol producers to market higher volumes of ethanol throughout
the
Western United States. In addition, we plan to expand relationships with animal
feed distributors and dairy operators to build local markets for WDG. We also
plan to expand the market for ethanol by continuing to work with state
governments to encourage the adoption of policies and standards that promote
ethanol as a fuel additive and ultimately as a primary transportation fuel.
In
addition, we plan to expand our distribution infrastructure by expanding our
ability to provide transportation, storage and related logistical services
to
our customers throughout the Western United States.
· Add production capacity to meet expected future demand for ethanol.
We are
developing additional ethanol production facilities to meet the expected future
demand for ethanol. We are also exploring opportunities to add production
capacity through strategic acquisitions of existing or pending ethanol
production facilities that meet our cost and location criteria. We intend to
expand our production capacity to 220 million gallons of annual production
capacity by the second quarter of 2008 and 420 million gallons of annual
production capacity by the end of 2010.
· Focus on cost efficiencies.
We plan
to develop or acquire ethanol production facilities in markets where local
characteristics create the opportunity to capture a significant production
and
shipping cost advantage over competing ethanol production facilities. We believe
a combination of factors will enable us to achieve this cost advantage,
including the following:
| |
o
|
Locations
near fuel blending facilities will enable lower ethanol transportation
costs and enjoy timing and logistical advantages over competing locations
requiring ethanol to be shipped over much longer distances.
|
| |
o
|
Locations
adjacent to major rail lines will enable the purchase of corn from
major
corn-producing regions for efficient delivery in large-scale trains.
|
| |
o
|
Locations
near large concentrations of dairy and/or beef cattle will enable
delivery
of WDG over short distances without the need for costly drying processes.
|
In
addition to these location-related efficiencies, we plan to incorporate advanced
design elements into our newly constructed production facilities to take
advantage of state-of-the-art technical and operational efficiencies.
· Explore new technologies
and renewable fuels.
We are
evaluating a number of technologies that may increase the efficiency of our
ethanol production facilities and reduce our use of carbon-based fuels. In
addition, we are exploring the feasibility of using different and potentially
abundant and cost-effective feedstocks, such as cellulosic plant biomass, to
supplement corn as the basic raw material used in the production of ethanol.
· Employ risk mitigation strategies.
We seek
to mitigate our exposure to commodity price fluctuations by purchasing forward
a
portion of our corn and natural gas requirements primarily on a fixed-price
basis and, to a lesser extent, by purchasing corn and natural gas futures
contracts. To mitigate ethanol inventory price risks, we may sell a portion
of
our production forward under fixed-price and indexed contracts. We may hedge
a
portion of the price risks associated with index contracts by selling
exchange-traded unleaded gasoline futures contracts. Proper execution of these
risk mitigation strategies can reduce the volatility of our gross profit
margins.
· Evaluate and pursue acquisition opportunities.
We
intend to evaluate and pursue opportunities to acquire additional ethanol
production, storage and distribution facilities and related infrastructure
currently in operation as financial resources and business prospects make the
acquisition of these facilities advisable. In addition, we may also seek to
acquire facility sites under development.
Industry Overview and Market Opportunity
Overview of Ethanol Market
The
primary applications for fuel-grade ethanol in the United States today
include:
· Octane
enhancer.
On
average, regular unleaded gasoline has an octane rating of 87 and premium
unleaded has an octane rating of 91. In contrast, pure ethanol has an average
octane rating of 113. Adding ethanol to gasoline enables refiners to produce
greater quantities of lower octane blend stock with an octane rating of less
than 87. In addition, ethanol is commonly added to finished regular grade
gasoline as a means of producing higher octane midgrade and premium gasoline.
· Fuel
blending.
In
addition to its performance and environmental benefits, ethanol is used to
extend fuel supplies. As the need for automotive fuel in the United States
increases and the dependence on foreign crude oil and refined products grows,
the United States is increasingly seeking domestic sources of fuel. Much of
the
ethanol blending throughout the United States today is done for the purpose
of
extending the volume of fuel sold at the gas pump. Furthermore, the experience
in Brazil, where ethanol accounts for 40% of all vehicle fuels and is sold
in
blends with gasoline ranging from 25% to 100%, suggests that ethanol could
capture a much greater portion of the United States market in the future.
· Renewable
fuels.
Ethanol
is blended with gasoline in order to enable gasoline refiners to comply with
a
variety of governmental programs, notably the national renewable fuels standard,
or RFS, designed to promote alternatives to fossil fuels. See “—Government
Regulation.”
The
ethanol fuel industry is greatly dependent upon tax policies and environmental
regulations that favor the use of ethanol in motor fuel blends in the United
States. See “—Governmental Regulation.” Ethanol blends have been either wholly
or partially exempt from the federal excise tax on gasoline since 1978. The
current federal excise tax on gasoline is $0.184 per gallon, and is paid at
the
terminal by refiners and marketers. If the fuel is blended with ethanol, the
blender may claim a $0.51 per gallon tax credit for each gallon of ethanol
used
in the mixture. Federal law also requires the sale of oxygenated fuels in
certain carbon monoxide non-attainment Metropolitan Statistical Areas, or MSAs,
during at least four winter months, typically November through February. In
addition, the Energy Policy Act of 2005, which was signed into law in by
President Bush in August 2005, enacted the RFS. The RFS sets a minimum amount
of
renewable fuels (i.e., ethanol, biodiesel or any other liquid fuel produced
from
biomass or biogas) that must be used by fuel refiners. Beginning in 2006, the
minimum amount of renewable fuels that must be used by fuel refiners is 4.0
billion gallons, which increases progressively to 7.5 billion gallons in 2012.
While we believe that the overall national market for ethanol will grow, we
believe that the market for ethanol in certain geographic areas such as
California could experience either increases or decreases in the demand
depending on the preferences of petroleum refiners and state policies. See
“Risk
Factors.”
We
believe that the domestic ethanol industry produced approximately 4.9 billion
gallons of ethanol in 2006, an increase of approximately 25% from the
approximately 3.9 billion gallons of ethanol produced in 2005. We believe that
the ethanol market in California alone was approximately 1.0 billion gallons
in
2006, representing approximately 20% of the national market. However, the
Western United States has relatively few ethanol plants with ethanol production
levels substantially below the demand for ethanol. The balance of ethanol is
shipped via rail from the Midwest to the Western United States. Gasoline and
diesel fuel that supply the major fuel terminals are shipped in pipelines
throughout portions of the Western United States. Unlike gasoline and diesel
fuel, however, ethanol cannot be shipped in these pipelines because ethanol
has
an affinity for mixing with water already present in the pipelines. When mixed,
water dilutes ethanol and creates significant quality control issues. Therefore,
ethanol must be trucked from rail terminals to regional fuel terminals, or
blending racks.
We
believe that approximately 95% of the ethanol produced in the United States
is
made in the Midwest from corn. According to the United States Department of
Energy, ethanol is typically blended at 5.7% to 10% by volume, but is also
blended at up to 85% by volume for vehicles designed to operate on 85% ethanol.
Compared to gasoline, ethanol is generally considered to be less expensive
and
cleaner burning and contains higher octane. We anticipate that the increasing
demand for transportation fuels coupled with limited opportunities for gasoline
refinery expansions and the growing importance of reducing CO2
emissions through the use of renewable fuels will generate additional growth
in
the demand for ethanol in the Western United States.
Ethanol
prices, net of tax incentives offered by the federal government, are generally
positively correlated to fluctuations in gasoline prices. In addition, we
believe that ethanol prices in the Western United States are typically $0.15
to
$0.20 per gallon higher than in the Midwest due to the freight costs of
delivering ethanol from Midwest production facilities.
Total
annual gasoline consumption in the United States is approximately 140 billion
gallons and total annual ethanol consumption currently represents less than
4%
of this amount, or approximately five billion gallons of ethanol. We believe
that the domestic ethanol industry has substantial potential for growth to
reach
what we estimate is an achievable level of at least 10% of the total annual
gasoline consumption in the United States, or approximately 14 billion gallons
of ethanol.
Overview of Ethanol Production Process
The
production of ethanol from starch- or sugar-based feedstocks has been refined
considerably in recent years, leading to a highly-efficient process that we
believe now yields substantially more energy in the ethanol and co-products
than
is required to make the products. The modern production of ethanol requires
large amounts of corn, or other high-starch grains, and water as well as
chemicals, enzymes and yeast, and denaturants such as unleaded gasoline or
liquid natural gas, in addition to natural gas and electricity.
In
the
dry milling process, corn or other high-starch grains are first ground into
meal
and then slurried with water to form a mash. Enzymes are then added to the
mash
to convert the starch into the simple sugar, dextrose. Ammonia is also added
for
acidic (pH) control and as a nutrient for the yeast. The mash is processed
through a high temperature cooking procedure, which reduces bacteria levels
prior to fermentation. The mash is then cooled and transferred to fermenters,
where yeast is added and the conversion of sugar to ethanol and CO2
begins.
After
fermentation, the resulting “beer” is transferred to distillation, where the
ethanol is separated from the residual “stillage.” The ethanol is concentrated
to 190 proof using conventional distillation methods and then is dehydrated
to
approximately 200 proof, representing 100% alcohol levels, in a molecular sieve
system. The resulting anhydrous ethanol is then blended with about 5%
denaturant, which is usually gasoline, and is then ready for shipment to
market.
The
residual stillage is separated into a coarse grain portion and a liquid portion
through a centrifugation process. The soluble liquid portion is concentrated
to
about 40% dissolved solids by an evaporation process. This intermediate state
is
called condensed distillers solubles, or syrup. The coarse grain and syrup
portions are then mixed to produce WDG or can be mixed and dried to produce
dried distillers grains with solubles, or DDGS. Both WDG and DDGS are
high-protein animal feed products.
Overview of Distillers Grains Market
According
to the National Corn Growers Association, approximately 8.9 million tons of
dried distillers grains were produced during the 2005 and 2006 crop year. Dairy
cows and beef cattle are the primary consumers of distillers grains. According
to Rincker and Berger, in their 2003 article entitled Optimizing the Use of Distiller Grain for Dairy-Beef Production,
a dairy
cow can consume 12-15 pounds of WDG per day in a balanced diet. At this rate,
the WDG output of an ethanol facility that produces 35 million gallons of
ethanol per year can feed approximately 105,000-130,000 dairy cows.
Successful
and profitable delivery of DDGS from the Midwest faces a number of challenges,
including product inconsistency, handling difficulty and lower feed values.
All
of these challenges are mitigated with a consistent supply of WDG from a local
plant. DDGS delivered via rail from the Midwest undergoes an intense drying
process and exposure to extreme heat at the production facility and in the
railcars, during which various nutrients are burned off which reduces the
nutritional composition of the final product. In addition, DDGS shipped via
rail
can take as long as two weeks to be delivered to the Western United States,
and
scheduling errors or rail yard mishaps can extend delivery time even further.
DDGS tends to solidify and set in place as it sits in a rail car and thus
expedient delivery is important. After solidifying and setting in place, DDGS
becomes very difficult and thus expensive to unload. During the summer, rail
cars typically take a full day to unload but can take longer. Also, DDGS shipped
from the Midwest can be inconsistent because some Midwest producers use a
variety of feedstocks depending on the availability and price of competing
crops. Corn, milo sorghum, barley and wheat are all common feedstocks used
for
the production of ethanol but lead to significant variability in the nutritional
composition of distillers grains. Dairies depend on rations that are calculated
with precision and a subtle difference in the makeup of a key ingredient can
significantly affect bovine milk production. By not drying the distillers grains
and by shipping them locally, we believe that we will be able to preserve the
feed integrity of these grains.
Historically,
the market price for distillers grains has been stable in comparison to the
market price for ethanol. We believe that the market price of DDGS is determined
by a number of factors, including the market value of corn, soybean meal and
other competitive protein ingredients, the performance or value of DDGS in
a
particular feed formulation and general market forces of supply and demand.
We
also believe that nationwide, the market price of distillers grains historically
has been influenced by producers of distilled spirits and more recently by
the
large corn dry-millers that operate fuel ethanol plants. The market price of
distillers grains is also often influenced by nutritional models that calculate
the feed value of distillers grains by nutritional content.
Customers
We
produce and also purchase from third-parties and resell ethanol to various
customers in the Western United States. We also arrange for transportation,
storage and delivery of ethanol purchased by our customers through our
agreements with third-party service providers. Our revenue is obtained primarily
from sales of ethanol to large oil companies. We began producing ethanol in
the
fourth quarter of 2006.
During
2006 and 2005, we produced or purchased from third parties and resold an
aggregate of approximately 102 million and 67 million gallons of fuel-grade
ethanol to approximately 60 customers and 27 customers, respectively. Sales
to
our two largest customers represented approximately 25% of our net sales in
2006
and sales to our three largest customers represented approximately 39% of our
net sales in 2005. Sales to each of our other customers did not represent 10%
or
more of our net sales in either 2006 or 2005. Customers who accounted for 10%
or
more of our net sales in 2006 were New West Petroleum and Chevron Products
USA.
Customers who accounted for 10% or more of our net sales in 2005 were New West
Petroleum, Chevron Products USA, and Southern Counties Oil Co.
Most
of
the major metropolitan areas in the Western United States have fuel terminals
served by rail, but other major metropolitan areas and more remote smaller
cities and rural areas do not. We believe that we have a competitive advantage
due to our experience in marketing to the segment of customers in major
metropolitan and rural markets in the Western United States. We manage the
complicated logistics of shipping ethanol purchased from third-parties from
the
Midwest by rail to intermediate storage locations throughout the Western United
States and trucking the ethanol from these storage locations to blending racks
where the ethanol is blended with gasoline. We believe that by establishing
an
efficient service for truck deliveries to these more remote locations, we have
differentiated ourselves from our competitors, which has resulted in increased
sales and profitability. In addition, by producing ethanol in the Western United
States, we believe that we will benefit from our ability to increase spot sales
of ethanol from this additional supply following ethanol price spikes caused
from time to time by rail delays in delivering ethanol from the Midwest to
the
Western United States.
In
addition to producing ethanol, we produce ethanol co-products such as WDG.
We
expect to be one of the few WDG producers with production facilities located
in
the Western United States. We intend to position WDG as the protein feed of
choice for cattle based on its nutritional composition, consistency of quality
and delivery, ease of handling and its mixing ability with minerals and other
feed ingredients. We believe that WDG has an ideal moisture level to carry
minerals and other feed ingredients and we expect to increase our profit margins
by providing WDG to the feed market in the Western United States.
Suppliers
Our
marketing operations are dependent upon various producers of fuel-grade ethanol
for our ethanol supplies. In addition, we provide ethanol transportation,
storage and delivery services through third-party service providers with whom
we
have contracted to receive ethanol at agreed upon locations from our suppliers
and to store and/or deliver the ethanol to agreed upon locations on behalf
of
our customers. These contracts generally run from year-to-year, subject to
termination by either party upon advance written notice before the end of the
then-current annual term. We also transport ethanol with our own fleet of
railcars, which we are expanding to support the continuing growth of our
business.
During
2006 and 2005, we purchased an aggregate of approximately 88 million and 67
million gallons of fuel-grade ethanol from approximately 22 suppliers and 15
suppliers, respectively. Purchases from our four and three largest suppliers
represented approximately 64% and 59% of our total purchases in 2006 and 2005,
respectively. Purchases from each of our other suppliers did not represent
10%
or more of total purchases in either 2006 or 2005.
Our
ethanol production operations are dependent upon various raw materials
suppliers, including suppliers of corn, natural gas, electricity and water.
The
cost of corn is the most important variable cost associated with the production
of ethanol. An ethanol plant must be able to efficiently ship corn from the
Midwest via rail and then cheaply and reliably truck processed ethanol to local
markets. We believe that our existing and planned grain receiving facilities
at
our current and planned ethanol plants are or will be some of the most efficient
grain receiving facilities in the United States. We source corn using standard
contracts, such as spot purchases, forward purchases and basis contracts. We
seek to limit our exposure to raw material price fluctuations by purchasing
forward a portion of our corn requirements in a fixed price basis and by
purchasing corn and other raw materials futures contracts. In addition, to
help
protect against supply disruptions, we typically maintain inventories of corn
at
each of our facilities.
Production
Facilities
The
table
below provides an overview as of March 2007 of our existing ethanol production
facilities and our facilities under construction or development.
| |
Madera
Facility
|
Front
Range
Facility(1)
|
Boardman
Facility(2)
|
California
Facility(2)
|
Imperial
Valley
Facility(2)
|
Magic
Valley
Facility(2)
|
|
Location
|
Madera,
CA
|
Windsor,
CO
|
Boardman,
OR
|
TBA
|
Brawley,
CA
|
Burley,
ID
|
|
Quarter/Year
completed or scheduled to be completed
|
4th
Qtr., 2006
|
2nd
Qtr., 2006
|
2nd
Qtr., 2007
|
2nd
Qtr., 2008
|
2nd
Qtr., 2008
|
2nd
Qtr., 2008
|
|
Annual
ethanol nameplate production capacity (in millions of
gallons)
|
35
|
40
|
35
|
50
|
50
|
50
|
|
Ownership
|
100%
|
42%
|
100%
|
100%
|
100%
|
100%
|
|
Primary
energy source
|
Natural
Gas
|
Natural
Gas
|
Natural
Gas
|
Natural
Gas
|
Natural
Gas
|
Natural
Gas
|
|
Estimated
annual WDG production capacity (in thousands of tons)
|
293
|
335
|
293
|
418
|
418
|
418
|
———————
(1) We
own
42% of Front Range, the entity that owns the facility located in Windsor,
Colorado.
(2) Data
is
estimated as of completion of construction.
Site Location
Criteria
Our
site
location criteria encompass many factors, including proximity of feedstock,
fuel
blending facilities and major rail lines, good road access, water and utility
availability and adequate space for equipment and truck movement. One of our
primary business and growth strategies is to develop or acquire ethanol
production facilities in markets where local characteristics create the
opportunity to capture a significant production and shipping cost advantage
over
competing ethanol production facilities. Therefore, it is critical that our
production sites are located near fuel blending facilities in the Western United
States because many of our competitors ship ethanol over long distances from
the
Midwest. Also, because our planned facilities are expected to be located in
the
Western United States, close proximity to major rail lines to receive corn
shipments from Midwest producers is critical.
Potential Future Facilities
and Expansions
We
intend
to expand our production capacity to 220 million gallons of annual production
capacity by the second quarter of 2008 and 420 million gallons of annual
production capacity by the end of 2010. We will determine whether additional
sites are suitable for construction of ethanol production facilities in the
future. We intend to evaluate and pursue opportunities to acquire additional
ethanol production, storage and distribution facilities and related
infrastructure currently in operation as financial resources and business
prospects make the acquisition of these facilities advisable. In addition,
we
may also seek to acquire facility sites under development. We are also
investigating the feasibility of expanding one or more existing facilities
to
significantly increase their production capacity. Such an expansion would entail
constructing additional structures and systems adjacent to an existing facility
and integrating certain processes.
Marketing Arrangements
We
have
exclusive agreements with third-party ethanol producers, including Phoenix
Bio-Industries, LLC, which was recently acquired by Altra Inc., and Front Range,
the latter of which we are a minority owner, to market and sell their entire
ethanol production volumes. Phoenix Bio-Industries, LLC owns and operates an
ethanol production facility in Goshen, California with annual nameplate
production capacity of 25 million gallons. Front Range, owns and operates an
ethanol production facility in Windsor, Colorado with annual nameplate
production capacity of 40 million gallons. We also have an exclusive agreement
to market and sell WDG produced at the facility owned by Front Range. We intend
to evaluate and pursue opportunities to enter into marketing arrangements with
other ethanol producers as business prospects make these marketing arrangements
advisable.
Competition
We
operate in the highly-competitive ethanol marketing and production industry.
The
largest ethanol producer in the United States is ADM, with wet and dry mill
plants in the Midwest and a total production capacity of about 1.1 billion
gallons per year, or approximately 23% of total United States ethanol production
in 2006. According to the RFA, as of January 2006, there were approximately
110
ethanol plants currently operating with a combined annual production capacity
of
approximately 5.5 billion gallons. In addition, 73 ethanol plants and 8
expansions of existing plants were under construction with an estimated combined
future annual production capacity of approximately 6.0 billion gallons. We
believe that most of the growth in ethanol production over the last ten years
has been by farmer-owned cooperatives that have commenced or expanded ethanol
production as a strategy for enhancing demand for corn and adding value through
processing. We believe that many smaller ethanol plants rely on marketing groups
such as Ethanol Products, Aventine Renewable Energy, Inc. and Renewable Products
Marketing Group LLC to move their product to market. We believe that, because
ethanol is a commodity, many of the Midwest ethanol producers can target the
Western United States, though ethanol producers further west in states such
as
Nebraska and Kansas often enjoy delivery cost advantages.
We
believe that our competitive strengths include our strategic locations in the
Western United States, our extensive ethanol distribution network, our strong
customer and supplier relationships, our use of modern technologies at our
production facilities and our experienced management. We believe that these
advantages will allow us to capture an increasing share of the total market
for
ethanol and its co-products and earn favorable margins on ethanol and its
co-products that we produce.
Our
strategic focus on particular geographic locations designed to exploit cost
efficiencies may nevertheless result in higher than expected costs as a result
of more expensive raw materials and related shipping costs, such as corn, which
generally must be transported from the Midwest. If the costs of producing and
shipping ethanol and its co-products over short distances is not advantageous
relative to the costs of obtaining raw materials from the Midwest, then the
planned benefits of our strategic locations may be lost.
Governmental Regulation
Our
business is subject to extensive and frequently changing federal, state and
local laws and regulations relating to the protection of the environment. These
laws, their underlying regulatory requirements and their enforcement, some
of
which are described below, impact, or may impact, our existing and proposed
business operations by imposing:
| |
·
|
restrictions
on our existing and proposed business operations and/or the need
to
install enhanced or additional controls;
|
| |
·
|
the
need to obtain and comply with permits and
authorizations;
|
| |
·
|
liability
for exceeding applicable permit limits or legal requirements, in
certain
cases for the remediation of contaminated soil and groundwater
at our
facilities, contiguous and adjacent properties and other properties
owned
and/or operated by third parties; and
|
| |
·
|
specifications
for the ethanol we market and
produce.
|
In
addition, some of the governmental regulations to which we are subject are
helpful to our ethanol marketing and production business. The ethanol fuel
industry is greatly dependent upon tax policies and environmental regulations
that favor the use of ethanol in motor fuel blends in North America. Some of
the
governmental regulations applicable to our ethanol marketing and production
business are briefly described below.
Federal Excise Tax Exemption
Ethanol
blends have been either wholly or partially exempt from the federal excise
tax
on gasoline since 1978. The exemption has ranged from $0.04 to $0.06 per gallon
of gasoline during that 25-year period. The current federal excise tax on
gasoline is $0.184 per gallon, and is paid at the terminal by refiners and
marketers. If the fuel is blended with ethanol, the blender may claim a $0.51
per gallon tax credit for each gallon of ethanol used in the mixture. The
federal excise tax exemption was revised and its expiration date was extended
for the sixth time since its inception as part of the American Jobs Creation
Act
of 2004. The new expiration date of the federal excise tax exemption is December
31, 2010. We believe that it is highly likely that this tax incentive will
be
extended beyond 2010 if Congress deems it necessary for the continued growth
and
prosperity of the ethanol industry.
Clean Air Act Amendments of 1990
In
November 1990, a comprehensive amendment to the Clean Air Act of 1977
established a series of requirements and restrictions for gasoline content
designed to reduce air pollution in identified problem areas of the United
States. The two principal components affecting motor fuel content are the
oxygenated fuels program, which is administered by states under federal
guidelines, and a federally supervised reformulated gasoline, or RFG, program.
Oxygenated
Fuels Program
Federal
law requires the sale of oxygenated fuels in certain carbon monoxide
non-attainment MSAs during at least four winter months, typically November
through February. Any additional MSAs not in compliance for a period of two
consecutive years in subsequent years may also be included in the program.
The
EPA Administrator is afforded flexibility in requiring a shorter or longer
period of use depending upon available supplies of oxygenated fuels or the
level
of non-attainment. This law currently affects the Los Angeles area, where over
150 million gallons of ethanol are blended with gasoline each
winter.
Reformulated
Gasoline Program
The
Clean
Air Act Amendments of 1990 established special standards effective January
1,
1995 for the most polluted ozone non-attainment areas: Los Angeles Area,
Baltimore, Chicago Area, Houston Area, Milwaukee Area, New York City Area,
Hartford, Philadelphia Area and San Diego, with provisions to add other areas
in
the future if conditions warrant. California’s San Joaquin Valley, the location
of our Madera County ethanol plant, was added in 2002. At the outset of the
RFG
program there were a total of 96 MSAs not in compliance with clean air standards
for ozone, which currently represents approximately 60% of the national
market.
The
RFG
program also includes a provision that allows individual states to “opt into”
the federal program by request of the governor, to adopt standards promulgated
by California that are stricter than federal standards, or to offer alternative
programs designed to reduce ozone levels. Nearly all of the Northeast and middle
Atlantic areas from Washington, D.C., to Boston not under the federal mandate
have “opted into” the federal standards.
These
state mandates in recent years have created a variety of gasoline grades to
meet
different regional environmental requirements. RFG accounts for about 30% of
nationwide gasoline consumption. California refiners blend a minimum of 2.0%
oxygen by weight. This is the equivalent of 5.7% ethanol in every gallon of
gas,
or roughly 1.0 billion gallons of ethanol per year in California
alone.
National Energy Legislation
The
Energy Policy Act of 2005 was signed into law by President Bush in August 2005.
The Energy Policy Act of 2005 substituted the then existing oxygenation program
in the RFG program with the RFS. The RFS sets a minimum amount of renewable
fuels that must be used by fuel refiners. Beginning in 2006, the minimum amount
of renewable fuels that must be used by fuel refiners is 4.0 billion gallons,
which increases progressively to 7.5 billion gallons in 2012. While we believe
that the overall national market for ethanol will grow, we also believe that
the
market for ethanol in certain geographic areas such as California could
experience either increases or decreases in demand depending on the preferences
of petroleum refiners and state policies. See “Risk Factors.”
State
Energy Legislation and Regulations
State
energy legislation and regulations may affect the demand for ethanol. California
recently passed legislation regulating the total emissions of CO2
from
vehicles and other sources. In 2006, the State of Washington passed a statewide
renewable fuel standard effective December 1, 2008. We believe other states
may
also enact their own renewable fuel standards.
On
January 18, 2007, California’s Governor signed an executive order directing the
California Air Resource Board, or CARB, to implement a Low Carbon Fuels Standard
for transportation fuels. The Governor’s office estimates that the standard will
have the effect of increasing current renewable fuels use in California by
three
to five times by the year 2020.
Additional Environmental Regulations
In
addition to the governmental regulations applicable to the ethanol marketing
and
production industries described above, our business is subject to additional
federal, state and local environmental regulations, including regulations
established by the EPA, the California Air Quality Management District, the
San
Joaquin Valley Air Pollution Control District and the CARB. We cannot predict
the manner or extent to which these regulations will harm or help our business
or the ethanol production and marketing industry in general.
Employees
As
of
March 7, 2007, we employed 78 persons on a full-time basis, including through
our subsidiaries. Our employees are highly skilled, and our success will depend
in part upon our ability to retain such employees and attract new qualified
employees who are in great demand. We have never had a work stoppage or strike,
and no employees are presently represented by a labor union or covered by a
collective bargaining agreement. We consider our relations with our employees
to
be good.
Risks
Related to our Business
We
have incurred losses in the past and we may incur losses in the future. If
we
continue to incur losses, we will experience negative cash flow, which may
hamper our operations, may prevent us from expanding our business and may cause
our stock price to decline.
We
have
incurred losses in the past. For the years ended December 31, 2006 and
2005, we incurred net losses of approximately $142,000 and $9.9 million,
respectively. We expect to rely on cash on hand, cash, if any, generated from
our operations and future financing activities to fund all of the cash
requirements of our business. If our net losses continue, we will experience
negative cash flow, which may hamper current operations and may prevent us
from
expanding our business. We may be unable to attain, sustain or increase
profitability on a quarterly or annual basis in the future. If we do not
achieve, sustain or increase profitability our stock price may
decline.
The
high concentration of our sales within the ethanol marketing and production
industry could result in a significant reduction in sales and negatively affect
our profitability if demand for ethanol declines.
Our
revenue is and will continue to be derived primarily from sales of ethanol.
Currently, the predominant oxygenate used to blend with gasoline is ethanol.
Ethanol competes with several other existing products and other alternative
products could also be developed for use as fuel additives. We expect to be
completely focused on the marketing and production of ethanol and its
co-products for the foreseeable future. We may be unable to shift our business
focus away from the marketing and production of ethanol to other renewable
fuels
or competing products. Accordingly, an industry shift away from ethanol or
the
emergence of new competing products may reduce the demand for ethanol. A
downturn in the demand for ethanol would significantly and adversely affect
our
sales and profitability.
If
the expected increase in ethanol demand does not occur, or if ethanol demand
decreases, there may be excess capacity in our industry which would likely
cause
a decline in ethanol prices, adversely impacting our results of operations,
cash
flows and financial condition.
Domestic
ethanol production capacity has increased steadily from an annualized rate
of
1.7 billion gallons per year in January of 1999 to 5.5 billion gallons per
year
in December 2006 according to the RFA. In addition, there is a significant
amount of capacity being added to our industry. We believe that approximately
4.6 billion gallons per year of production capacity is currently under
construction. This capacity is being added to address anticipated increases
in
demand. Moreover, under the United States Department of Agriculture’s CCC
Bioenergy Program, which expired September 30, 2006, the federal government
made
payments of up to $150 million annually to ethanol producers that increase
their
production. This created an additional incentive to develop excess capacity.
However, demand for ethanol may not increase as quickly as expected, or at
all.
If the ethanol industry has excess capacity, a fall in prices will likely occur
which will have an adverse impact on our results of operations, cash flows
and
financial condition. Excess capacity may result from the increases in capacity
coupled with insufficient demand. Demand could be impaired due to a number
of
factors, including regulatory developments and reduced United States gasoline
consumption. Reduced gasoline consumption could occur as a result of increased
gasoline or oil prices. For example, price increases could cause businesses
and
consumers to reduce driving or acquire vehicles with more favorable gasoline
mileage capabilities.
We
have identified seven material weaknesses in our internal control over financial
reporting and cannot assure you that additional material weaknesses will not
be
identified in the future. If our internal control over financial reporting
or
disclosure controls and procedures are not effective, there may be errors in
our
financial statements that could require a restatement or our filings may not
be
timely and investors may lose confidence in our reported financial information,
which could lead to a decline in our stock price.
Section
404 of the Sarbanes-Oxley Act of 2002 requires us to evaluate the effectiveness
of our internal control over financial reporting as of the end of each year,
and
to include a management report assessing the effectiveness of our internal
control over financial reporting in each Annual Report on Form 10-K. Section
404
also requires our independent registered public accounting firm to attest to,
and report on, management’s assessment of our internal control over financial
reporting.
We
have
identified the following seven material weaknesses in our internal control
over
financial reporting: (i) we had not effectively implemented comprehensive
entity-level internal controls; (ii) we did not have a sufficient complement
of
personnel with appropriate training and experience in generally accepted
accounting principals; (iii) we did not adequately segregate the duties of
different personnel within our accounting group due to an insufficient
complement of staff; (iv) we did not perform adequate oversight of certain
accounting functions and maintained inadequate documentation of management
review and approval of accounting transactions and financial reporting
processes; (v) we did not have adequate controls governing major account invoice
processing and payment; (vi) we had not fully implemented certain control
activities and capabilities included in the design of our enterprise resource
platform, or ERP, system; and (vii) we did not have adequate access and data
and
formulaic integrity controls over critical spreadsheets used in connection
with
accounting and financial reporting. See “Controls and Procedures.”
Our
management, including our Chief Executive Officer and Acting Chief Financial
Officer, does not expect that our internal control over financial reporting
will
prevent all error and all fraud. A control system, no matter how well designed
and operated, can provide only reasonable, not absolute, assurance that the
control system’s objectives will be met. Further, the design of a control system
must reflect the fact that there are resource constraints, and the benefits
of
controls must be considered relative to their costs. Controls can be
circumvented by the individual acts of some persons, by collusion of two or
more
people, or by management override of the controls. Over time, controls may
become inadequate because changes in conditions or deterioration in the degree
of compliance with policies or procedures may occur. Because of the inherent
limitations in a cost-effective control system, misstatements due to error
or
fraud may occur and not be detected.
As
a
result, we cannot assure you that significant deficiencies or material
weaknesses in our internal control over financial reporting will not be
identified in the future. Any failure to maintain or implement required new
or
improved controls, or any difficulties we encounter in their implementation,
could result in significant deficiencies or material weaknesses, cause us to
fail to timely meet our periodic reporting obligations, or result in material
misstatements in our financial statements. Any such failure could also adversely
affect the results of periodic management evaluations and annual auditor
attestation reports regarding disclosure controls and the effectiveness of
our
internal control over financial reporting required under Section 404 of the
Sarbanes-Oxley Act of 2002 and the rules promulgated thereunder. The existence
of a material weakness could result in errors in our financial statements that
could result in a restatement of financial statements, cause us to fail to
timely meet our reporting obligations and cause investors to lose confidence
in
our reported financial information, leading to a decline in our stock
price.
We
may not be able to implement our planned expansion strategy, including as a
result of our failure to successfully manage our growth, which would prevent
us
from achieving our goals.
Our
strategy envisions a period of rapid growth. We plan to grow our business by
investing in new facilities and/or acquiring existing facilities or sites under
development as well as pursuing other business opportunities such as the
production of other renewable fuels to the extent we deem those opportunities
advisable. We believe that there is increasing competition for suitable
production sites. We may not find suitable additional sites for construction
of
new facilities, suitable acquisition candidates or other suitable expansion
opportunities.
We
will
need additional financing to implement our expansion strategy and we may not
have access to the funding required for the expansion of our business or such
funding may not be available to us on acceptable terms. We plan to finance
the
expansion of our business with additional indebtedness. We may also issue
additional equity securities to help finance our expansion. We could face
financial risks associated with incurring additional indebtedness, such as
reducing our liquidity and access to financial markets and increasing the amount
of cash flow required to service such indebtedness, or associated with issuing
additional stock, such as dilution of ownership and earnings. In addition,
we
are planning the financing of our expansion strategy and are initially using
our
existing cash to implement this strategy based on the belief that we can secure
additional debt financing in the future in order to complete our expansion.
If
we are unable to secure this debt financing, we will suffer from a lack of
capital resources, our planned expansion strategy may be less successful than
if
we had planned solely on using our existing cash to finance our expansion,
and
our business and prospects may be materially and adversely
effected.
We
must
also obtain numerous regulatory approvals and permits in order to construct
and
operate additional or expanded production facilities. These requirements may
not
be satisfied in a timely manner or at all. Federal and state governmental
requirements may substantially increase our costs, which could have a material
adverse effect on our results of operations and financial position. Our
expansion plans may also result in other unanticipated adverse consequences,
such as the diversion of management’s attention from our existing operations.
Our
construction costs may also increase to levels that would make a new production
facility too expensive to complete or unprofitable to operate. We have not
entered into any construction contracts, other than site acquisition
arrangements and engineering contracts, that might limit our exposure to higher
costs in developing and completing any new facilities. Contractors, engineering
firms, construction firms and equipment suppliers also receive requests and
orders from other ethanol companies and, therefore, we may not be able to secure
their services or products on a timely basis or on acceptable financial terms.
We may suffer significant delays or cost overruns as a result of a variety
of
factors, such as shortages of workers or materials, transportation constraints,
adverse weather, unforeseen difficulties or labor issues, any of which could
prevent us from commencing operations as expected at our facilities.
Rapid
growth may impose a significant burden on our administrative and operational
resources. Our ability to effectively manage our growth will require us to
substantially expand the capabilities of our administrative and operational
resources and to attract, train, manage and retain qualified management,
technicians and other personnel. We may be unable to do so.
We
may
not find additional appropriate sites for new facilities and we may not be
able
to finance, construct, develop or operate these new facilities successfully.
We
also may be unable to find suitable acquisition candidates. Accordingly, we
may
fail to implement our planned expansion strategy, including as a result of
our
failure to successfully manage our growth, and as a result, we may fail to
achieve our goals.
The
market price of ethanol is volatile and subject to significant fluctuations,
which may cause our profitability
or losses to fluctuate significantly.
The
market price of ethanol is dependent upon many factors, including the price
of
gasoline, which is in turn dependent upon the price of petroleum. Petroleum
prices are highly volatile and difficult to forecast due to frequent changes
in
global politics and the world economy. The distribution of petroleum throughout
the world is affected by incidents in unstable political environments, such
as
Iraq, Iran, Kuwait, Saudi Arabia, the former U.S.S.R. and other countries and
regions. The industrialized world depends critically upon oil from these areas,
and any disruption or other reduction in oil supply can cause significant
fluctuations in the prices of oil and gasoline. We cannot predict the future
price of oil or gasoline and may establish unprofitable prices for the sale
of
ethanol due to significant fluctuations in market prices. For example, our
average sales price of ethanol declined by approximately 25% from our 2004
average sales price per gallon in five months from January 2005 through May
2005
and reversed this decline and increased to approximately 55% above our 2004
average sales price per gallon in four months from June 2005 through September
2005; and from September through December 2005, our average sales price of
ethanol trended downward, but reversed its trend by rising approximately 36%
above our 2005 average price per gallon by the end of 2006. In recent years,
the
prices of gasoline, petroleum and ethanol have all reached historically
unprecedented high levels. If the prices of gasoline and petroleum decline,
we
believe that the demand for and price of ethanol may be adversely affected.
Fluctuations in the market price of ethanol may cause our profitability or
losses to fluctuate significantly.
We
believe that the production of ethanol is expanding rapidly. There are a number
of new plants under construction and planned for construction, both inside
and
outside California. We expect existing ethanol plants to expand by increasing
production capacity and actual production. Increases in the demand for ethanol
may not be commensurate with increasing supplies of ethanol. Thus, increased
production of ethanol may lead to lower ethanol prices. The increased production
of ethanol could also have other adverse effects. For example, increased ethanol
production could lead to increased supplies of co-products from the production
of ethanol, such as WDG. Those increased supplies could lead to lower prices
for
those co-products. Also, the increased production of ethanol could result in
increased demand for corn. This could result in higher prices for corn and
cause
higher ethanol production costs and, in the event that we are unable to pass
increases in the price of corn to our customers, will result in lower profit
margins. We cannot predict the future price of ethanol, WDG or corn. Any
material decline in the price of ethanol or WDG, or any material increase in
the
price of corn, will adversely affect our sales and profitability.
We
rely heavily on our President and Chief Executive Officer, Neil Koehler. The
loss of his services could adversely affect our ability to source ethanol from
our key suppliers and our ability to sell ethanol to our customers.
Our
success depends, to a significant extent, upon the continued services of Neil
Koehler, who is our President and Chief Executive Officer. For example, Mr.
Koehler has developed key personal relationships with our ethanol suppliers
and
customers. We greatly rely on these relationships in the conduct of our
operations and the execution of our business strategies. The loss of Mr. Koehler
could, therefore, result in the loss of our favorable relationships with one
or
more of our ethanol suppliers and customers. In addition, Mr. Koehler has
considerable experience in the construction, start-up and operation of ethanol
production facilities and in the ethanol marketing business. Although we have
entered into an employment agreement with Mr. Koehler, that agreement is of
limited duration and is subject to early termination by Mr. Koehler under
certain circumstances. In addition, we do not maintain “key person” life
insurance covering Mr. Koehler or any other executive officer. The loss of
Mr.
Koehler could also significantly delay or prevent the achievement of our
business objectives.
The
raw materials and energy necessary to produce ethanol may be unavailable or
may
increase in price, adversely affecting our sales and profitability.
The
principal raw material we use to produce ethanol and its co-products is corn.
As
a result, changes in the price of corn can significantly affect our business.
In
general, rising corn prices produce lower profit margins and, therefore,
represent unfavorable market conditions. This is especially true since market
conditions generally do not allow us to pass along increased corn costs to
our
customers because the price of ethanol is primarily determined by other factors,
such as the price of oil and gasoline. At certain levels, corn prices may make
ethanol uneconomical to use in markets where the use of fuel oxygenates is
not
mandated.
The
price
of corn is influenced by general economic, market and regulatory factors. These
factors include weather conditions, crop conditions and yields, farmer planting
decisions, government policies and subsidies with respect to agriculture and
international trade and global demand and supply. The significance and relative
impact of these factors on the price of corn is difficult to predict. Any event
that tends to negatively impact the supply of corn will tend to increase prices
and potentially harm our business. Corn prices as measured by the United States
Department of Agriculture, or USDA, reported as prices received, had increased
57% over the previous year by December 2006. The USDA’s December 2006 crop
report estimated that corn bought by ethanol plants will represent approximately
17% of the 2006/2007 crop year’s total corn supply, up from 13% in the prior
crop year. The increasing ethanol capacity could boost demand for corn and
result in the sustainment or further increase in corn prices.
The
production of ethanol also requires a significant amount of other raw materials
and energy, primarily water, electricity and natural gas. Our production
facilities require significant and uninterrupted supplies of water, electricity
and natural gas. The prices of electricity and natural gas have fluctuated
significantly in the past and may fluctuate significantly in the future. Local
water, electricity and gas utilities may not be able to reliably supply the
water, electricity and natural gas that our facilities will need or may not
be
able to supply such resources on acceptable terms. In addition, if there is
an
interruption in the supply of water or energy for any reason, we may be required
to halt ethanol production.
The
United States ethanol industry is highly dependent upon a myriad of federal
and
state legislation and regulation and any changes in such legislation or
regulation could materially adversely affect our results of operations and
financial condition.
The
elimination or significant reduction in the Federal Excise Tax Credit could
have
a material adverse effect on our results of operations.
The
production of ethanol is made significantly more competitive by federal tax
incentives. The federal excise tax incentive program, which is scheduled to
expire on December 31, 2010, allows gasoline distributors who blend ethanol
with
gasoline to receive a federal excise tax rate reduction for each blended gallon
they sell regardless of the blend rate. The current federal excise tax on
gasoline is $0.184 per gallon, and is paid at the terminal by refiners and
marketers. If the fuel is blended with ethanol, the blender may claim a $0.51
per gallon tax credit for each gallon of ethanol used in the mixture. The
federal excise tax incentive program may not be renewed prior to its expiration
in 2010, or if renewed, it may be renewed on terms significantly less favorable
than current tax incentives. The elimination or significant reduction in the
federal excise tax incentive program could have a material adverse effect on
our
results of operations.
Waivers
of the RFS minimum levels of renewable fuels included in gasoline could have
a
material adverse affect on our results of operations.
Under
the
Energy Policy Act of 2005, the Department of Energy, in consultation with the
Secretary of Agriculture and the Secretary of Energy, may waive the RFS mandate
with respect to one or more states if the administrator determines that
implementing the requirements would severely harm the economy or the environment
of a state, a region or the United States, or that there is inadequate supply
to
meet the requirement. Any waiver of the RFS with respect to one or more states
would adversely offset demand for ethanol and could have a material adverse
effect on our results of operations and financial condition.
While
the Energy Policy Act of 2005 imposes the RFS, it does not mandate the use
of
ethanol and eliminates the oxygenate requirement for reformulated gasoline
in
the RFG program program included in the Clean Air Act.
The
RFG
program’s oxygenate requirements contained in the Clean Air Act, which,
according to the RFA, accounted for approximately 2.0 billion gallons of ethanol
use in 2004, was completely eliminated on May 5, 2006 by the Energy Policy
Act
of 2005. While the RFA expects that ethanol should account for the largest
share
of renewable fuels produced and consumed under the RFS, the RFS is not limited
to ethanol and also includes biodiesel and any other liquid fuel produced from
biomass or biogas. The elimination of the oxygenate requirement for reformulated
gasoline in the RFG program included in the Clean Air Act may result in a
decline in ethanol consumption in favor of other alternative fuels, which in
turn could have a material adverse effect on our results of operations and
financial condition.
Certain
countries can export ethanol to the United States duty-free, which may undermine
the ethanol production industry in the United States.
Imported
ethanol is generally subject to a $0.54 per gallon tariff and a 2.5% ad valorem
tax that was designed to offset the $0.51 per gallon ethanol subsidy available
under the federal excise tax incentive program for refineries that blend ethanol
in their fuel. There is a special exemption from the tariff for ethanol imported
from 24 countries in Central America and the Caribbean islands which is limited
to a total of 7.0% of United States production per year (with additional
exemptions for ethanol produced from feedstock in the Caribbean region over
the
7.0% limit). In May 2006, bills were introduced in both the United States House
of Representatives and United States Senate to repeal the $0.54 per gallon
tariff. We do not know the extent to which the volume of imports would increase
or the effect on United States prices for ethanol if this proposed legislation
is enacted or if the tariff is not renewed beyond its current expiration in
December 2007. In addition The North America Free Trade Agreement countries,
Canada and Mexico, are exempt from duty. Imports from the exempted countries
have increased in recent years and are expected to increase further as a result
of new plants under development. The import of ethanol duty-free from a country
exempted from the tariff may negatively impact the demand for domestic ethanol
and the price at which we sell our ethanol.
Our
purchase and sale commitments as well as inventory of ethanol held for sale
subject us to the risk of fluctuations in the price of ethanol, which may result
in lower or even negative gross margins and which could materially and adversely
affect our profitability.
Our
purchases and sales of ethanol are not always matched with sales and purchases
of ethanol at prevailing market prices. We commit from time to time to the
sale
of ethanol to our customers without corresponding and commensurate commitments
for the supply of ethanol from our suppliers, which subjects us to the risk
of
an increase in the price of ethanol. We also commit from time to time to the
purchase of ethanol from our suppliers without corresponding and commensurate
commitments for the purchase of ethanol by our customers, which subjects us
to
the risk of a decline in the price of ethanol. In addition, we generally
increase inventory levels in anticipation of rising ethanol prices and decrease
inventory levels in anticipation of declining ethanol prices. As a result,
we
are subject to the risk of ethanol prices moving in unanticipated directions,
which could result in declining or even negative gross margins. Accordingly,
our
business is subject to fluctuations in the price of ethanol and these
fluctuations may result in lower or even negative gross margins and which could
materially and adversely affect our profitability.
We
depend on a small number of customers for the majority of our sales. A reduction
in business from any of these customers could cause a significant decline in
our
overall sales and profitability.
The
majority of our sales are generated from a small number of customers. During
2006, sales to our two largest customers, each of whom accounted for 10% or
more
of total net sales, represented an aggregate of approximately 25%, of our total
net sales. During 2005, sales to our three largest customers, each of whom
accounted for 10% or more of total net sales, represented an aggregate of
approximately 39%, of our total net sales. We expect that we will continue
to
depend for the foreseeable future upon a small number of customers for a
significant portion of our sales. Our agreements with these customers generally
do not require them to purchase any specified amount of ethanol or dollar amount
of sales or to make any purchases whatsoever. Therefore, in any future period,
our sales generated from these customers, individually or in the aggregate,
may
not equal or exceed historical levels. If sales to any of these customers cease
or decline, we may be unable to replace these sales with sales to either
existing or new customers in a timely manner, or at all. A cessation or
reduction of sales to one or more of these customers could cause a significant
decline in our overall sales and profitability.
Our
lack of long-term ethanol orders and commitments by our customers could lead
to
a rapid decline in our sales and profitability.
We
cannot
rely on long-term ethanol orders or commitments by our customers for protection
from the negative financial effects of a decline in the demand for ethanol
or a
decline in the demand for our marketing services. The limited certainty of
ethanol orders can make it difficult for us to forecast our sales and allocate
our resources in a manner consistent with our actual sales. Moreover, our
expense levels are based in part on our expectations of future sales and, if
our
expectations regarding future sales are inaccurate, we may be unable to reduce
costs in a timely manner to adjust for sales shortfalls. Furthermore, because
we
depend on a small number of customers for a significant portion of our sales,
the magnitude of the ramifications of these risks is greater than if our sales
were less concentrated. As a result of our lack of long-term ethanol orders
and
commitments, we may experience a rapid decline in our sales and
profitability.
We
depend on a small number of suppliers for the majority of the ethanol that
we
sell. If any of these suppliers is unable or decides not to continue to supply
us with ethanol in adequate amounts, we may be unable to satisfy the demands
of
our customers and our sales, profitability
and relationships with our customers will be adversely
affected.
We
depend
on a small number of suppliers for the majority of the ethanol that we sell.
During 2006, our four largest suppliers, each of whom accounted for 10% or
more
of total purchases, represented approximately 64% of the total ethanol we
purchased for resale. During 2005, our three largest suppliers, each of whom
accounted for 10% or more of total purchases, represented approximately 59%
of
the total ethanol we purchased for resale. We expect to continue to depend
for
the foreseeable future upon a small number of suppliers for a significant
majority of the ethanol that we purchase. In addition, we source the ethanol
that we sell primarily from suppliers in the Midwestern United States. The
delivery of the ethanol that we sell is therefore subject to delays resulting
from inclement weather and other conditions. If any of these suppliers is unable
or declines for any reason to continue to supply us with ethanol in adequate
amounts, we may be unable to replace that supplier and source other supplies
of
ethanol in a timely manner, or at all, to satisfy the demands of its customers.
If this occurs, our sales and profitability and our relationships with our
customers will be adversely affected.
We
may be adversely affected by environmental, health and safety laws, regulations
and liabilities.
We
are
subject to various federal, state and local environmental laws and regulations,
including those relating to the discharge of materials into the air, water
and
ground, the generation, storage, handling, use, transportation and disposal
of
hazardous materials, and the health and safety of our employees. In addition,
some of these laws and regulations require our facilities to operate under
permits that are subject to renewal or modification. These laws, regulations
and
permits can often require expensive pollution control equipment or operational
changes to limit actual or potential impacts to the environment. A violation
of
these laws and regulations or permit conditions can result in substantial fines,
natural resource damages, criminal sanctions, permit revocations and/or facility
shutdowns. In addition, we have made, and expect to make, significant capital
expenditures on an ongoing basis to comply with increasingly stringent
environmental laws, regulations and permits.
We
may be
liable for the investigation and cleanup of environmental contamination at
each
of the properties that we own or operate and at off-site locations where we
arrange for the disposal of hazardous substances. If these substances have
been
or are disposed of or released at sites that undergo investigation and/or
remediation by regulatory agencies, we may be responsible under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980,
or
other environmental laws for all or part of the costs of investigation and/or
remediation, and for damages to natural resources. We may also be subject to
related claims by private parties alleging property damage and personal injury
due to exposure to hazardous or other materials at or from those properties.
Some of these matters may require us to expend significant amounts for
investigation, cleanup or other costs.
In
addition, new laws, new interpretations of existing laws, increased governmental
enforcement of environmental laws or other developments could require us to
make
additional significant expenditures. Continued government and public emphasis
on
environmental issues can be expected to result in increased future investments
for environmental controls at our production facilities. Present and future
environmental laws and regulations (and interpretations thereof) applicable
to
our operations, more vigorous enforcement policies and discovery of currently
unknown conditions may require substantial expenditures that could have a
material adverse effect on our results of operations and financial position.
The
hazards and risks associated with producing and transporting our products (such
as fires, natural disasters, explosions, and abnormal pressures and blowouts)
may also result in personal injury claims or damage to property and third
parties. As protection against operating hazards, we maintain insurance coverage
against some, but not all, potential losses. However, we could sustain losses
for uninsurable or uninsured risks, or in amounts in excess of existing
insurance coverage. Events that result in significant personal injury or damage
to our property or third parties or other losses that are not fully covered
by
insurance could have a material adverse effect on our results of operations
and
financial position.
The
ethanol production and marketing industry is extremely competitive. Many of
our
significant competitors have greater production and financial resources than
we
do and one or more of these competitors could use their greater resources to
gain market share at our expense. In addition, certain of our suppliers may
circumvent our marketing services, causing our sales and profitability to
decline.
The
ethanol production and marketing industry is extremely competitive. Many of
our
significant competitors in the ethanol production and marketing industry, such
as ADM, Cargill, Inc., VeraSun Energy Corporation, Aventine Renewable Energy,
Inc., and Abengoa Bioenergy Corp., have substantially greater production and
financial resources than we do. As a result, our competitors may be able to
compete more aggressively and sustain that competition over a longer period
of
time than we could. Successful competition will require a continued high level
of investment in marketing and customer service and support. Our lack of
resources relative to many of our significant competitors may cause us to fail
to anticipate or respond adequately to new developments and other competitive
pressures. This failure could reduce our competitiveness and cause a decline
in
our market share, sales and profitability. Even if sufficient funds are
available, we may not be able to make the modifications and improvements
necessary to successfully compete.
In
addition, some of our suppliers are potential competitors and, especially if
the
price of ethanol remains at historically high levels, they may seek to capture
additional profits by circumventing our marketing services in favor of selling
directly to our customers. If one or more of our major suppliers, or numerous
smaller suppliers, circumvent our marketing services, our sales and
profitability will decline.
We
also
face increasing competition from international suppliers. Although there is
a
$0.54 per gallon tariff, which is scheduled to expire in December 2007, on
foreign-produced ethanol that is approximately equal to the blenders’ credit,
ethanol imports equivalent to up to 7% of total domestic production in any
given
year from various countries were exempted from this tariff under the Caribbean
Basin Initiative to spur economic development in Central America and the
Caribbean. Currently, international suppliers produce ethanol primarily from
sugar cane and have cost structures that are generally substantially lower
than
ours.
Any
increase in domestic or foreign competition could cause us to reduce our prices
and take other steps to compete effectively, which could adversely affect our
results of operations and financial position.
We
engage in hedging transactions and other risk mitigation strategies that could
harm our results.
In
an
attempt to partially offset the effects of volatility of ethanol prices and
corn
and natural gas costs, we often enter into contracts to supply a portion of
our
ethanol production or purchase a portion of our corn or natural gas requirements
on a forward basis and also engage in other hedging transactions involving
exchange-traded futures contracts for corn, natural gas and unleaded gasoline
from time to time. The financial statement impact of these activities is
dependent upon, among other things, the prices involved and our ability to
sell
sufficient products to use all of the corn and natural gas for which we have
futures contracts. Hedging arrangements also expose us to the risk of financial
loss in situations where the other party to the hedging contract defaults on
its
contract or, in the case of exchange-traded contracts, where there is a change
in the expected differential between the underlying price in the hedging
agreement and the actual prices paid or received by us. Hedging activities
can
themselves result in losses when a position is purchased in a declining market
or a position is sold in a rising market. A hedge position is often settled
in
the same time frame as the physical commodity is either purchased or sold.
Hedging losses may be offset by a decreased cash price for corn and natural
gas
and an increased cash price for ethanol. We also vary the amount of hedging
or
other risk mitigation strategies we undertake, and we may choose not to engage
in hedging transactions at all. As a result, our results of operations and
financial position may be adversely affected by increases in the price of corn
or natural gas or decreases in the price of ethanol or unleaded
gasoline.
We
are a minority member of Front Range with limited control over that entity’s
business decisions. We are therefore dependent upon the business judgment and
conduct of the manager and majority member of that entity. As a result, our
interests may not be as well served as if we were in control of Front Range,
which could adversely affect its contribution to our results of operations
and
our business prospects related to that entity.
Front
Range operates an ethanol production facility located in Windsor, Colorado.
We
own approximately 42% of Front Range, which represents a minority interest
in
that entity. The manager and majority member of Front Range owns approximately
54% of that entity and has control of that entity’s business decisions,
including those related to day-to-day operations. The manager and majority
member of Front Range has the right to set the manager’s compensation, determine
cash distributions, decide whether or not to expand the ethanol production
facility and make most other business decisions on behalf of that entity. We
are
therefore largely dependent upon the business judgment and conduct of the
manager and majority member of Front Range. As a result, our interests may
not
be as well served as if we were in control of Front Range. Accordingly, the
contribution by Front Range to our results of operations and our business
prospectus related to that entity may be adversely affected by our lack of
control over that entity.
Risks
Related to our Common Stock
Our
common stock has a small public float and shares of our common stock eligible
for public sale could cause the market price of our stock to drop, even if
our
business is doing well, and make it difficult for us to raise additional capital
through sales of equity securities.
As
of
March 7, 2007, we had outstanding approximately 40.3 million shares of our
common stock. Approximately 10.1 million of these shares were restricted under
the Securities Act of 1933, or Securities Act, including approximately 5.4
million shares owned, in the aggregate, by our executive officers, directors
and
10% stockholders. Accordingly, our common stock has a relatively small public
float of approximately 30.2 million shares.
We
have
registered for resale a substantial number of shares of our common stock,
including shares of our common stock underlying warrants. The holders of these
shares are permitted, subject to few limitations, to freely sell these shares
of
common stock. As a result of our relatively small public float, sales of
substantial amounts of common stock, including shares issued upon the exercise
of stock options or warrants, or an anticipation that such sales could occur,
may materially and adversely affect prevailing market prices for our common
stock. In addition, any adverse effect on the market price of our common stock
could make it difficult for us to raise additional capital through sales of
equity securities at a time and at a price that we deem
appropriate.
As
a result of our issuance of shares of Series A Preferred Stock to Cascade
Investment, L.L.C., our
common stockholders may experience numerous negative effects and most of the
rights of our common stockholders will be subordinate to the rights of Cascade
Investment, L.L.C.
As
a
result of our issuance of shares of Series A Preferred Stock to Cascade
Investment, L.L.C., or Cascade, common stockholders may experience numerous
negative effects, including substantial dilution. The 5,250,000 shares of Series
A Preferred Stock issued to Cascade are immediately convertible into 10,500,000
shares of our common stock, which amount, when issued, would, based upon the
number of shares of our common stock outstanding as of March 7, 2007, represent
approximately 21% of our shares outstanding and, in the event that we are
profitable, would likewise result in a decrease in our diluted earnings per
share by approximately 21%, without taking into account cash or stock payable
as
dividends on the Series A Preferred Stock.
Other
negative effects to our common stockholders may include additional dilution
from
dividends paid in Series A Preferred Stock and certain antidilution adjustments.
In addition, rights in favor of holders of our Series A Preferred Stock include:
seniority in liquidation and dividend preferences; substantial voting rights;
numerous protective provisions; the right to appoint two persons to our board
of
directors and periodically nominate two persons for election by our stockholders
to our board of directors; preemptive rights; and redemption rights. Also,
the
Series A Preferred Stock could have the effect of delaying, deferring and
discouraging another party from acquiring control of Pacific Ethanol. In
addition, based on our current number of shares of common stock outstanding,
Cascade has approximately 21% of all outstanding voting power as compared to
approximately 11% of all outstanding voting power held in aggregate by our
current executive officers and directors. Any of the above factors may
materially and adversely affect our common stockholders and the values of their
investments in our common stock.
Our
stock price is highly volatile, which could result in substantial losses for
investors purchasing shares of our common stock and in litigation against
us.
The
market price of our common stock has fluctuated significantly in the past and
may continue to fluctuate significantly in the future. The market price of
our
common stock may continue to fluctuate in response to one or more of the
following factors, many of which are beyond our control:
| |
·
|
changing
conditions in the ethanol and fuel markets as well as other commodity
markets such as corn;
|
| |
·
|
the
volume and timing of the receipt of orders for ethanol from major
customers;
|
| |
·
|
competitive
pricing pressures;
|
| |
·
|
our
ability to produce, sell and deliver ethanol on a cost-effective
and
timely basis;
|
| |
·
|
the
introduction and announcement of one or more new alternatives to
ethanol
by our competitors;
|
| |
·
|
changes
in market valuations of similar companies;
|
| |
·
|
stock
market price and volume fluctuations generally;
|
| |
·
|
regulatory
developments or increased enforcement;
|
| |
·
|
fluctuations
in our quarterly or annual operating results;
|
| |
·
|
additions
or departures of key personnel;
|
| |
·
|
our
inability to obtain construction, acquisition, capital equipment
and/or
working capital financing; and
|
| |
·
|
future
sales of our common stock or other
securities.
|
Furthermore,
we believe that the economic conditions in California and other Western states,
as well as the United States as a whole, could have a negative impact on our
results of operations. Demand for ethanol could also be adversely affected
by a
slow-down in overall demand for oxygenate and gasoline additive products. The
levels of our ethanol production and purchases for resale will be based upon
forecasted demand. Accordingly, any inaccuracy in forecasting anticipated
revenues and expenses could adversely affect our business. The failure to
receive anticipated orders or to complete delivery in any quarterly period
could
adversely affect our results of operations for that period. Quarterly results
are not necessarily indicative of future performance for any particular period,
and we may not experience revenue growth or profitability on a quarterly or
an
annual basis.
The
price
at which you purchase shares of our common stock may not be indicative of the
price that will prevail in the trading market. You may be unable to sell your
shares of common stock at or above your purchase price, which may result in
substantial losses to you and which may include the complete loss of your
investment. In the past, securities class action litigation has often been
brought against a company following periods of stock price volatility. We may
be
the target of similar litigation in the future. Securities litigation could
result in substantial costs and divert management’s attention and our resources
away from our business. Any of the risks described above could adversely affect
our sales and profitability and also the price of our common stock.
Item
1B. Unresolved
Staff Comments.
None.
Our
corporate headquarters, located in Sacramento, California, consists of a 7,000
square foot office leased for approximately 40 months. We also rent, under
a
four-year lease, an office in Fresno, California, consisting of 3,000 square
feet and an office in Davis, California, consisting of 500 square feet. In
addition, we rent, under a three-year lease, an office in Portland, Oregon,
consisting of 860 square feet. We also rent under a six-month lease, with an
option for an additional six month extension, an office in Fresno, California,
consisting of 800 square feet.
Our
completed ethanol production facilities are located in Madera, California,
at
which a 137 acre facility is located, and Windsor, Colorado, at which a 40
acre
facility is located. We are a minority owner of the entity that owns the
Windsor, Colorado facility. We are constructing an ethanol production facility
in Boardman, Oregon, on a 25 acre plot. We have acquired sites or options with
respect to sites for four other potential ethanol production facilities that
we
may develop, or which are currently under development or construction, including
sites at Brawley, California; and another plant in California, the location
of
which is yet to be announced; and Burley, Idaho. See “Business—Production
Facilities” above.
We
are
subject to legal proceedings, claims and litigation arising in the ordinary
course of business. While the amounts claimed may be substantial, the ultimate
liability cannot presently be determined because of considerable uncertainties
that exist. Therefore, it is possible that the outcome of those legal
proceedings, claims and litigation could adversely affect our quarterly or
annual operating results or cash flows when resolved in a future period.
However, based on facts currently available, management believes such matters
will not adversely affect our financial position, results of operations or
cash
flows.
Barry
Spiegel - State Court Action
On
December 23, 2005, Barry J. Spiegel, a former shareholder and director of
Accessity, filed a complaint in the Circuit Court of the 17th Judicial District
in and for Broward County, Florida (Case No. 05018512), or State Court Action,
against Barry Siegel, Philip Kart, Kenneth Friedman and Bruce Udell, or
collectively, the Individual Defendants. Messrs. Siegel, Udell and Friedman
are
former directors of Accessity and Pacific Ethanol. Mr. Kart is a former
executive officer of Accessity and Pacific Ethanol.
The
State
Court Action relates to the Share Exchange Transaction and purports to state
the
following five counts against the Individual Defendants: (i) breach of fiduciary
duty, (ii) violation of the Florida Deceptive and Unfair Trade Practices Act,
(iii) conspiracy to defraud, (iv) fraud and (v) violation of Florida’s
Securities and Investor Protection Act. Mr. Spiegel bases his claims on
allegations that the actions of the Individual Defendants in approving the
Share
Exchange Transaction caused the value of his Accessity common stock to diminish
and is seeking $22.0 million in damages. On March 8, 2006, the Individual
Defendants filed a motion to dismiss the State Court Action. Mr. Spiegel filed
his response in opposition on May 30, 2006. The Court granted the motion to
dismiss by Order dated December 1, 2006 (the “Order”), on the grounds that Mr.
Spiegel failed to bring his claims as a derivative action. Mr. Spiegel is
seeking appellate review of the Order.
On
February 9, 2007, Mr. Spiegel filed an amended complaint which purports to
state
the following five counts: (i) breach of fiduciary duty, (ii) fraudulent
inducement, (iii) violation of Florida’s Securities and Investor Protection Act,
(iv) fraudulent concealment and (v) breach of fiduciary duty of disclosure.
The
amended complaint includes Pacific Ethanol as a defendant. The breach of
fiduciary duty counts are alleged solely against the Individual Defendants
and
not Pacific Ethanol. We expect to vigorously defend the amended
complaint.-
Barry
Spiegel - Federal Court Action
On
December 22, 2006, Barry J. Spiegel, filed a complaint in the United States
District Court, Southern District of Florida (Case No. 06-61848), or Federal
Court Action, against the Individual Defendants and Pacific Ethanol. The Federal
Court Action relates to the Share Exchange Transaction and purports to state
the
following three counts: (i) violations of Section 14(a) of the Exchange Act
and
SEC Rule 14a-9, (ii) violations of Section 10(b) of the Exchange Act and Rule
10b-5 promulgated thereunder, and (iii) violation of Section 20(A) of the
Exchange Act. The first two counts are alleged against the Individual Defendants
and Pacific Ethanol and the third count is alleged solely against the Individual
Defendants. Mr. Spiegel bases his claims on, among other things,
allegations that the actions of the Individual Defendants and Pacific Ethanol
in
connection with the Share Exchange Transaction resulted in a share exchange
ratio that was unfair and resulted in the preparation of a proxy statement
seeking shareholder approval of the Share Exchange Transaction that contained
material misrepresentations and omissions. Mr. Spiegel is seeking in excess
of
$15.0 million in damages. Mr. Spiegel amended the Federal Court Action on
February 9, 2007 and March 5, 2007 and only recently served the complaint on
Pacific Ethanol. We expect to vigorously defend the Federal Court
Action.
Mercator
Group, LLC
We
filed
a Demand for Arbitration against Presidion Solutions, Inc., or Presidion,
alleging that Presidion breached the terms of the Memorandum of Understanding,
or the MOU, between Accessity and Presidion dated January 17, 2003. We sought
a
break-up fee of $250,000 pursuant to the terms of the MOU alleging that
Presidion breached the MOU by wrongfully terminating the MOU. Additionally,
we
sought out of pocket costs of its due diligence amounting to approximately
$37,000. Presidion filed a counterclaim against us alleging that we had breached
the MOU and therefore owe Presidion a break-up fee of $250,000. The dispute
was
heard by a single arbitrator before the American Arbitration Association in
Broward County, Florida in late February 2004. During June 2004, the arbitrator
awarded us the $250,000 break-up fee set forth in the MOU between us and
Presidion, as well as our share of the costs of the arbitration and interest
from the date of the termination by Presidion of the MOU, aggregating
approximately $280,000. During the third quarter of 2004, Presidion paid us
the
full amount of the award with accrued interest. The arbitrator dismissed
Presidion’s counterclaim against us.
In
2003,
we filed a lawsuit seeking damages in excess of $100 million as a result of
information obtained during the course of the arbitration discussed above,
against: (i) Presidion Corporation, f/k/a MediaBus Networks, Inc., Presidion’s
parent corporation, (ii) Presidion’s investment bankers, Mercator Group, LLC, or
Mercator, and various related and affiliated parties and (iii) Taurus Global
LLC, or Taurus, (collectively referred to as the “Mercator Action”), alleging
that these parties committed a number of wrongful acts, including, but not
limited to tortiously interfering in the transaction between us and Presidion.
In 2004, we dismissed this lawsuit without prejudice, which was filed in Florida
state court. In January 2005, we refiled this action in the State of California,
for a similar amount, as we believe this to be the proper jurisdiction. On
August 18, 2005, the court stayed the action and ordered the parties to
arbitration. The parties agreed to mediate the matter. Mediation took place
on
December 9, 2005 and was not successful. On December 5, 2005, we filed a Demand
for Arbitration with the American Arbitration Association. On April 6, 2006,
a
single arbitrator was appointed. Arbitration hearings have been scheduled to
commence in July 2007.
The
final
outcome of the Mercator Action will most likely take an indefinite time to
resolve. We currently have limited information regarding the financial condition
of the defendants and the extent of their insurance coverage. Therefore, it
is
possible that we may prevail, but may not be able to collect any judgment.
The
share exchange agreement relating to the Share Exchange Transaction provides
that following full and final settlement or other final resolution of the
Mercator Action, after deduction of all fees and expenses incurred by the law
firm representing us in this action and payment of the 25% contingency fee
to
the law firm, shareholders of record of Accessity on the date immediately
preceding the closing date of the Share Exchange Transaction will receive
two-thirds and we will retain the remaining one-third of the net proceeds from
any Mercator Action recovery.
Item
4. Submission
of Matters to a Vote of Security Holders.
None.
Market
Information
Our
common stock has been traded on the Nasdaq Global Market (formerly, the Nasdaq
National Market) under the symbol “PEIX” since October 10, 2005. Prior to
October 10, 2005 and since March 24, 2005, our common stock traded on the Nasdaq
Capital Market (formerly, the Nasdaq SmallCap Market) under the symbol “PEIX.”
Prior to March 24, 2005, our common stock traded on the Nasdaq SmallCap Market
under the symbol “ACTY.” The table below shows, for each fiscal quarter
indicated, the high and low closing prices for shares of our common stock.
This
information has been obtained from The Nasdaq Stock Market. The prices shown
reflect inter-dealer prices, without retail mark-up, mark-down or commission,
and may not necessarily represent actual transactions.
| |
Price
Range
|
| |
High
|
Low
|
|
Year
Ended December 31, 2005:
|
|
|
|
First
Quarter (January 1 - March 31)
|
$10.25
|
$5.49
|
|
Second
Quarter (April 1 - June 30)
|
12.94
|
8.58
|
|
Third
Quarter (July 1 - September 30)
|
11.20
|
7.78
|
|
Fourth
Quarter (October 1 - December 31)
|
13.48
|
7.71
|
| |
|
|
|
Year
Ended December 31, 2006:
|
|
|
|
First
Quarter
|
$22.34
|
$9.99
|
|
Second
Quarter
|
42.39
|
20.14
|
|
Third
Quarter
|
25.45
|
13.76
|
|
Fourth
Quarter
|
19.08
|
12.58
|
Security
Holders
As
of
March 7, 2007, we had 40,285,227 shares of common stock outstanding and held
of
record by approximately 500 stockholders. These holders of record include
depositories that hold shares of stock for brokerage firms which, in turn,
hold
shares of stock for numerous beneficial owners. On March 7, 2007, the closing
sale price of our common stock on the Nasdaq Global Market was $15.28 per
share.
Performance
Graph
The
graph
below shows a comparison of the cumulative total stockholder return on our
common stock with the cumulative total return on The NASDAQ Stock Market (U.S.)
Index and of public companies filing reports with the Securities and Exchange
Commission under Standard Industrial Classification Code 2860—Industrial Organic
Chemicals, or Peer Group, in each case over the five year period ended December
31, 2006.
The
graph
includes the date of March 23, 2005, the date of the Share Exchange Transaction
and the date on which we effectively began operating in a business properly
categorized under Standard Industrial Classification Code 2860—Industrial
Organic Chemicals. Our predecessor, Accessity, was in an unrelated business
prior to March 23, 2005. See “Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Share Exchange Transaction.”
The
graph
assumes $100 invested at the indicated starting date in our common stock and
in
each of The NASDAQ Stock Market (U.S.) Index and the Peer Group, with the
reinvestment of all dividends. We have not paid or declared any cash dividends
on our common stock and do not anticipate paying any cash dividends in the
foreseeable future. Stockholder returns over the indicated periods should not
be
considered indicative of future stock prices or stockholder returns. This graph
assumes that the value of the investment in our common stock and each of the
comparison groups was $100 on December 31, 2001.
| |
Cumulative
Total Return ($)
|
| |
12/01
|
12/02
|
12/03
|
12/04
|
3/23/05
|
12/05
|
12/06
|
|
PACIFIC
ETHANOL, INC.
|
100.00
|
24.60
|
37.30
|
94.13
|
143.65
|
171.75
|
244.29
|
|
THE
NASDAQ STOCK MARKET (U.S.) INDEX
|
100.00
|
69.66
|
99.71
|
113.79
|
106.87
|
114.47
|
124.20
|
|
SIC
2860—INDUSTRIAL ORGANIC CHEMICALS
|
100.00
|
84.41
|
105.89
|
156.97
|
154.98
|
130.92
|
166.23
|
Dividend
Policy
We
have
never paid cash dividends on our common stock and do not currently intend to
pay
cash dividends on our common stock in the foreseeable future. We currently
anticipate that we will retain any earnings for use in the continued development
of our business.
Our
current and future debt financing arrangements may limit or prevent cash
distributions from our subsidiaries to us, depending upon the achievement of
certain financial and other operating conditions and our ability to properly
service the debt, thereby limiting or preventing us from paying cash dividends.
In addition, the holders of our preferred stock are entitled to dividends of
5%,
and those dividends must be paid prior to the payment of any dividends to our
common stockholders.
Recent
Sales of Unregistered Securities
From
October through December 2006, we issued an aggregate of 28,750 shares of our
common stock upon the exercise of outstanding warrants. In connection with
the
warrant exercises we received aggregate gross proceeds of $2.87.
On
October 17, 2006, we issued 2,081,888 shares of our common stock and a warrant
to purchase 693,963 shares of our common stock as partial consideration for
our
acquisition of 42% of the membership interests of Front Range.
Exemption
from the registration provisions of the Securities Act for the transactions
described above is claimed under Section 4(2) of the Securities Act, among
others, on the basis that such transactions did not involve any public offering
and the purchasers were accredited or sophisticated with access to the kind
of
information registration would provide. In each case, appropriate investment
representations were obtained, stock certificates were issued with restricted
stock legends, and/or stop transfer orders were placed with our transfer
agent.
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers
On
October 4, 2006, we granted to certain employees and directors shares of
restricted stock under our 2006 Stock Incentive Plan pursuant to Restricted
Stock Agreements dated and effective as of October 4, 2006 by and between us
and
those employees and directors. We granted an aggregate of 945,560 shares of
restricted stock to the employees and directors, with an aggregate of 280,720
shares of restricted stock vesting immediately and an aggregate of 148,568
shares of restricted stock vesting on each of the next two anniversaries of
the
grant date starting on October 4, 2007 and an aggregate of 122,568 shares of
restricted stock vesting on each of the subsequent three anniversaries of the
grant date starting on October 4, 2009. Future vesting is subject to various
restrictions.
We
were
obligated to withhold minimum withholding tax amounts with respect to vested
shares of restricted stock and upon future vesting of shares of restricted
stock
granted to our employees. Each employee was entitled to pay the minimum
withholding tax amounts to us in cash or to elect to have us withhold a vested
amount of shares of restricted stock having a value equivalent to our minimum
withholding tax requirements, thereby reducing the number of shares of vested
restricted stock that the employee ultimately receives. If an employee failed
to
timely make such election, we automatically withheld the necessary shares of
vested restricted stock.
In
connection with satisfying our withholding requirements, we withheld an
aggregate of 42,157 shares of our common stock and remitted a cash payment
to
cover the minimum withholding tax amounts, thereby effectively repurchasing
from
the employees the 42,157 shares of common stock at a deemed purchase price
equal
to $13.06 per share for an aggregate purchase price of
$551,000.
The
following financial information should be read in conjunction with the
consolidated audited financial statements and the notes to those statements
beginning on page F-1 of this report, and the section entitled “Management’s
Discussion and Analysis of Financial Condition and Results of Operations”
included elsewhere in this report. The consolidated statements of operations
data for the years ended December 31, 2006, 2005 and 2004 and the consolidated
balance sheet data at December 31, 2006 and 2005 are derived from, and are
qualified in their entirety by reference to, the consolidated audited financial
statements beginning on page F-1 of this report. The consolidated statements
of
operations data from January 30, 2003 (inception) to December 31, 2003 and
the
consolidated balance sheet data at December 31, 2003 are derived from, and
qualified in their entirety by reference to, the consolidated audited financial
statements of Pacific Ethanol. The historical results that appear below are
not
necessarily indicative of results to be expected for any future periods.
| |
|
Year
Ended December 31,
|
|
| |
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
| |
|
(in
thousands, except per share data)
|
|
|
Consolidated
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
Net
sales
|
|
$
|
226,356
|
|
$
|
87,599
|
|
$
|
20
|
|
$
|
1,017
|
|
|
Cost
of goods sold
|
|
|
201,527
|
|
|
84,444
|
|
|
13
|
|
|
946
|
|
|
Gross
profit
|
|
|
24,829
|
|
|
3,155
|
|
|
7
|
|
|
71
|
|
|
Selling,
general and administrative expenses
|
|
|
24,641
|
|
|
12,638
|
|
|
2,277
|
|
|
648
|
|
|
Income
(loss) from operations
|
|
|
188
|
|
|
(9,483
|
)
|
|
(2,270
|
)
|
|
(577
|
)
|
|
Other
income (expense), net
|
|
|
3,426
|
|
|
(440
|
)
|
|
(532
|
)
|
|
(282
|
)
|
|
Non-controlling
interest in variable interest entity
|
|
|
(3,756
|
)
|
|
|
|
|
|
|
|
|
|
|
Loss
from operations before income taxes
|
|
|
(142
|
)
|
|
(9,923
|
)
|
|
(2,802
|
)
|
|
(859
|
)
|
|
Provision
for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(142
|
)
|
$
|
(9,923
|
)
|
$
|
(2,802
|
)
|
$
|
(859
|
)
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock dividends
|
|
$
|
(2,998
|
)
|
$
|
|
|
$
|
|
|
$
|
|
|
|
Deemed
dividend on preferred stock
|
|
|
(84,000
|
)
|
|
|
|
|
|
|
|
|
|
|
Loss
available to common stockholders
|
|
$
|
(87,140
|
)
|
$
|
(9,923
|
)
|
$
|
(2,802
|
)
|
$
|
(859
|
)
|
|
Loss
per common share, basic and diluted
|
|
$
|
(2.50
|
)
|
$
|
(0.40
|
)
|
$
|
(0.23
|
)
|
$
|
(0.07
|
)
|
|
Weighted-average
shares outstanding, basic and diluted
|
|
|
34,855
|
|
|
25,066
|
|
|
12,397
|
|
|
11,733
|
|
|
Consolidated
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
44,053
|
|
$
|
4,521
|
|
$
|
|
|
$
|
249
|
|
|
Working
capital (deficit)
|
|
|
96,451
|
|
|
(2,894
|
)
|
|
(1,025
|
)
|
|
(358
|
)
|
|
Total
assets
|
|
|
453,820
|
|
|
48,185
|
|
|
7,179
|
|
|
6,560
|
|
|
Long-term
debt
|
|
|
28,970
|
|
|
1,995
|
|
|
4,013
|
|
|
|
|
|
Stockholders’
equity
|
|
|
298,445
|
|
|
28,516
|
|
|
1,356
|
|
|
1,368
|
|
No
cash dividends on our common stock were declared during any of the periods
presented above.
Various
factors materially affect the comparability of the information presented in
the
above table. These factors relate primarily to a Share Exchange Transaction
that
was consummated on March 23, 2005 with the shareholders of PEI California,
and the holders of the membership interests of each of Kinergy and ReEnergy,
pursuant to which we acquired all of the issued and outstanding capital stock
of
PEI California and all of the outstanding membership interests of Kinergy and
ReEnergy. In addition, we acquired a minority interest in Front Range on October
17, 2006 and will treat Front Range as a consolidated subsidiary for financial
reporting purposes, in accordance with Financial Accounting Standards Board’s
(“FASB”) Financial Interpretation No. (“FIN”) 46(R), Consolidation
of Variable Interest Entities,
as we
are considered the primary beneficiary.
Item
7. Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
The
following discussion and analysis should be read in conjunction with our
consolidated financial statements and notes to consolidated financial statements
included elsewhere in this report. This report and our consolidated financial
statements and notes to consolidated financial statements contain
forward-looking statements, which generally include the plans and objectives
of
management for future operations, including plans and objectives relating to
our
future economic performance and our current beliefs regarding revenues we might
generate and profits we might earn if we are successful in implementing our
business and growth strategies. The forward-looking statements and associated
risks may include, relate to or be qualified by other important factors,
including, without limitation:
| |
·
|
fluctuations
in the market price of ethanol and its co-products;
|
| |
·
|
the
projected growth or contraction in the ethanol and co-product market
in
which we operate;
|
| |
·
|
our
strategies for expanding, maintaining or contracting our presence
in these
markets;
|
| |
·
|
our
ability to successfully develop, finance, construct and operate our
planned ethanol production facilities;
|
| |
·
|
anticipated
trends in our financial condition and results of operations;
and
|
| |
·
|
our
ability to distinguish ourselves from our current and future competitors.
|
We
do not
undertake to update, revise or correct any forward-looking statements.
Any
of
the factors described above or in the “Risk Factors” section above could cause
our financial results, including our net income or loss or growth in net income
or loss to differ materially from prior results, which in turn could, among
other things, cause the price of our common stock to fluctuate
substantially.
Overview
Our
primary goal is to become the leading marketer and producer of renewable fuels
in the Western United States.
We
produce and sell ethanol and its co-products and provide transportation, storage
and delivery of ethanol through third-party service providers in the Western
United States, primarily in California, Nevada, Arizona, Washington, Oregon
and
Colorado. We have extensive customer relationships throughout the Western United
States and extensive supplier relationships throughout the Western and
Midwestern United States.
In
October 2006, we completed construction of an ethanol production facility with
nameplate annual production capacity of 35 million gallons located in Madera,
California, and began producing ethanol. In October 2006, we also acquired
approximately 42% of the outstanding membership interests of Front Range Energy,
LLC, or Front Range, which owns and operates an ethanol production facility
with
nameplate annual production capacity of 40 million gallons located in Windsor,
Colorado. In addition, we are currently constructing or in advanced stages
of
development of four additional ethanol production facilities. We also intend
to
construct or otherwise acquire additional ethanol production facilities as
financial resources and business prospects make the construction or acquisition
of these facilities advisable. See “Business—Production Facilities”
below.
Total
annual gasoline consumption in the United States is approximately 140 billion
gallons. Total annual ethanol consumption currently represents less than 4%
of
annual gasoline consumption, or approximately 5.1 billion gallons of ethanol.
We
believe that the domestic ethanol industry has substantial potential for growth
to reach what we estimate is an achievable level of at least 10% of the total
annual gasoline consumption in the United States, or approximately 14 billion
gallons of ethanol. In California alone, an increase in the consumption of
ethanol from California’s current level of 5.7%, or approximately 1.0 billion
gallons of ethanol per year, to at least 10% of total annual gasoline
consumption would result in consumption of approximately 700 million additional
gallons of ethanol, representing an increase in annual ethanol consumption
in
California alone of approximately 75% and an increase in annual ethanol
consumption in the entire United States of approximately 13%.
We
intend
to achieve our goal of becoming the leading marketer and producer of renewable
fuels in the Western United States in part by expanding our production capacity
to 220 million gallons of annual production capacity by the second quarter
of
2008 and 420 million gallons of annual production capacity by the end of 2010.
We intend to achieve this goal in part also by expanding our relationships
with
third-party ethanol producers to market higher volumes of ethanol throughout
the
Western United States, expanding our relationships with animal feed distributors
and end users to build local markets for wet distillers grains, or WDG, the
primary co-product of our ethanol production, and expanding the market for
ethanol by continuing to work with state governments to encourage the adoption
of policies and standards that promote ethanol as a fuel additive and ultimately
as a primary transportation fuel. We also intend to expand our distribution
infrastructure by expanding our ability to provide transportation, storage
and
related logistical services to our customers throughout the Western United
States.
Financial
Performance Summary
Our
net
sales increased by $138.8 million, or 158.4% to $226.4 million for the year
ended December 31, 2006 from $87.6 million for the year ended December 31,
2005.
Our net loss decreased by $9.8 million to $142,000 for 2006 from a net loss
of
$9.9 million for 2005.
The
following factors contributed to our operating results for 2006:
| |
·
|
Net
sales. Our
increase in net sales in 2006 as compared to 2005 was primarily due
to the
following combination of factors:
|
| |
o
|
Higher
sales volumes.
Total volume of ethanol sold as a principal and an agent increased
by 49.4
million gallons, or 94.5%, to 101.7 million gallons for 2006 from
52.3
million gallons for 2005. The substantial increase in sales volume
is
primarily due to additional supply provided under our ethanol marketing
agreements and the commencement of ethanol production.
|
| |
o
|
Commencement
of ethanol production.
In the fourth quarter of 2006, we commenced producing ethanol and
its
co-products at our Madera facility and, based on our ownership interest
in
Front Range, began recording a proportionate amount of its net sales.
The
production and sale of ethanol and its co-products at our Madera
facility
and through Front Range contributed an aggregate of $25.9 million
in sales
for 2006.
|
| |
o
|
Higher
ethanol prices.
Our average sales price of ethanol increased by $0.61 per gallon,
or
36.5%, to $2.28 per gallon for all gallons sold as a principal and
an
agent for 2006 as compared to $1.67 per gallon for 2005.
|
| |
o
|
Partial
period comparison.
Our results of operations for 2006, including our net sales, include
our
operations and those of all of our wholly-owned subsidiaries, including
Kinergy Marketing, LLC, or Kinergy, for that entire period. However,
our
results of operations for 2005, including our net sales, exclude
Kinergy’s
net sales for the period from January 1, 2005 through March 22, 2005
in
the amount of $23.6 million. See “Share Exchange Transaction”
below.
|
| |
·
|
Gross
profit. Our
gross profit margin increased to 10.9% for 2006 as compared to a
gross
profit margin of 3.6% for 2005. This increase was primarily due to
locking
in favorable margins through purchase and sale commitments consistent
with
our risk management guidelines at various times during 2006. The
increase
in our gross profit margins was also due to sales resulting from
ethanol
production, which typically generates higher gross profits than ethanol
marketing arrangements, at our Madera facility and also through Front
Range.
|
|
|
· |
Selling,
general and administrative expenses.
Our selling, general and administrative expenses increased by $12.0
million to $24.6 million in 2006 as compared to $12.6 million in
2005;
however, these expenses decreased as a percentage of our net sales
due to
our substantial growth in net sales. Our selling, general and
administrative expenses decreased to 10.9% of net sales in 2006 as
compared to 14.4% of net sales in 2005.
|
Sales
and Margins
Historically,
we have generated all of our revenues from marketing ethanol produced by third
parties. However, in the fourth quarter of 2006, we began generating revenues
from the production and sale of ethanol and its co-products as a result of
the
commencement of operations at our Madera facility and our interest in Front
Range.
We
have
three principal methods of selling ethanol: as a merchant, as a producer and
as
an agent. See “Critical Accounting Policies—Revenue Recognition” below.
When
acting as a merchant or as a producer, we generally enter into sales contracts
having a typical term of six months to ship ethanol to a customer’s desired
location. We support these sales contracts through purchase contracts with
several third-party suppliers or through our own production. We manage the
necessary logistics to deliver ethanol to our customers either directly from
a
third-party supplier or from our inventory via truck or rail. Our sales as
a
merchant or as a producer expose us to price risks resulting from potential
fluctuations in the market price of ethanol. Our exposure varies depending
on
the magnitude of our sales commitments compared to the magnitude of our purchase
commitments and existing inventory, as well as the pricing terms—such as market
index or fixed pricing—of our contracts. We seek to mitigate our exposure to
price risks by implementing appropriate risk management strategies.
When
acting as an agent for third-party suppliers, we conduct back-to-back purchases
and sales in which we match ethanol purchase and sale contracts of like
quantities and delivery periods. When acting as an agent for third-party
suppliers, we receive a predetermined service fee and we have little or no
exposure to price risks resulting from potential fluctuations in the market
price of ethanol.
Prior
to
2005, Kinergy’s gross profit margins for marketing ethanol produced by third
parties averaged between 2.0% and 4.4%. Gross profit margins above this
historical range generally result when we are able to correctly anticipate
and
benefit from holding a net long position (i.e., volume on purchase commitments,
together with existing inventory, exceeds volume on sales commitments) while
ethanol prices are rising, or holding a net short position (i.e., volume on
sales commitments exceeds volume on purchase commitments and existing inventory)
while ethanol prices are declining. Gross profit margins below this historical
range generally result when a net long or short position is held and there
is a
sustained adverse movement in market prices.
The
market price of ethanol has recently experienced significant fluctuations.
For
example, Kinergy’s average sales price per gallon of ethanol declined by
approximately 25% from its 2004 average sales price in the five months from
January 2005 through May 2005 and reversed this decline and increased to
approximately 55% above Kinergy’s 2004 average sales price in the four months
from June 2005 through September 2005; and from September through December
2005,
our average sales price per gallon of ethanol trended downward but reversed
its
trend by rising approximately 36% above our 2005 average sales price by the
end
of 2006. Fluctuations in the market price of ethanol may cause our results
of
operations to fluctuate significantly.
We
believe that our gross profit margins will primarily depend on four key factors:
| |
·
|
the
market price of ethanol, which we believe will be impacted by the
degree
of competition in the ethanol market, the price of gasoline and related
petroleum products, and government regulation, including tax incentives;
|
| |
·
|
the
market price of key production input commodities, including corn
and
natural gas;
|
| |
·
|
our
ability to anticipate trends in the market price of ethanol, WDG,
and key
input commodities and implement appropriate risk management and
opportunistic strategies; and
|
| |
·
|
the
proportion of our sales of ethanol produced at our facilities to
our sales
of ethanol produced by third-parties.
|
We
believe that our gross profit margins will also depend on the market price
of
WDG.
Management
seeks to optimize our gross profit margins by anticipating the factors above
and
implementing hedging transactions and taking other actions designed to limit
risk and address the various factors. For example, we may seek to decrease
inventory levels in anticipation of declining ethanol prices and increase
inventory levels in anticipation of increasing ethanol prices. We may also
seek
to alter our proportion or timing, or both, of purchase and sales commitments.
Our
inability to anticipate the factors above or their relative importance, and
adverse movements in the factors themselves, could result in declining or even
negative gross profit margins over certain periods of time. Our ability to
anticipate those factors or favorable movements in the factors themselves may
enable us to generate above-average gross profit margins. However, given the
difficulty associated with successfully forecasting any of these factors, we
are
unable to estimate our future gross profit margins.
Acquisition
of Front Range
On
October 17, 2006, we entered into a Membership Interest Purchase Agreement
with
Eagle Energy to acquire Eagle Energy’s 42% interest in Front Range. As
consideration for the acquisition of Eagle Energy’s interest in Front Range, we
paid to Eagle Energy cash of $30 million, issued 2,081,888 shares of common
stock valued at $30 million under the valuation provisions of the agreement
and
issued a warrant to purchase up to 693,963 shares of common stock at an exercise
price of $14.41 per share. The warrant had a fair value of $5.1 million. The
warrant expires October 17, 2007.
Share
Exchange Transaction
On
March
23, 2005, we completed a share exchange transaction, or Share Exchange
Transaction, with the shareholders of Pacific Ethanol, Inc., a California
corporation, or PEI California, and the holders of the membership interests
of
each of Kinergy, and ReEnergy, LLC, or ReEnergy. Upon completion of the Share
Exchange Transaction, we acquired all of the issued and outstanding shares
of
capital stock of PEI California and all of the outstanding membership interests
of each of Kinergy and ReEnergy. Immediately prior to the consummation of the
Share Exchange Transaction, our predecessor, Accessity Corp., a New York
corporation, or Accessity, reincorporated in the State of Delaware under the
name Pacific Ethanol, Inc.
Critical
Accounting Policies
Our
discussion and analysis of our financial condition and results of operations
are
based upon our consolidated financial statements, which have been prepared
in
accordance with accounting principles generally accepted in the United States
of
America. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date
of
the financial statements and the reported amount of net sales and expenses
for
each period. The following represents a summary of our critical accounting
policies, defined as those policies that we believe are the most important
to
the portrayal of our financial condition and results of operations and that
require management’s most difficult, subjective or complex judgments, often as a
result of the need to make estimates about the effects of matters that are
inherently uncertain.
Revenue
Recognition
We
recognize revenue when it is realized or realizable and earned. We consider
revenue realized or realizable and earned when it has persuasive evidence of
an
arrangement, delivery has occurred, the sales price is fixed or determinable,
and collection is reasonably assured in conformity with Staff Accounting
Bulletin No. 104, Revenue
Recognition.
We
derive
revenue primarily from sales of ethanol and related co-products. We recognize
revenue when title transfers to our customers, which is generally upon the
delivery of these products to a customer’s designated location. These deliveries
are made in accordance with sales commitments and related sales orders entered
into with customers either verbally or in written form. The sales commitments
and related sales orders provide quantities, pricing and conditions of sales.
In
this regard, we engage in three basic types of revenue generating
transactions:
| |
·
|
As
a merchant.
Sales as a merchant consist of sales to customers through purchases
from
third-party suppliers in which we may or may not obtain physical
control
of the ethanol or co-products, though ultimately titled to us, in
which
shipments are directed from our suppliers to our terminals or direct
to
our customers but for which we accept the risk of loss in the
transactions.
|
| |
·
|
As
a producer.
Sales as a producer consist of sales of our inventory produced at
our
facilities, including by Front
Range.
|
| |
·
|
As
an agent.
Sales as an agent consist of sales to customers through purchases
from
third-party suppliers in which, depending upon the terms of the
transactions, title to the product may technically pass to us, but
risk of
loss in the transactions does not since all transacted sales prices
flow
back to our third-party suppliers. When acting as an agent for third-party
suppliers, we conduct back-to-back purchases and sales in which we
match
ethanol purchase and sales contracts of like quantities and delivery
periods. We receive a predetermined service fee under these transactions
and therefore act predominantly in an agency
capacity.
|
We
have
employed the principles detailed in Emerging Issues Task Force (“EITF”) Issue
No. 99-19, Reporting
Revenue Gross as a Principal Versus Net as an Agent,
as
guidance in our revenue recognition policies. Revenue from sales of third-party
ethanol and its co-products is recorded net of costs when we are is acting
as an
agent between the customer and supplier and gross when we are a principal to
the
transaction. Several factors are considered to determine whether we are is
acting as an agent or principal, most notably whether we are the primary obligor
to the customer, whether we have inventory risk and related risk of loss or
whether we add meaningful value to the vendor’s product or service.
Consideration is also given to whether we have has latitude in establishing
the
sales price or have credit risk, or both.
We
record
revenues based upon the gross amounts billed to our customers in transactions
where we act as a producer or a merchant and obtain title to ethanol and its
co-products and therefore own the product and any related, unmitigated inventory
risk for the ethanol, regardless of whether we actually obtain physical control
of the product. When we act in an agency capacity, we record revenues on a
net
basis, or our predetermined agency fees only, based upon the amount of net
revenues retained in excess of amounts paid to suppliers.
Consolidation
of Variable Interest Entities.
We
have
determined that Front Range meets the definition of a variable interest entity
under the Financial Accounting Standards Board’s (“FASB”) Financial
Interpretation No. (“FIN”) 46(R), Consolidation
of Variable Interest Entities.
We are
therefore required to treat Front Range as a consolidated subsidiary for
financial reporting purposes rather than use equity investment accounting
treatment. We determined that we had become the primary beneficiary of the
variable interest entity as of October 17, 2006, the date we acquired our
ownership interest in Front Range. Under FIN 46(R), and as long as we are deemed
the primary beneficiary of Front Range, we must treat Front Range as a
consolidated subsidiary for financial reporting purposes. Therefore, we restated
the assets, liabilities, and the non-controlling interests of Front Range to
fair market values consistent with Statement of Financial Accounting Standards
(“SFAS”) No. 141, Business
Combinations,
and
SFAS No. 142, Goodwill
& Other Intangible Assets.
In
accordance with SFAS No. 141, we allocated the purchase price to the
tangible and intangible assets and liabilities acquired based upon their
estimated fair values. The excess purchase price over the fair value was
recorded as goodwill.
The
following summarizes our estimated fair values of the Front Range tangible
and
intangible assets and liabilities acquired (in thousands):
|
Cash
and cash equivalents
|
|
$
|
742
|
|
|
Investments
|
|
|
7,058
|
|
|
Accounts
receivable
|
|
|
3,520
|
|
|
Inventories
|
|
|
3,535
|
|
|
Other
current assets
|
|
|
235
|
|
|
Property
and equipment
|
|
|
92,376
|
|
|
Other
long-term assets
|
|
|
584
|
|
|
Intangibles
- customer backlog
|
|
|
3,900
|
|
|
Intangibles
- non-compete covenants
|
|
|
400
|
|
|
Goodwill
|
|
|
80,607
|
|
|
Current
portion of long-term debt
|
|
|
(3,395
|
)
|
|
Accounts
payable and accrued expenses
|
|
|
(4,591
|
)
|
|
Long-term
debt
|
|
|
(28,753
|
)
|
|
Non-controlling
interest in variable interest entity
|
|
|
(90,606
|
)
|
|
Net
Assets
|
|
$
|
65,612
|
|
Impairment
of Intangible and Long-Lived Assets
Our
intangible assets, including goodwill, were derived from the acquisition of
our
interest in Front Range in 2006 and our acquisition of Kinergy in 2005 in
connection with the Share Exchange Transaction. In accordance with SFAS No.
141,
we allocated the respective purchase prices to the tangible assets, liabilities
and intangible assets acquired based upon their estimated fair values. The
excess purchase prices over the fair values of the assets acquired and
liabilities assumed were recorded as goodwill.
Our
long-lived assets are primarily associated with our Madera and Front Range
ethanol production facilities. The long-lived assets attributable to Front
Range
were recorded as a result of the determination of our status as the primary
beneficiary of a variable interest entity and the resulting consolidated
accounting treatment.
We
account for goodwill and intangible assets in accordance with SFAS No. 142.
We
review goodwill and intangible assets at least annually, or more frequently
if
impairment indicators arise. In our review, we determine the fair value of
these
intangibles using market multiples and discounted cash flow modeling and compare
it to the net book value of the acquired assets. Any assessed impairments will
be recorded permanently and expensed in the period in which the impairment
is
determined. If it is determined through our assessment process that any of
our
intangible assets require impairment charges, they will be recorded in the
line
item other operating charges in the consolidated statement of operations. We
performed our annual review of impairment and we have not recognized any
impairment losses on any of our intangible assets through December 31,
2006.
We
evaluate impairment of long-lived assets in accordance with SFAS No. 144,
Accounting
for the Impairment or Disposal of Long-Lived Assets. We
assess the impairment of long-lived assets, including property and equipment
and
purchased intangibles subject to amortization, when events or changes in
circumstances indicate that suggest the fair value of assets could be less
then
their net book value. In such event, we assess long-lived assets for impairment
by determining their fair value based on the forecasted, undiscounted cash
flows
the assets are expected to generate plus the net proceeds expected from the
sale
of the asset. An impairment loss would be recognized when the fair value is
less
than the related asset’s net book value, and an impairment expense would be
recorded in the amount of the difference. Forecasts of future cash flows are
judgments based on our experience and knowledge of our operations and the
industries in which we operate. These forecasts could be significantly affected
by future changes in market conditions, the economic environment, and capital
spending decisions of our customers and inflation. We have not recognized any
impairment losses on long-lived assets through December 31, 2006.
Stock-Based
Compensation
Effective
January 1, 2006, we adopted the fair value method of accounting for employee
stock compensation
cost pursuant to SFAS
No. 123 (Revised 2004), Share-Based
Payments.
Prior to that date, we used the intrinsic value method under Accounting Policy
Board Opinion No. 25 to recognize compensation cost. Under the method of
accounting for the change to the fair value method, compensation
cost recognized in 2006 is the same amount that would have been recognized
if
the fair value method would have been used for all awards granted. The effects
on net income and earnings per share had the fair value method been applied
to
all outstanding and unvested awards in each period are reflected in Note 14
of the financial statements.
Our
assumptions made for purposes of estimating the fair value of our stock options,
as well as a summary of the activity under our stock option plan are included
in
Note 14 of the financial statements.
We
account for the stock options granted to non-employees in accordance with EITF
Issue No. 96-18, Accounting
for Equity Instruments That Are Issued to Other Than Employees for
Acquiring,
or
in Conjunction with Selling, Goods or Services,
and
SFAS No. 123R.
Derivative
Instruments and Hedging Activities
Our
business and activities expose us to a variety of market risks, including risks
related to changes in commodity prices and interest rates. We monitor and manage
these financial exposures as an integral part of our risk management program.
This program recognizes the unpredictability of financial markets and seeks
to
reduce the potentially adverse effects that market volatility could have on
operating results. We account for our use of derivatives related to our hedging
activities pursuant to SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities,
in
which we recognize all of our derivative instruments in our statement of
financial position as either assets or liabilities, depending on the rights
or
obligations under the contracts. We have designated and documented contracts
for
the physical delivery of commodity products to and from counterparties as normal
purchases and normal sales. Derivative instruments are measured at fair value,
pursuant to the definition found in SFAS No. 107, Disclosures
about Fair Value of Financial Instruments.
Changes
in the derivative’s fair value are recognized currently in earnings unless
specific hedge accounting criteria are met. Special accounting for qualifying
hedges allows a derivative’s effective gains and losses to be deferred in other
comprehensive income and later recorded together with the gains and losses
to
offset related results on the hedged item in the income statement. Companies
must formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
The
estimated gains/(losses) on our derivatives as of December 31, 2006 and 2005
are
as follows (in thousands):
| |
|
2006
|
|
2005
|
|
|
Commodity
futures
|
|
$
|
646
|
|
$
|
—
|
|
|
Commodity
options
|
|
|
(24
|
)
|
|
—
|
|
|
Interest
rate options
|
|
|
(17
|
)
|
|
—
|
|
|
Total
|
|
$
|
605
|
|
$
|
—
|
|
Allowance
for Doubtful Accounts
We
primarily sell ethanol to gasoline refining and distribution companies. We
also
sell WDG to dairy operators and animal feed distributors. We had significant
concentrations of credit risk as of December 31, 2006, as described in Note
2 of
our consolidated financial statements. However, those customers historically
have had good credit ratings and historically we have collected amounts that
were billed to those customers. Receivables from customers are generally
unsecured. We continuously monitor our customer account balances and actively
pursue collections on past due balances.
We
maintain an allowance for doubtful accounts for balances that appear to have
specific collection issues. Our collection process is based on the age of the
invoice and requires attempted contacts with the customer at specified
intervals. If after a specified number of days, we have been unsuccessful in
our
collection efforts, we consider recording a bad debt allowance for the balance
at question. We would eventually write-off accounts included in our allowance
when we have determined that collection is not likely. The factors considered
in
reaching this determination are the apparent financial condition of the
customer, and our success in contacting and negotiating with the
customer.
Costs
of Start-up Activities
Start-up
activities are defined broadly in Statement of Position 98-5, Reporting
on the Costs of Start-Up Activities,
as
those one-time activities related to opening a new facility, introducing a
new
product or service, conducting business in a new territory, conducting business
with a new class of customer or beneficiary, initiating a new process in an
existing facility, commencing some new operation or activities related to
organizing a new entity. Our start-up activities consist primarily of costs
associated with new or potential sites for ethanol production facilities. We
expense all the costs associated with a potential site, until the site is
consider viable by management, at which time costs would be considered for
capitalization based on authoritative accounting literature. These costs are
included in selling, general, and administrative expenses in our consolidated
statement of operations.
Results
of Operations
The
tables presented below, which compare our results of operations from one period
to another, present the results for each period, the change in those results
from one period to another in both dollars and percentage change, and the
results for each period as a percentage of net sales. The columns present the
following:
| |
·
|
The
first two data columns in the tables show the absolute results for
each
period presented.
|
| |
·
|
The
columns entitled “Dollar Variance” and “Percentage Variance” show the
change in results, both in dollars and percentages. These two columns
show
favorable changes as a positive and unfavorable changes as negative.
For
example, when our net sales increase from one period to the next,
that
change is shown as a positive number in both columns. Conversely,
when
expenses increase from one period to the next, that change is shown
as a
negative in both columns.
|
| |
·
|
The
last two columns in the tables show the results for each period as
a
percentage of net sales.
|
Year
Ended December 31, 2006 Compared to the Year Ended December 31,
2005
|
|
|
|
Year
Ended
|
|
|
Dollar
Variance
|
|
|
Percentage
Variance
|
|
|
Results
as a Percentage
of
Net Sales for the
Year
Ended
|
|
| |
|
|
December
31,
|
|
|
Favorable
|
|
|
Favorable
|
|
|
December
31,
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
(Unfavorable)
|
|
|
(Unfavorable)
|
|
|
2006
|
|
|
2005
|
|
| |
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Net
sales
|
|
$
|
226,356
|
|
$
|
87,599
|
|
$
|
138,757
|
|
|
158.4
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
Cost
of sales
|
|
|
201,527
|
|
|
84,444
|
|
|
(117,083
|
)
|
|
(138.6
|
)
|
|
89.0
|
|
|
96.4
|
|
|
Gross
profit
|
|
|
24,829
|
|
|
3,155
|
|
|
21,674
|
|
|
687.0
|
|
|
10.9
|
|
|
3.6
|
|
|
Selling,
general and administrative expenses
|
|
|
24,641
|
|
|
12,638
|
|
|
(12,003
|
)
|
|
(94.9
|
)
|
|
10.9
|
|
|
14.4
|
|
|
Income
(loss) from operations
|
|
|
188
|
|
|
(9,483
|
)
|
|
9,671
|
|
|
101.9
|
|
|
0.1
|
|
|
(10.8
|
)
|
|
Other
income (expense), net
|
|
|
3,426
|
|
|
(440
|
)
|
|
3,866
|
|
|
878.6
|
|
|
1.5
|
|
|
(0.5
|
)
|
|
Income
(loss) before non-controlling interest in variable interest
entity
|
|
|
3,614
|
|
|
(9,923
|
)
|
|
13,537
|
|
|
136.4
|
|
|
1.6
|
|
|
(11.3
|
)
|
|
Provision
for income taxes
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Non-controlling
interest in variable interest entity
|
|
|
(3,756
|
)
|
|
—
|
|
|
(3,756
|
)
|
|
(100.0
|
)
|
|
(1.7
|
)
|
|
—
|
|
|
Net
loss
|
|
$
|
(142
|
)
|
$
|
(9,923
|
)
|
$
|
9,781
|
|
|
98.6
|
%
|
|
(0.1
|
)%
|
|
(11.3
|
)%
|
|
Preferred
stock dividends
|
|
|
(2,998
|
)
|
|
—
|
|
|
(2,998
|
)
|
|
(100.0
|
)
|
|
(1.3
|
)
|
|
—
|
|
|
Deemed
dividend on preferred stock
|
|
|
(84,000
|
)
|
|
—
|
|
|
(84,000
|
)
|
|
(100.0
|
)
|
|
(37.1
|
)
|
|
—
|
|
|
Loss
available to common stockholders
|
|
$
|
(87,140
|
)
|
$
|
(9,923
|
)
|
$
|
(77,217
|
)
|
|
(778.2
|
)%
|
|
(38.5
|
)%
|
|
(11.3
|
)%
|
Preliminary
Note.
Various
factors materially affect the comparability of the information presented in
the
above table. These factors relate primarily to the Share Exchange Transaction.
As a result of the Share Exchange Transaction, our results of operations for
2005 include the operations of Kinergy from only March 23 through December
31,
2005. Kinergy’s net sales for the period from January 1 through March 22, 2005
were approximately $23.6 million and, along with other components of Kinergy’s
results of operations, are not included in our results of operations for 2005
in
the above table. Our results of operations for 2006 consist of our operations
and all of our wholly-owned subsidiaries, including Kinergy, for that entire
period.
Net
Sales.
The
increase in our net sales in 2006 as compared to 2005 was predominantly due
to
increased sales volume and increased average sales prices. During 2006, total
volume of ethanol sold as a principal and an agent increased by 49.4 million
gallons, or 94.5%, to 101.7 million gallons as compared to 52.3 million gallons
for 2005. For 2006, our average sales price of ethanol increased by $0.61 per
gallon, or 36.5%, to $2.28 per gallon for all gallons sold as a principal and
an
agent as compared to $1.67 per gallon for 2005. The substantial increase in
sales volume is primarily due to additional supply provided under our ethanol
marketing agreements and the commencement of ethanol production. In the fourth
quarter of 2006, we commenced producing ethanol and its co-products at our
Madera facility and, based on our ownership interest in Front Range, began
recording a proportionate amount of its net sales. The production and sale
of
ethanol and its co-products at our Madera facility and through Front Range
contributed an aggregate of $25.9 million in sales for 2006.
Gross
Profit.
The
increase in gross profit, both in dollars and as a percentage of net sales,
in
2006 as compared to 2005 is generally reflective of more advantageous buying
and
selling during a period of increasing market prices as well as the commencement
of ethanol production at our Madera facility and our acquisition of a 42%
interest in Front Range, both of which occurred in the fourth quarter of 2006.
We established and maintained net long ethanol positions during much of 2006.
The decision to maintain net long ethanol positions was reached in accordance
with our risk management program and was based on a confluence of factors,
including management’s expectation of increased prices of gasoline and petroleum
and the continued phase-out of methyl tertiary-butyl ether, or MTBE, blending
which we believed would result in a significant increase in demand for blending
ethanol with gasoline. Future gross profit margins will vary based upon, among
other things, the size and timing of our net long or short positions during
our
various contract periods and the volatility of the market price of ethanol.
Selling,
General and Administrative Expenses.
The
increase in selling, general and administrative expenses during 2006 as compared
to 2005 was primarily due to a $5,613,000 increase in payroll and benefits
related to the hiring of additional staff positions, a $2,759,000 increase
in
legal, accounting and consulting fees, a $1,671,000 increase in additional
non-cash director and consulting expenses, a $1,200,000 increase in depreciation
and amortization, a $769,000 increase in insurance expense primarily related
to
increased directors and officers insurance costs, a $626,000 increase in general
office and administrative expenses, a $619,000 increase in costs related to
internal controls and procedures in connection with the Sarbanes-Oxley Act
of
2002, a $452,000 increase in travel and entertainment, a $250,000 increase
in
investor relations expense, a $152,000 increase in supplies and repair and
maintenance related to the Madera facility, a $137,000 increase in hardware,
software, and other information technology related expenses, a $102,000 increase
in taxes, licenses, and fees, an $85,000 increase in trade association dues
and
memberships, a $46,000 increase in advertising and promotion, and a $1,321,000
decrease in all other selling, general, and administrative
expenses.
We
expect
that over the near-term, our selling, general and administrative expenses will
increase in terms of actual expenditures as a result of, among other things,
increased legal and accounting fees associated with increased corporate
governance activities related to the Sarbanes-Oxley Act of 2002, recently
adopted rules and regulations of the Securities and Exchange Commission,
increased employee costs associated with planned staffing increases, increased
sales and marketing expenses, increased activities related to the construction
of ethanol production facilities and increased activity in searching for and
analyzing potential acquisitions. However, we expect that over the near-term,
our selling, general and administrative expenses will decrease as a percentage
of net sales due to our expected sales growth.
Other
Income (Expense), Net. Other
income increased during 2006 as compared to 2005, primarily due to a $4,332,000
increase in interest income associated with the significant increase in our
cash
position due to the sale of shares of our common stock in May 2006 and shares
of
our Series A Preferred Stock in April 2006, $1,110,000 in deferred financing
cost amortization related to potential plant expansion financing, and $494,000
in interest expense related to notes payable attributable to Front Range. Other
changes included a $373,000 increase in capitalized interest related to a loan
for the construction of our Madera production facility, a $297,000 decrease
in
penalties and fines expenses and a $350,000 increase in all other
categories.
Non-Controlling
Interest in Variable Interest Entity.
Non-controlling interest in variable interest entity was $3,756,000. This amount
relates to our consolidated treatment of our variable interest entity, Front
Range, and represents the non-controlling interests in the earnings of Front
Range.
Preferred
Stock Dividends.
Shares
of our Series A Cumulative Redeemable Convertible Preferred Stock, or Series
A
Preferred Stock, are entitled to quarterly cumulative dividends payable in
arrears in cash in an amount equal to 5% per annum of the purchase price per
share of the Series A Preferred Stock; or at our option, be paid in additional
shares of Series A Preferred Stock based on the value of the purchase price
per
share of the Series A Preferred Stock. In 2006, we declared cash dividends
on
shares of our Series A Preferred Stock in the aggregate amount of
$2,998,000.
Deemed
Dividend on Preferred Stock.
We have
recorded a deemed dividend on preferred stock in our financial statements for
the year ended December 31, 2006. This non-cash dividend is to reflect the
implied economic value to the preferred stockholder of being able to convert
its
shares into common stock at a price which is in excess of the fair value of
the
Series A Preferred Stock. The fair value allocated to the Series A Preferred
Stock together with the original conversion terms were used to calculate the
value of the deemed dividend on the Series A Preferred Stock of $84 million
at
the date of issuance. The fair value was calculated using the difference between
the agreed-upon conversion price of the Series A Preferred Stock into shares
of
common stock of $8.00 per share and the fair market value of our common stock
of
$29.27 on the date of issuance of the Series A Preferred Stock. The fair value
allocated to the Series A Preferred Stock was in excess of the gross proceeds
received of $84 million in connection with the sale of the Series A Preferred
Stock; however, the deemed dividend on the Series A Preferred Stock is limited
to the gross proceeds received of $84 million. The deemed dividend on preferred
stock is a reconciling item and adjusts our reported net loss, together with
the
preferred stock dividends discussed above, to loss available to common
stockholders.
Year
Ended December 31, 2005 Compared to the Year Ended December 31,
2004
| |
|
|
Year
Ended
|
|
|
|
|
|
Percentage
Variance
|
|
|
Results
as a Percentage
of
Net Sales for the
Year
Ended
|
|
| |
|
|
December
31,
|
|
|
Favorable
|
|
|
Favorable
|
|
|
December
31,
|
|
| |
|
|
2005
|
|
|
2004
|
|
|
(Unfavorable)
|
|
|
(Unfavorable)
|
|
|
2005
|
|
|
2004
|
|
| |
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Net
sales
|
|
$
|
87,599
|
|
$
|
20
|
|
$
|
87,579
|
|
|
437,895.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
Cost
of sales
|
|
|
84,444
|
|
|
13
|
|
|
(84,431
|
)
|
|
(649,469.2
|
)
|
|
96.4
|
|
|
65.0
|
|
|
Gross
profit
|
|
|
3,155
|
|
|
7
|
|
|
3,148
|
|
|
44,971.4
|
|
|
3.6
|
|
|
35.0
|
|
|
Selling,
general and administrative expenses
|
|
|
10,995
|
|
|
2,277
|
|
|
(8,718
|
)
|
|
(382.8
|
)
|
|
12.6
|
|
|
11,385.0
|
|
|
Feasibility
study expensed in connection with acquisition of ReEnergy
|
|
|
852
|
|
|
—
|
|
|
(852
|
)
|
|
(100.0
|
)
|
|
1.0
|
|
|
—
|
|
|
Acquisition
cost expense in excess of cash received
|
|
|
481
|
|
|
—
|
|
|
(481
|
)
|
|
(100.0
|
)
|
|
0.5
|
|
|
—
|
|
|
Discontinued
design of cogeneration facility
|
|
|
310
|
|
|
—
|
|
|
(310
|
)
|
|
(100.0
|
)
|
|
0.4
|
|
|
—
|
|
|
Loss
from operations
|
|
|
(9,483
|
)
|
|
(2,270
|
)
|
|
(7,213
|
)
|
|
(317.8
|
)
|
|
(10.8
|
)
|
|
(11,350.0
|
)
|
|
Total
other expense
|
|
|
(440
|
)
|
|
(532
|
)
|
|
92
|
|
|
17.3
|
|
|
(0.5
|
)
|
|
(2,660.0
|
)
|
|
Loss
from operations before income taxes
|
|
|
(9,923
|
)
|
|
(2,802
|
)
|
|
(7,121
|
)
|
|
(254.1
|
)
|
|
(11.3
|
)
|
|
(14,010.0
|
)
|
|
Provision
for income taxes
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Net
loss
|
|
$
|
(9,923
|
)
|
$
|
(2,802
|
)
|
$
|
(7,121
|
)
|
|
(254.1
|
)
|
|
(11.3
|
)%
|
|
(14,010.0
|
)%
|
Net
Sales.
Our net
sales increased by approximately $87.6 million in 2005 as compared to 2004.
This
increase was almost entirely due to the acquisition of Kinergy on March 23,
2005. Without the acquisition of Kinergy, our net sales would have been $16,000
in 2005.
Gross
Profit.
Our
increase in gross profit was primarily due to the acquisition of Kinergy on
March 23, 2005. Prior to 2005, Kinergy’s gross profit margins for marketing
ethanol produced by third parties averaged between 2.0% and 4.4%. Gross profit
margins above this historical average range have generally resulted after
correctly anticipating and benefiting from holding a net long position (i.e.,
volume on purchase contracts, together with inventory, exceeds volume on sales
contracts) while ethanol prices are rising, or holding a net short position
(i.e., volume on sales contracts exceeds volume on purchase contracts and
inventory) while ethanol prices are declining. Gross profit margins below the
historical average range have generally resulted when a net long or short
position was held and there was a sustained adverse movement in market prices.
Selling,
General and Administrative Expenses.
The
increase in selling, general and administrative expenses during 2005 as compared
to 2004 was primarily due to $2,041,000 in additional legal, accounting and
consulting fees, $2,058,000 in abandoned debt financing fees, $802,000 in
additional amortization of intangibles and $1,251,000 in additional payroll
expense related to the three executive employment agreements that became
effective upon the consummation of the Share Exchange Transaction on March
23,
2005, the addition of two staff positions in May and June 2005, an employee
promotion in May 2005, the addition of two executive positions in June 2005,
the
addition of two high-level ethanol plant management positions in September
2005
and the addition of three additional staff positions in the fourth quarter
of
2005. Additionally, non-cash compensation and consulting fees increased $651,000
for non-cash compensation from stock grants in connection with the hiring of
two
employees, $232,000 for a stock grant that vested upon closing of the Share
Exchange Transaction on March 23, 2005, $104,000 for non-cash consulting fees
related to stock options granted to a consulting firm in connection with the
employment of our Chief Financial Officer, $59,000 for non-cash compensation
related to stock options granted in connection with the hiring of two ethanol
plant managers, $22,000 for non-cash compensation related to stock options
granted to reward employees for past performance, $173,000 for non-cash
consulting fees related to warrants that were granted in February 2004 and
vested over one year, and $823,000 for non-cash consulting fees related to
warrants that were granted in connection with the Share Exchange Transaction
that vest ratably over two years. The increase in selling, general and
administrative expenses was also due to $195,000 in additional insurance expense
related primarily to liability and property coverage for our Madera construction
site, a $409,000 increase in non-sales commission expense related to insurance
proceeds for the casualty loss at the Company’s Madera facility, a $164,000
increase for expenses related to the termination of the proposed acquisition
of
PBI, a $221,000 increase in business travel expenses, a $82,000 increase in
research and development expense, a $168,000 increase in market and filing
fees,
a $165,000 increase in policy and investor relations expenses, a $72,000
increase in rents, a $48,000 increase in advertising and marketing expense,
an
$55,000 increase in dues and trade memberships, a $54,000 increase in printing
and postage expense, a $25,000 increase in telephone expense, a $7,000 increase
in bad debt expense, and the net balance of $45,000 related to various increases
in other selling, general and administrative expenses.
Other
Income (Expense), Net.
Other
income increased during 2005 as compared to 2004 primarily due to a $345,000
increase in interest income on cash held in seven day investment accounts,
$28,000 in management fees and other income, a net decrease of $37,000 in
interest expense related to long-term debt, amortization of discount, and
construction payables, net of capitalized interest related to our Madera ethanol
plant, all of which were partially offset by an increase of $15,000 in bank
charges, finance charges, and short-term interest and an increase in liquidated
damages and fees paid to stockholders in the amount of $299,000.
Liquidity
and Capital Resources
During
2006, we funded our operations primarily from our cash on hand, net income
from
the operations, and net proceeds from the issuance and sale of shares of our
Series A Preferred Stock and common stock, as well as the exercise of warrants
and options to purchase shares of our common stock. As of December 31, 2006,
we
had working capital of $96,451,000 representing an increase in working capital
of $99,345,000 from negative working capital of $2,894,000 as of December 31,
2005. This increase in working capital is primarily due to a private offering
of
our common stock that we conducted in May 2006 in which we raised $137,619,000
in net proceeds.
Our
current available capital resources consist primarily of approximately
$44,053,000 in cash and cash equivalents as of December 31, 2006. We expect
that
our future available capital resources will consist primarily of any balance
of
this cash and cash equivalents as of December 31, 2006, cash generated from
operations, if any, unrestricted proceeds from the sale of our Series A
Preferred Stock, and any future debt and/or equity financings. We also have
$24,851,000 of restricted funds remaining as of December 31, 2006 from the
proceeds of the sale of our Series A Preferred Stock. These funds are held
in a
restricted funds account and are subject to restrictions which, among other
things, limit the requisition of funds only for the payment of costs in
connection with the construction or acquisition of ethanol production
facilities.
Accounts
receivable increased $24,374,000 during 2006 from $4,948,000 as of December
31,
2005 to $29,322,000 as of December 31, 2006. This increase is primarily due
to a
158.4% increase in our net sales for 2006 over 2005.
Inventory
balances increased $7,232,000 during 2006, from $363,000 as of December 31,
2005
to $7,595,000 as of December 31, 2006. As of December 31, 2005, there was
significant inventory in transit (prepaid inventory) due to logistical delays
in
delivery to our inventory terminal locations. The increased inventory balance
as
of December 31, 2006 reflects a return to a more typical balance between
inventory in transit and actual inventory on hand.
Other
current assets increased $2,221,000 during 2006, from $86,000 as of December
31,
2005 to $2,307,000 as of December 31, 2006. The increase is primarily related
to
a $1,310,000 increase in deferred financing fees.
Property
and equipment increased $172,948,000 during 2006 from $23,208,000 as of
December 31, 2005 to $196,156,000 as of December 31, 2006. This increase is
primarily due to our construction activities at our plants under development
and
our acquisition of our interest in Front Range.
Total
tangible other assets increased $35,095,000 during 2006 from $62,000 as of
December 31, 2005 to $35,157,000 as of December 31, 2006. The increase is
primarily due to an increase in restricted cash from the sale of our Series
A
Preferred Stock, and advances made for equipment, and deferred financing fees
related to our April 2006 debt financing.
Cash
used
in our operating activities totaled $8,151,000 for 2006 as compared to
$4,007,000 generated in 2005. This $12,158,000 increase in use of cash is
primarily due to a $20,939,000 increase in accounts receivable, a $3,697,000
increase in inventory and a $513,000 increase in prepaid expenses and other
assets, partially offset by a $4,050,000 increase in accounts payable.
Cash
used
in our investing activities totaled $174,820,000 for 2006 as compared to
$17,251,000 for 2005. Included in the results for 2006 is $24,851,000 in
restricted cash designated for construction projects and acquisitions,
$81,540,000 in cash used for additions to property, plant, and equipment
reflecting activities associated with our plants under development and
$28,962,000 in purchases of available for sale investments.
Cash
provided by our financing activities totaled $222,503,000 for 2006 as compared
to $17,765,000 for 2005. This significant increase is related to proceeds from
our private offerings of Series A Preferred Stock and common stock in April
and
May 2006, respectively, as well as from the exercise of warrants and stock
options. The amount for 2005 includes the proceeds from the sale of our common
stock in March 2005.
We
believe that current and future available capital resources, revenues generated
from operations and other existing sources of liquidity, including proceeds
from
our new debt financing described below, proceeds remaining from our private
offerings of Series A Preferred Stock in April 2006 and common stock in May
2006
described below, and distributions, if any, as a result of our ownership
interest in Front Range, will be adequate to meet our anticipated working
capital and capital expenditure requirements for at least the next twelve
months. If,
however, our capital requirements or cash flow vary materially from our current
projections, if unforeseen circumstances occur or if we require a significant
amount of cash to fund future acquisitions, we may require additional financing.
Our failure to raise capital, if needed, could restrict our growth or hinder
our
ability to compete.
New
Debt Financing
In
February 2007, we closed a debt financing transaction, or Debt Financing, in
the
aggregate amount of up to $325,000,000 through certain of our wholly-owned
indirect subsidiaries, or the Borrowers. The primary purpose of the credit
facility is to provide debt financing in connection with the development,
construction, installation, engineering, procurement, design, testing, start-up,
operation and maintenance of five ethanol production facilities.
The
Debt
Financing includes (i) a construction loan facility in an aggregate amount
of up
to $300,000,000 that matures on the earlier of October 27, 2008 and the date,
or
Conversion Date, the construction loans made thereunder are converted into
term
loans, and (ii) a term loan facility in an aggregate amount of up to
$300,000,000 that matures on the date that is 84 months after the Conversion
Date, and (iii) a working capital and letter of credit facility in an aggregate
amount of up to $25,000,000 that matures on the date that is 12 months after
the
Conversion Date.
During
the term of the working capital and letter of credit facility, the Borrowers
may
borrow, repay and re-borrow amounts available under the working capital and
letter of credit facility. Loans made under the construction loan or the term
loan facility may not be re-borrowed once repaid or prepaid. Loans made under
the construction loan facility do not amortize, and are fully due and payable
on
their maturity date. The term loan facility is intended to refinance the loans
made under the construction loan facility. Loans made under the term loan
facility amortize at a rate of 6.0% per annum from and after the Conversion
Date, and the remaining principal amounts are fully due and payable on their
maturity date. Loans made under the working capital and letter of credit
facility are fully due and payable on their maturity date.
The
Borrowers have the option to select floating or periodic fixed-rate loans under
the Debt Financing. Depending upon the type of loan and whether the loan is
made
under the construction loan facility, the term loan facility or the working
capital and letter of credit facility, loans under the Debt Financing bear
interest at rates ranging from 2.25% to 4.50% over the selected fixed or
floating interest rate. Interest on floating rate loans is payable quarterly
in
arrears, while interest on the various fixed-rate loans available under the
credit facility is payable quarterly (or earlier if at the end of selected
interest periods ranging from one to six months).
Borrowings
and the Borrowers’ other obligations under the Debt Financing are secured by a
first-priority security interest in all of the equity interests in the Borrowers
and substantially all the assets of the Borrowers.
Loans
and
letters of credit under the credit facility are subject to conditions precedent,
including, among others, the absence of a material adverse effect; the absence
of defaults or events of defaults; the accuracy of certain representations
and
warranties; the maintenance of a debt to equity ratio which is not in excess
of
65:35; title insurance date-downs; payment of fees and expenses; the
contribution of all required equity, which is anticipated to be approximately
$218.8 million in the aggregate; obtainment of required contracts, permits
and
insurance; and certain certifications from the independent engineer in respect
of construction progress. Loans and letters of credit under the credit facility
are also generally not available for the Madera plant or the Boardman plant
until its completion. Also, the Borrowers may not be able to fully utilize
the
credit facility if the completed ethanol plants fail to meet certain minimum
performance standards. Finally, disbursements from the construction and term
facility are limited to a percentage of project costs of the corresponding
plant
and in any event are not to exceed approximately $1.15 per gallon of annual
production capacity of the plant.
We
expect
to achieve a senior debt to equity ratio of approximately 55:45 upon
commencement of commercial operations of each of the Madera and Boardman ethanol
plants. We expect to achieve a senior debt to equity ratio of approximately
35:65 during the construction phase of each of the Burley, and Brawley ethanol
plants and
another plant in California, the location of which is yet to be
announced.
Upon
commencement of commercial operations of each of these plants, we expect to
draw
additional funds to increase the senior debt to equity ratio to approximately
55:45.
In
connection with the Debt Financing, we have also entered into a Sponsor Support
Agreement under which we are to provide limited contingent equity support in
connection with the development, construction, installation, engineering,
procurement, design, testing, start-up and maintenance of five ethanol
production facilities. In particular, we have agreed to contribute to the
Borrowers up to an aggregate of $42,400,000, or Sponsor Funding Cap, of
contingent equity in the event the Borrowers’ have insufficient funds to either
pay their project costs (other than debt service under the Debt Financing)
as
they become due and payable or cause the ethanol production facilities to be
completed by the Conversion Date. We have agreed to provide a warranty with
respect to all ethanol plants other than our Madera facility. The term of the
warranty is one year from the date the ethanol plant achieves commercial
operations. Our obligations under the warranty are capped at the Sponsor Funding
Cap. Until our contingent equity obligations have been fully performed or the
warranty period has expired, we may not incur any secured indebtedness for
borrowed money, grant liens on our assets or provide any secured credit
enhancements in an aggregate amount in excess of $10,000,000 unless we provide
the lenders under the Debt Financing with the same liens or credit
support.
Acquisition
of Front Range
In
October 2006, we acquired 42% of the outstanding membership interests of Front
Range, which owns and operates an ethanol production facility located in
Windsor, Colorado. As consideration for the acquisition of the membership
interests, we paid $30 million in cash and issued an aggregate of 2,081,888
shares of our common stock and a warrant to purchase an aggregate of up to
693,963 shares of our common stock at an exercise price of $14.41 per share.
The
warrant is exercisable immediately through and including October 17, 2007.
Front
Range is subject to certain loan covenants which became effective in the fourth
quarter of 2006. Under these covenants, Front Range is required to maintain
a
certain fixed-charge coverage ratio, a minimum level of working capital, and
a
minimum level of net worth. The covenants also limit annual distributions made
to the owners of Front Range, including Pacific Ethanol, based on Front Range’s
leverage ratio.
Sale
of Common Stock
On
May
31, 2006, we issued to 45 investors an aggregate of 5,496,583 shares of our
common stock at a price of $26.38 per share, for an aggregate purchase price
of
$145.0 million in cash. Net proceeds from this private offering totaled
approximately $138.0 million. We also issued to the investors warrants to
purchase an aggregate of 2,748,297 shares of our common stock at an exercise
price of $31.55 per share.
Sale
of Series A Preferred Stock
On
April
13, 2006, we issued to Cascade 5,250,000 shares of our Series A Preferred Stock
at a price of $16.00 per share for an aggregate purchase price of $84.0 million.
Of the $84.0 million aggregate purchase price, $4.0 million was paid to us
at
closing and $80.0 million was deposited into a restricted cash account that
is
disbursed in accordance with a Deposit Agreement. We used the initial $4.0
million of proceeds for general working capital and must use the remaining
$80.0
million for the construction or acquisition of one or more ethanol production
facilities in accordance with the terms of the Deposit Agreement.
Terminated
Debt Financing
On
April
13, 2006, we entered into a Construction and Term Loan Agreement with TD
BankNorth, N.A. and Comerica Bank for debt financing in the aggregate amount
of
up to approximately $34.0 million. In December 2006, we paid $1.0 million to
amend this agreement to extend the termination date through February 28, 2007.
On February 28, 2007, this debt financing was unused and
terminated.
Effects
of Inflation
The
impact of inflation has not been significant on our financial condition or
results of operations or those of our operating subsidiaries.
Impact
of New Accounting Pronouncements
In
February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities.
SFAS
No. 159 permits an entity to irrevocably elect fair value on a
contract-by-contract basis as the initial and subsequent measurement attribute
for many financial assets and liabilities and certain other items including
insurance contracts. Entities electing the fair value option would be required
to recognize changes in fair value in earnings and to expense upfront cost
and
fees associated with the item for which the fair value option is elected. SFAS
No. 159 is effective for fiscal years beginning after November 15, 2007. Early
adoption is permitted as of the beginning of a fiscal year that begins on or
before November 15, 2007, provided the entity also elects to apply the
provisions of SFAS No. 157, Fair
Value Measurements.
We are
currently evaluating the impact of adopting SFAS No. 159 on our financial
condition or results of operations.
In
September 2006, the Securities and Exchange Commission issued SAB No. 108,
Topic
1N, Financial
Statements—Considering the Effects of Prior Year Misstatements When Quantifying
Misstatements in the Current Year Financial Statements.
SAB No.
108 addresses how to quantify the effect of an error on the financial statements
and requires a dual approach to compute the materiality of the misstatement.
Specifically, the amount of the misstatement is to be computed using both the
“rollover” (i.e., the current year income statement perspective) and the “iron
curtain” (i.e., the year-end balance sheet perspective). SAB No. 108 is
effective for all fiscal years ending after November 15, 2006, and accordingly,
we adopted SAB No. 108 in the fourth quarter of fiscal 2006. The adoption of
SAB
No. 108 did not have a material impact on our financial condition or our results
of operations.
In
September 2006, the FASB issued SFAS No. 157, Fair
Value Measurements.
This
new statement provides a single definition of fair value, together with a
framework for measuring it, and requires additional disclosure about the use
of
fair value to measure assets and liabilities. SFAS No. 157 also emphasizes
that
fair value is a market-based measurement, not an entity-specific measurement,
and sets out a fair value hierarchy with the highest priority being quoted
prices in active markets. The required effective date of SFAS No. 157 is the
first quarter of 2008. We are currently evaluating the impact this statement
may
have on our consolidated financial statements.
In
September 2006, the FASB issued FASB Staff Position (“FSP”) AUG AIR-1,
Accounting
for Planned Major Maintenance Activities.
The
principal source of guidance on the accounting for planned major maintenance
activities is the Airline Guide. The Airline Guide permitted four alternative
methods of accounting for planned major maintenance activities: direct expense,
built-in overhaul, deferral and accrual (accrue-in-advance). FSP AUG AIR-1
amended the Airline Guide by prohibiting the use of the accrue-in-advance method
of accounting for planned major maintenance activities in annual and interim
financial reporting periods. The required effective date of FSP AUG-AIR-1 is
the
first quarter of 2007. We do not anticipate FSP AUG AIR-1 to have a material
affect on our consolidated financial statements.
In
June
2006, the FASB issued Financial Interpretation No. (“FIN”) 48, Accounting
for Uncertainty in Income Taxes—An Interpretation of FASB Statement No.
109.
This
interpretation 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 interpretation contains a two-step
approach to recognizing and measuring uncertain tax positions accounted for
in
accordance with SFAS No. 109. The first step is to evaluate the tax position
for
recognition by determining if the weight of available evidence indicates that
it
is more likely than not that the position will be sustained on audit, including
resolution of related appeals or litigation processes, if any. The second step
is to measure the tax benefit as the largest amount which is more than fifty
percent likely of being realized upon ultimate settlement. The interpretation
also provides guidance on derecognition, classification, interest and penalties,
and other matters. These provisions are effective for us beginning in the first
quarter of 2007. We are assessing the impact of this statement and currently
do
not believe that the adoption will have a material effect on our consolidated
financial statements.
In
February 2006, the FASB issued SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments,
which
amends SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities
and SFAS
No. 140, Accounting
for the Impairment or Disposal of Long-Lived Assets.
Specifically, SFAS No. 155 amends SFAS No. 133 to permit fair value
remeasurement for any hybrid financial instrument with an embedded derivative
that otherwise would require bifurcation, provided the whole instrument is
accounted for on a fair value basis. Additionally, SFAS No. 155 amends SFAS
No.
140 to allow a qualifying special purpose entity to hold a derivative financial
instrument that pertains to a beneficial interest other than another derivative
financial instrument. SFAS No. 155 applies to all financial instruments acquired
or issued after the beginning of an entity’s first fiscal year that begins after
September 15, 2006, with early application allowed. We do not expect the
adoption of SFAS No. 155 to have a material impact on our results of operations
or financial position.
Contractual
Obligations
The
following table outlines payments due under our significant contractual
obligations (in thousands):
|
Contractual
Obligations
At
December 31, 2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|
Total
|
|
|
Sourcing
commitments(1)
|
|
$
|
81,945
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
81,945
|
|
|
Debt
principal(2)
|
|
|
4,030
|
|
|
2,910
|
|
|
3,158
|
|
|
3,425
|
|
|
18,359
|
|
|
—
|
|
|
31,882
|
|
|
Debt
interest(2)
|
|
|
2,831
|
|
|
2,597
|
|
|
2,344
|
|
|
2,070
|
|
|
1,773
|
|
|
—
|
|
|
11,615
|
|
|
Water
rights - capital lease, including interest(3)
|
|
|
160
|
|
|
160
|
|
|
160
|
|
|
160
|
|
|
160
|
|
|
800
|
|
|
1,600
|
|
|
Operating
leases(4)
|
|
|
267
|
|
|
203
|
|
|
172
|
|
|
172
|
|
|
110
|
|
|
—
|
|
|
924
|
|
|
Firm
capital commitments(5)
|
|
|
78,148
|
|
|
17,570
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
95,718
|
|
|
Preferred
dividends(6)
|
|
|
4,200
|
|
|
4,200
|
|
|
4,200
|
|
|
4,200
|
|
|
4,200
|
|
|
4,200
|
|
|
25,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
commitments
|
|
$
|
171,581
|
|
$
|
27,640
|
|
$
|
10,034
|
|
$
|
10,027
|
|
$
|
24,602
|
|
$
|
5,000
|
|
$
|
248,884
|
|
__________
|
|
(1) |
Unconditional
purchase commitments for production materials incurred in the normal
course of business.
|
|
|
(2) |
Under
Front Range’s three term loan agreements quarterly payments apply to
accrued interest and principal and mature in 2011, but have required
principal payments based on a ten year amortization schedule. Interest
fluctuates at a premium of 2.75-3.50% based on the 30- or 90-day
LIBOR,
depending on the loan. At December 31, 2006, the 30-day LIBOR was
5.33%
and the 90-day LIBOR was 5.32%.
|
|
|
(3) |
The
water rights lease obligation of Front Range relates to a lease agreement
for water in production processes. The lease requires an initial
payment
of $400,000 and annual payments of $160,000 per year for the next
ten
years. The future payments were discounted using a 5.25% interest
rate.
|
|
|
(4) |
Future
minimum payments under non cancellable operating
leases.
|
|
|
(5) |
Construction
commitments for in-progress and contracted ethanol processing
facilities.
|
|
|
(6) |
Represents
dividends on 5,250,000 shares of Series A Preferred
Stock.
|
The
above
table outlines our obligations as of December 31, 2006 and does not reflect
the changes in our obligations that occurred after that date.
Item
7A. Quantitative
and Qualitative Disclosures About Market Risk.
We
are
exposed to various market risks, including changes in commodity prices and
interest rates. Market risk is the potential loss arising from adverse changes
in market rates and prices. In the ordinary course of business, we enter into
various types of transactions involving financial instruments to manage and
reduce the impact of changes in commodity prices and interest rates. We do
not
enter into derivatives or other financial instruments for trading or speculative
purposes.
Commodity
Risk
-
Cash
Flow Hedges
As
part
of our risk management strategy, we use derivative instruments to protect cash
flows from fluctuations caused by volatility in commodity prices for periods
of
up to twelve months. These hedging activities are conducted to protect gross
margins to reduce the potentially adverse effects that market volatility could
have on operating results by minimizing our exposure to price volatility on
ethanol sale and purchase commitments where the price is to be set at a future
date and/or if the contract specifies a floating or index-based price for
ethanol that is based on either the New York Mercantile Exchange price of
gasoline or the Chicago Board of Trade price of ethanol. In addition, we hedge
anticipated sales of ethanol to minimize our exposure to the potentially adverse
effects of price volatility. These derivatives are designated and documented
as
SFAS No. 133 cash flow hedges and effectiveness is evaluated by assessing the
probability of the anticipated transactions and regressing commodity futures
prices against our purchase and sales prices. Ineffectiveness, which is defined
as the degree to which the derivative does not offset the underlying exposure,
is recognized immediately in earnings. For the year ended December 31, 2006,
losses of ineffectiveness in the amount of $239,000 was recorded in cost of
goods sold. For the year ended December 31, 2006, an effective gain in the
amount of $1,281,000 was recorded to revenue and an effective loss in the amount
of $438,000 was recorded in cost of goods sold. There was no ineffectiveness
or
effectiveness recorded for the year ended December 31, 2005. Amounts remaining
in other comprehensive income (loss) will be reclassified to earnings upon
the
recognition of the related purchase or sale. Other comprehensive gain in the
amount of $461,000 associated with commodity cash flow hedges is expected to
be
recognized in income over the next twelve months. The notional balance of these
derivatives as of December 31, 2006 and 2005 were $11,588,000 and $0,
respectively.
Interest
Rate Risk
As
part
of our interest rate risk management strategy, we use derivative instruments
to
minimize significant unanticipated earnings fluctuations that may arise from
rising variable interest rate costs associated with existing and anticipated
borrowings. To meet these objectives we purchased interest rate caps on the
three-month LIBOR. The rate for a notional balance ranging from $0 to
$22,705,473 is 5.50% per annum. The rate for a notional balance ranging from
$0
to $9,730,917 is 6.00% per annum. These derivatives are designated and
documented as SFAS No. 133 cash flow hedges and effectiveness is evaluated
by
assessing the probability of anticipated interest expense and regressing the
historical value of the rates against the historical value in the existing
and
anticipated debt. Ineffectiveness, reflecting the degree to which the derivative
does not offset the underlying exposure, is recognized immediately in earnings.
During the year ended December 31, 2006, ineffectiveness in the amount of
$24,000 was recorded in interest expense. There was no ineffectiveness recorded
in the years ended December 31, 2005 and 2004. Amounts remaining in other
comprehensive income will be reclassified to earnings upon the recognition
of
the hedged interest expense. For the year ending December 31, 2007, we
anticipate reclassifying $27,000 to income associated with our cash flow
interest rate caps.
Front
Range, our variable interest entity, entered into an interest rate swap with
a
notional balance of $17,658,000 to provide a fixed rate of 8.16% on its
construction and term loan. This interest rate swap is accounted for as a
non-designated derivative in accordance with SFAS No. 133 whereby it is marked
to fair value and changes in fair value are recorded to other expense. For
the
year ended December 31, 2006, an amount of $13,000 was recorded to other
expense.
We
marked
all of our derivative instruments to fair value at each period end, except
for
those derivative contracts which qualified for the normal purchase and sale
exemption pursuant to SFAS No. 133. According to our designation of the
derivative, changes in the fair value of derivatives are reflected in net income
or other comprehensive income.
Other
Comprehensive Income
Other
comprehensive income relative to derivatives for the year ended December 31,
2006 is as follows (in thousands):
| |
|
Commodity
Derivatives
|
|
Interest
Rate Derivatives
|
|
| |
|
Gain/(Loss)*
|
|
Gain/(Loss)*
|
|
|
Beginning
balance, January 1, 2006
|
|
$
|
—
|
|
$
|
—
|
|
|
Net
changes
|
|
|
1,307
|
|
|
(272
|
)
|
|
Less:
Amount reclassified to revenue
|
|
|
1,281
|
|
|
—
|
|
|
Less:
Amount reclassified to cost of goods sold
|
|
|
(435
|
)
|
|
—
|
|
|
Less:
Amount reclassified to other income (expense)
|
|
|
—
|
|
|
(7
|
)
|
|
Ending
balance, December 31, 2006
|
|
$
|
461
|
|
$
|
(265
|
)
|
—————
*Calculated
on a pretax basis
The
estimated fair values of our derivatives as of December 31, 2006 and 2005 are
as
follows (in thousands):
| |
|
2006
|
|
2005
|
|
|
Commodity
futures
|
|
$
|
329
|
|
$
|
—
|
|
|
Interest
rate options
|
|
|
125
|
|
|
—
|
|
|
Total
|
|
$
|
454
|
|
$
|
—
|
|
Material
Limitations
The
disclosures with respect to the above noted risks do not take into account
the
underlying commitments or anticipated transactions. If the underlying items
were
included in the analysis, the gains or losses on the futures contracts may
be
offset. Actual results will be determined by a number of factors that are not
generally under our control and could vary significantly from those factors
disclosed.
We
are
exposed to credit losses in the event of nonperformance by counterparties on
the
above instruments, as well as credit or performance risk with respect to our
hedged customers’ commitments. Although nonperformance is possible, we do not
anticipate nonperformance by any of these parties.
Item
8. Financial
Statements and Supplementary Data.
Reference
is made to the financial statements included in this report, which begin at
Page
F-1.
Item
9. Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure.
None.
Evaluation
of Disclosure Controls and Procedures
We
conducted an evaluation under the supervision and with the participation of
our
management, including our Chief Executive Officer and Acting
Chief
Financial
Officer,
who is also
our
Chief Operating
Officer,
of the
effectiveness of the design and operation of our disclosure controls and
procedures. The term “disclosure controls and procedures,” as defined in Rules
13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934, as
amended (“Exchange Act”), means controls and other procedures of a company that
are designed to ensure that information required to be disclosed by the company
in the reports it files or submits under the Exchange Act is recorded,
processed, summarized and reported, within the time periods specified in the
Securities and Exchange Commission’s rules and forms. Disclosure controls and
procedures also include, without limitation, controls and procedures designed
to
ensure that information required to be disclosed by a company in the reports
that it files or submits under the Exchange Act is accumulated and communicated
to the company’s management, including its principal executive and principal
financial officers, or persons performing similar functions, as appropriate,
to
allow timely decisions regarding required disclosure. Based on this evaluation,
our Chief Executive Officer and Acting Chief Financial Officer concluded as
of
December 31, 2006 that our disclosure controls and procedures were not effective
at the reasonable assurance level due to the material weaknesses discussed
immediately below.
Management’s
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-15(f)
under the Exchange Act. Our internal control over financial reporting is
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes
in
accordance with generally accepted accounting principles. Our internal control
over financial reporting includes those policies and procedures
that:
| |
(i)
|
pertain
to the maintenance of records that, in reasonable detail, accurately
and
fairly reflect the transactions and dispositions of our
assets;
|
| |
(ii)
|
provide
reasonable assurance that transactions are recorded as necessary
to permit
preparation of financial statements in accordance with generally
accepted
accounting principles, and that our receipts and expenditures are
being
made only in accordance with authorizations of our management and
directors; and
|
| |
(iii)
|
provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could
have
a material affect on our financial
statements.
|
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
A
material weakness in internal control over financial reporting is defined by
the
Public Company Accounting Oversight Board’s Audit Standard No. 2 as being a
significant deficiency, or combination of significant deficiencies, that results
in more than a remote likelihood that a material misstatement of the financial
statements would not be prevented or detected. A significant deficiency is
a
control deficiency, or combination of control deficiencies, that adversely
affects the company’s ability to initiate, authorize, record, process, or report
external financial data reliably in accordance with generally accepted
accounting principles such that there is more than a remote likelihood that
a
misstatement of the company’s annual or interim financial statements that is
more than inconsequential will not be prevented or detected.
Management
assessed and evaluated the effectiveness of our internal control over financial
reporting as of December 31, 2006. Based on the results of management’s
assessment and evaluation, our Chief Executive Officer and Acting Chief
Financial Officer concluded that while certain of the remediation initiatives
undertaken in response to material weaknesses identified and discussed below
have been implemented, other remediation initiatives were either not fully
implemented by December 31, 2006 or were completed thereafter, but before the
filing of this report. Further, the material weakness identified as of December
31, 2005 as “The organization of our accounting department did not provide us
with the appropriate resources and adequate technical skills to accurately
account for and disclose our activities” continued to exist as of December 31,
2006, but management identified seven more specific material weaknesses relating
to our internal control over financial reporting, as follows:
| |
(1)
|
We
had not effectively implemented comprehensive entity-level internal
controls.
|
| |
(2)
|
We
did not have a sufficient complement of personnel with appropriate
training and experience in generally accepted accounting principals,
or
GAAP.
|
| |
(3)
|
We
did not adequately segregate the duties of different personnel within
our
accounting group due to an insufficient complement of staff.
|
| |
(4)
|
We
did not perform adequate oversight of certain accounting functions
and
maintained inadequate documentation of management review and approval
of
accounting transactions and financial reporting
processes.
|
| |
(5)
|
We
did not have adequate controls governing major account invoice processing
and payment.
|
| |
(6)
|
We
had not fully implemented certain control activities and capabilities
included in the design of our enterprise resource platform, or ERP,
system.
|
| |
(7)
|
We
did not have adequate access and data and formulaic integrity controls
over critical spreadsheets used in connection with accounting and
financial reporting.
|
The
foregoing material weaknesses are described in detail below under the caption
“Material Weaknesses and Related Remediation Initiatives.” As
a
result of these material weaknesses, our Chief Executive Officer and Acting
Chief Financial Officer concluded that we did not maintain effective internal
control over financial reporting as of December 31, 2006.
In
making
its assessment of our internal control over financial reporting, management
used
criteria issued by the Committee of Sponsoring Organizations of the Treadway
Commission (“COSO”) in its Internal
Control-Integrated Framework.
Because
of the material weaknesses described above, management believes that, as of
December 31, 2006, we did not maintain effective internal control over financial
reporting.
A
nationally-recognized independent consulting firm assisted management with
its
assessment of the effectiveness of our internal control over financial
reporting, including scope determination, planning, staffing, documentation,
testing, remediation and retesting and overall program management of the
assessment project.
Our
independent auditors have issued an attestation report on management’s
assessment of our internal control over financial reporting. That report appears
below under the caption, “Report of Independent Registered Public Accounting
Firm.”
Inherent
Limitations on the Effectiveness of Controls
Management
does not expect that our disclosure controls and procedures or our internal
control over financial reporting will prevent or detect all errors and all
fraud. A control system, no matter how well conceived and operated, can provide
only reasonable, not absolute, assurance that the objectives of the control
systems are met. Further, the design of a control system must reflect the fact
that there are resource constraints, and the benefits of controls must be
considered relative to their costs. Because of the inherent limitations in
a
cost-effective control system, no evaluation of internal control over financial
reporting can provide absolute assurance that misstatements due to error or
fraud will not occur or that all control issues and instances of fraud, if
any,
have been or will be detected.
These
inherent limitations include the realities that judgments in decision-making
can
be faulty and that breakdowns can occur because of a simple error or mistake.
Controls can also be circumvented by the individual acts of some persons, by
collusion of two or more people, or by management override of the controls.
The
design of any system of controls is based in part on certain assumptions about
the likelihood of future events, and there can be no assurance that any design
will succeed in achieving its stated goals under all potential future
conditions. Projections of any evaluation of controls effectiveness to future
periods are subject to risks. Over time, controls may become inadequate because
of changes in conditions or deterioration in the degree of compliance with
policies or procedures.
Material
Weaknesses and Related Remediation Initiatives
(1) We
had
not effectively implemented comprehensive entity-level internal controls, as
evidenced by the following deficiencies:
· We
did
not maintain documentation evidencing quarterly or other meetings between the
Audit Committee, senior financial managers and our General Counsel. Such
meetings include reviewing and approving quarterly and annual filings with
the
Securities and Exchange Commission and reviewing on-going activities to
determine if there are any potential audit related issues which may warrant
involvement and follow-up action by the Audit Committee. We believe that we
have
fully implemented processes to create or maintain appropriate documentation.
We
anticipate that our updated controls will be tested and this deficiency will
be
remediated by June 30, 2007.
· We
did
not maintain documentation evidencing discussions comparing actual results
to
budgeted amounts between executive management and our Board of Directors. We
believe that we have fully implemented processes to create or maintain
appropriate documentation. We anticipate that our updated controls will be
tested and this deficiency will be remediated by June 30, 2007.
· We
did
not obtain prescribed attestations by executive management regarding their
compliance with our Codes of Ethics or attestations of employees as to their
understanding of and compliance with company policies related to their
employment. Our standard operating procedures, or SOPs, are available to all
employees through our intranet and our Codes of Ethics are available on our
main
website. We require all new employees to affirm in writing that they will read
and abide by our SOPs. We anticipate that the steps necessary to address this
deficiency will be fully implemented by June 30, 2007 and that our updated
controls will be tested and this deficiency will be remediated by December
31,
2007.
· We
did
not follow a formal fraud assessment process as prescribed by our SOPs. Our
SOPs
call for a quarterly fraud assessment as part of our financial closing
procedures and an annual fraud assessment as part of the business planning
process carried out by our management. We intend to modify our SOPs to assign
responsibility for performing the quarterly and annual fraud risk assessments
to
the Internal Audit Director with review and approval by our Executive Committee.
We anticipate that the steps necessary to address this deficiency will be fully
implemented by June 30, 2007 and that our updated controls will be tested and
this deficiency will be remediated by December 31, 2007.
· We
did
not make available to management timely internal management reports, or to
the
extent available, we maintained insufficient auditable evidence of management’s
review and analysis of those reports. Management has directed that key
performance indicators and other financial information be gathered and reported
to our Executive Committee on a weekly basis. Management has initiated an effort
to provide financial reports from our ERP system and its supporting financial
management systems to appropriate members of the operational and financial
management teams. This broadened reporting capability will require additional
configuration of the appropriate systems and staff training in report writing
tools. We expect that the timing of these remediation efforts will be partly
dependent on the timing of our hiring of a Chief Financial Officer and a
Controller. However, we anticipate that the steps necessary to address this
deficiency will be fully implemented by June 30, 2007 and that our updated
controls will be tested and this deficiency will be remediated by December
31,
2007.
· We
did
not fully implement or automate through our ERP system our SOP governing
delegation of authority, which includes contract and spending limits for all
transaction processing functions. Our SOP governing delegation of authority
has
been reviewed and approved by our management, Executive Committee and General
Counsel. We have completed full implementation of an automation of our SOP
governing delegation of authority within our ERP system. We anticipate that
our
updated controls will be tested and this deficiency will be remediated by June
30, 2007.
· We
did
not fully comply with SOPs prescribing deadlines and control activities related
to our period-end closing and financial reporting processes during 2006. We
have
implemented measures to comply with our SOPs relating to deadlines and control
activities related to our period-end closing and financial reporting processes.
Our efforts include following detailed closing schedules and checklists and
timely obtaining complete review and approval by management of all financial
close documentation and results. We anticipate that our updated controls will
be
tested and this deficiency will be remediated by June 30, 2007.
· We
had
not fully implemented the automated internal control capabilities in our ERP
system, including change management and control processes, incident management
and backup and recovery processes. We have implemented procedures to more
rigorously track changes and document and report incidents as they occur in
the
areas of change and incident management. We have moved support of our
financially material systems and servers to an outsourcer who will perform
qualified backup and recovery and provide appropriate attestation that the
controls are effective. We anticipate that the steps necessary to address this
deficiency will be fully implemented by March 31, 2007 and that our updated
controls will be tested and this deficiency will be remediated by June 30,
2007.
· We
did
not conduct annual performance reviews or evaluations of our management and
staff employees. We intend to perform appropriate reviews in 2007. We anticipate
that our updated procedures will be tested and this deficiency will be
remediated by December 31, 2007.
(2) We
did
not have a sufficient complement of personnel with appropriate training and
experience in GAAP, as evidenced by the following deficiencies:
· Our
former Chief Financial Officer functioned in that position through November
20,
2006 and retired on December 15, 2006. Our Audit Committee began transitioning
the Chief Financial Officer’s responsibilities to others starting on November
20, 2006 and ultimately delegated overall responsibility for accounting
functions and reporting to our Acting Chief Financial Officer. Our Audit
Committee also launched a recruitment effort in December 2006, and currently
has
a number of qualified candidates under evaluation for the Chief Financial
Officer position. Most qualified candidates are currently employed by other
public companies that are preparing annual reports. Accordingly, we do not
expect to complete the hiring of a new Chief Financial Officer until the second
quarter of 2007. We anticipate that this deficiency will be remediated by June
30, 2007.
· The
Controller position is currently open, and the Audit Committee and Executive
Management are evaluating candidates. Our Director of Financial Reporting is
currently filling the position as acting Controller, and a former Controller
is
reporting to him as acting Assistant Controller. We expect to fill the
Controller position within 60 days from the filing of this report and anticipate
that this deficiency will be remediated by June 30, 2007.
· We
believe that during 2006, and through December 31, 2006, the organization and
supervision of our accounting department were inappropriate to the scale of
our
activities. Under the direction of our Acting Chief Financial Officer and Audit
Committee, we have undertaken extensive training and reorganization of the
accounting staff and allocated significant additional resources to the
accounting department, including retaining additional contractors and
consultants. We anticipate that the steps necessary to address this deficiency
will be fully implemented and that this deficiency will be remediated by June
30, 2007.
· As
a
result of too few accounting staff members, a variety of tasks were not
completed on a timely basis. We continue to seek to hire qualified permanent
staff members and we have engaged contract staff members. We have added
personnel to our accounts payable and accounts receivable functions, our ethanol
sales order process and our commodity management and financial close and
reporting processes. We have added additional accounting staff members at our
Madera County, California plant site and we plan to hire additional accounting
staff members at all new plant sites as they come on-line. In addition, our
financial closings are performed in accordance with a scheduled checklist and
according to our financial controls. We anticipate that the steps necessary
to
address this deficiency will be fully implemented and that our updated controls
will be tested and this deficiency will be remediated by June 30,
2007.
(3) We
did
not adequately segregate the duties of different personnel within our accounting
group due to an insufficient complement of staff and inadequate management
oversight. Activities that were not adequately segregated included (a)
processing of payments and making modifications to payments prior to issuance,
and (b) payroll calculation and payroll processing. We are addressing these
segregation issues through revised desk procedures and management and staff
training. We anticipate that our updated controls will be tested and this
deficiency will be remediated by June 30, 2007.
(4) We
did
not perform adequate oversight of certain accounting functions and maintained
inadequate documentation of management review and approval of accounting
transactions and financial reporting processes. Our SOPs call for management
oversight in a wide variety of transactions and activities to help ensure:
(a)
accurate entry of inputs into our ERP system that are used to automatically
calculate amounts that are reported in our financial statements, (b) preparation
and distribution of financial information and reports to operational management
for review and approval, and (c) reconciliation of share-based payments. In
addition, our SOPs call for documentation of management oversight of a wide
variety of transactions and activities, including: (i) customer invoicing and
adjustments to customer invoices, (ii) period-end closing processes, (iii)
vendor invoices and payment processing, (iv) hedge effectiveness assessments
and
mark-to-market calculations, (v) payroll processing, and (vi) review of
supporting documentation, including resolution of material issues, related
to
statements and reports filed with the Securities and Exchange Commission.
Documentation is now created and maintained as part of management’s routine
review and approval process. We are also implementing appropriate management
oversight and approval activities in other areas. We anticipate that the steps
necessary to address this deficiency will be fully implemented and that our
updated controls will be tested and this deficiency will be remediated by June
30, 2007.
(5) We
did
not have adequate controls governing major account invoice processing and
payment. Our SOPs provide for a number of procedures to be followed before
cash
can be remitted to suppliers. These procedures were occasionally bypassed in
order to accelerate the payment by wire transfer of amounts owed to major
suppliers. We have addressed this deficiency by implementing revised procedures
that: (a) provide for all transactions to be processed through the ERP system,
(b) assure that the prescribed purchase order, receiving, invoice processing
and
payment approval processes are followed before payment is remitted to a
supplier, (c) restrict access to the recommended payment list within our ERP
system, and (d) reconcile all wire transfers as part of the daily bank account
reconciliation process. We anticipate that our updated controls will be tested
and this deficiency will be remediated by June 30, 2007.
(6) We
had
not fully implemented certain control activities and capabilities included
in
the design of our ERP system. Certain features of our ERP system are designed
to
automate accounting procedures and transaction processing, or to enforce
controls, including features that enforce proper authorization of credit memos.
We believe that we have fully implemented these features. We anticipate that
our
updated controls will be tested and this deficiency will be remediated by June
30, 2007.
(7) We
did
not have adequate access and data and formulaic integrity controls over critical
spreadsheets used in connection with accounting and financial reporting. Our
SOPs call for access and data and formulaic integrity controls over critical
spreadsheets used in connection with accounting and financial reporting. We
have
moved all spreadsheets that are used in our financial management and closing
processes to a secured, shared server with access granted to a limited number
of
management-approved personnel. We have also begun to set passwords at the
spreadsheet level to further limit access to critical information. We continue
to review and plan for formal processes to ensure qualified review and approval
of financial calculations and modifications to those calculations. We expect
to
revise our SOPs to enhance our internal controls in these regards. We expect
that the timing of these remediation efforts will be partly dependent on the
timing of our hiring of a Chief Financial Officer and a Controller. However,
we
anticipate that the steps necessary to address this deficiency will be fully
implemented by June 30, 2007 and that our updated controls will be tested and
this deficiency will be remediated by December 31, 2007.
The
above
material weaknesses did not result in adjustments to our 2006 consolidated
financial statements, however, it is reasonably possible that, if not
remediated, one or more of the material weaknesses could result in a material
misstatement in our reported financial statements that might result in a
material misstatement in a future annual or interim period.
Changes
in Internal Control over Financial Reporting
The
changes noted above, are the only changes during our most recently completed
fiscal quarter that have materially affected or are reasonably likely to
materially affect, our internal control over financial reporting, as defined
in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To
the
Board of Directors
Pacific
Ethanol, Inc.
Sacramento,
California
We
have audited management’s assessment, included in the accompanying Management’s
Report on Internal Control over Financial Reporting, that Pacific Ethanol,
Inc.’s (the “Company”) internal control over financial reporting was not
effective as of December 31, 2006, because of the effect of material
weaknesses described therein, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (the “COSO Framework”). The Company’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management’s
assessment and an opinion on the effectiveness of the Company’s internal control
over financial reporting based on our audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control
over
financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing
such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with accounting principles generally accepted in the United States of America.
A
company’s internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable
assurance that transactions are recorded as necessary to permit preparation
of
financial statements in accordance with accounting principles generally accepted
in the United States of America, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management
and
directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the company’s assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may
not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
A
material weakness is a significant control deficiency, or combination of
significant control deficiencies, that results in more than a remote likelihood
that a material misstatement of the annual or interim financial statements
will
not be prevented or detected. The following material weaknesses have been
identified and included in management’s assessment as of December 31,
2006:
| |
(1)
|
The
Company had not effectively implemented comprehensive entity-level
internal controls;
|
| |
(2)
|
The
Company did not have a sufficient complement of personnel with appropriate
training and experience in generally accepted accounting principles,
or
GAAP;
|
| |
(3)
|
The
Company did not adequately segregate the duties of different personnel
within its accounting group due to an insufficient complement of
staff;
|
| |
(4)
|
The
Company did not perform adequate oversight of certain accounting
functions
and maintained inadequate documentation of management review and
approval
of accounting transactions and financial reporting
processes;
|
| |
(5)
|
The
Company did not have adequate controls governing major account invoice
processing and payment;
|
| |
(6)
|
The
Company did not fully implement certain control activities and
capabilities included in the design of its enterprise resource platform,
or ERP system; and
|
| |
(7)
|
The
Company did not maintain adequate access and data and formulaic integrity
controls over critical spreadsheets used in connection with accounting
and
financial reporting.
|
We
have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements of Pacific Ethanol, Inc. and our report dated March 7, 2007 expressed
an unqualified opinion.
In
our opinion, management’s assessment that the Company did not maintain effective
internal control over financial reporting as of December 31, 2006 is fairly
stated, in all material respects, based on the COSO framework. Also, in our
opinion, because of the effect of the material weaknesses described above on
the
achievement of the objectives of the control criteria, the Company has not
maintained effective internal control over financial reporting as of
December 31, 2006, based on the COSO framework.
We
do not express an opinion or any other form of assurance on management’s
statements referring to new controls being implemented after December 31,
2006.
/s/
HEIN
& ASSOCIATES LLP
Irvine,
California
March
7,
2007
Item
9B. Other
Information.
None.
Item
10. Directors,
Executive Officers and Corporate Governance
The
information under the captions “Information about our Board of Directors, Board
Committees and Related Matters” and “Section 16(a) Beneficial Ownership
Reporting Compliance,” appearing in the Proxy Statement, is hereby incorporated
by reference.
The
information under the caption “Executive Compensation and Related Information,”
appearing in the Proxy Statement, is hereby incorporated by reference.
Item
12. Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The
information under the captions “Security Ownership of Certain Beneficial Owners
and Management” and “Equity Compensation Plan Information,” appearing in the
Proxy Statement, is hereby incorporated by reference.
Item
13. Certain
Relationships and Related Transactions, and Director
Independence
The
information under the captions “Certain Relationships and Related Transactions”
and “Information
about our Board of Directors, Board Committees and Related Matters—Director
Independence” appearing
in the Proxy Statement, is hereby incorporated by reference.
Item
14. Principal
Accounting Fees and Services
PART
IV
Item
15. Exhibits,
Financial Statement Schedules
(a)(1)
and (a)(2) Financial Statements and Financial Statement
Schedules
None.
(a)(3)
Exhibits
Reference
is made to the exhibits listed on the Index to Exhibits.
Index
to Financial Statements
|
Report
of Independent Registered Public Accounting Firm
|
F-2
|
| |
|
|
Consolidated
Balance Sheets as of December 31, 2006 and 2005
|
F-3
|
| |
|
|
Consolidated
Statements of Operations for the Years Ended December 31, 2006, 2005
and 2004
|
F-5
|
| |
|
|
Consolidated
Statements of Comprehensive Income (Loss) for the Years Ended
December 31, 2006, 2005 and 2004
|
F-6
|
| |
|
|
Consolidated
Statement of Stockholders’ Equity for the Years Ended December 31,
2006, 2005 and 2004
|
F-7
|
| |
|
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2006, 2005
and 2004
|
F-10
|
| |
|
|
Notes
to Consolidated Financial Statements
|
F-12
|
To
the
Board of Directors
Pacific
Ethanol, Inc.
Sacramento,
California
We
have audited the accompanying consolidated balance sheets of Pacific Ethanol,
Inc. as of December 31, 2006 and 2005 the related consolidated statements
of operations, comprehensive income (loss), stockholders’ equity, and cash flows
for the three year period ended December 31, 2006. These consolidated financial
statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audits to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall presentation of the financial statements. 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 Pacific
Ethanol, Inc. at December 31, 2006 and 2005, and the results of its
operations and its cash flows for three year period ended December 31, 2006,
in
conformity with accounting principles generally accepted in the United States
of
America.
We
also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of Pacific
Ethanol, Inc.’s internal control over financial reporting as of
December 31, 2006, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO) and our report dated March 7, 2007
expressed an unqualified opinion on management’s assessment of the effectiveness
of the Company’s internal control over financial reporting and an adverse
opinion on the effectiveness of the Company’s internal control over financial
reporting.
As
discussed in Note 11 to the consolidated financial statements, the Company
adopted the provisions of SEC Staff Accounting Bulletin No. 108,
Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements,
which resulted in a change in the manner in which the Company assesses the
impact of financial statement errors.
/s/
HEIN
& ASSOCIATES LLP
Irvine,
California
March
7,
2007
PACIFIC
ETHANOL, INC.
CONSOLIDATED
BALANCE SHEETS
(in
thousands)
| |
|
December
31,
|
|
|
ASSETS
|
|
2006
|
|
2005
|
|
| |
|
|
|
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
44,053
|
|
$
|
4,521
|
|
|
Investments
in marketable securities
|
|
|
39,119
|
|
|
2,750
|
|
|
Accounts
receivable, net (including $1,188 and $938 as
of
December 31, 2006 and 2005,
respectively,
from a related party)
|
|
|
29,322
|
|
|
4,948
|
|
|
Restricted
cash
|
|
|
1,567
|
|
|
—
|
|
|
Notes
receivable - related party
|
|
|
—
|
|
|
136
|
|
|
Inventories
|
|
|
7,595
|
|
|
363
|
|
|
Prepaid
expenses
|
|
|
1,053
|
|
|
627
|
|
|
Prepaid
inventory
|
|
|
2,029
|
|
|
1,349
|
|
|
Other
current assets
|
|
|
2,307
|
|
|
86
|
|
|
Total
current assets
|
|
|
127,045
|
|
|
14,780
|
|
|
Property
and Equipment, Net
|
|
|
196,156
|
|
|
23,208
|
|
|
Other
Assets:
|
|
|
|
|
|
|
|
|
Restricted
cash
|
|
|
24,851
|
|
|
—
|
|
|
Deposits
and advances
|
|
|
9,040
|
|
|
14
|
|
|
Goodwill
|
|
|
85,307
|
|
|
2,566
|
|
|
Intangible
assets, net
|
|
|
10,155
|
|
|
7,569
|
|
|
Other
assets
|
|
|
1,266
|
|
|
48
|
|
|
Total
other assets
|
|
|
130,619
|
|
|
10,197
|
|
|
Total
Assets
|
|
$
|
453,820
|
|
$
|
48,185
|
|
The
accompanying notes are an integral part of these
consolidated financial statements.
PACIFIC
ETHANOL, INC.
CONSOLIDATED
BALANCE SHEETS
(in
thousands, except par value)
| |
|
December
31,
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
2006
|
|
2005
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
Current
portion - related party note payable
|
|
$
|
—
|
|
$
|
1,200
|
|
|
Current
portion - notes payable
|
|
|
4,125
|
|
|
—
|
|
|
Accounts
payable - trade
|
|
|
11,483
|
|
|
4,755
|
|
|
Accounts
payable - related party
|
|
|
3,884
|
|
|
6,412
|
|
|
Accrued
retention - related party
|
|
|
5,538
|
|
|
1,450
|
|
|
Accrued
payroll
|
|
|
|
