UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
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,
2007
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OR
¨
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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
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41-2170618
|
(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification No.)
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400
Capitol Mall, Suite 2060, Sacramento, California
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95814
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(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, $0.001 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, or a smaller reporting company.
See the definitions of “large accelerated filer,” “accelerated filer” and
“smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filer ¨
|
Accelerated
filer x
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Non-accelerated
filer ¨ (Do not check if
a smaller reporting company)
|
Smaller
reporting company ¨
|
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 $475.0 million as of June 29, 2007, 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, $0.001 par value, outstanding
as of March 24, 2008 was 40,674,464.
DOCUMENTS
INCORPORATED BY REFERENCE:
Part III
incorporates by reference certain information from the registrant’s proxy
statement (the “Proxy Statement”) for the 2008 Annual Meeting of Stockholders to
be filed on or before April 30, 2008.
TABLE
OF CONTENTS
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Page
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PART
I
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Item
1.
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Business
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1
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Item
1A.
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Risk
Factors.
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13
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Item
1B.
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Unresolved
Staff Comments.
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23
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Item
2.
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Properties.
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24
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Item
3.
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Legal
Proceedings.
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24
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Item
4.
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Submission
of Matters to a Vote of Security Holders.
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26
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PART
II
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Item
5.
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Market
For Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.
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26
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Item
6.
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Selected
Financial Data.
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29
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Item
7.
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Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
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30
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Item
7A.
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Quantitative
and Qualitative Disclosures About Market Risk.
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34
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Item
8.
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Financial
Statements and Supplementary Data.
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51
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Item
9.
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Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure.
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51
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Item
9A.
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Controls
and Procedures
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51
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Item
9A(T)
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Controls
and Procedures
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57
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Item
9B.
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Other
Information.
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38
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PART
III
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Item
10.
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Directors,
Executive Officers and Corporate Governance
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57
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Item
11.
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Executive
Compensation
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57
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Item
12.
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
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57
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Item
13.
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Certain
Relationships and Related Transactions, and Director
Independence
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57
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Item
14.
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Principal
Accounting Fees and Services
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57
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PART
IV
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Item
15.
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Exhibits,
Financial Statement Schedules
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57
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Index
to Financial Statements
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F-1
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Index
to Exhibits
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Signatures
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Exhibits
Filed With This Report
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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
Overview
Our
primary goal is to be the leading marketer and producer of low carbon 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, Oregon, Colorado and
Idaho. We have extensive customer relationships throughout the Western United
States and extensive supplier relationships throughout the Western and
Midwestern United States.
Our
customers are integrated oil companies and gasoline marketers who blend ethanol
into gasoline. We supply ethanol to our customers either from our own ethanol
production facilities located within the regions we serve, or with ethanol
procured in bulk from other producers. In some cases, we have marketing
agreements with ethanol producers to market all of the output of their
facilities. Additionally, we have customers who purchase our co-products for
animal feed and other uses.
We own
and operate two ethanol production facilities located in Madera, California and
Boardman, Oregon. Our Madera facility has an annual production capacity of up to
40 million gallons and has been in operation since October 2006. Our Boardman
facility has an annual production capacity of up to 40 million gallons and has
been in operation since September 2007. In addition, we own a 42% interest in
Front Range Energy, LLC, or Front Range, which owns and operates an ethanol
production facility with annual production capacity of up to 50 million gallons
in Windsor, Colorado. We have two additional ethanol production facilities under
construction, in Burley, Idaho and Stockton, California, which are expected to
commence operations in the second and third quarters of 2008, respectively. We
also intend to either construct or acquire additional ethanol production
facilities as financial resources and business prospects make the construction
or acquisition of these facilities advisable. See “—Production
Facilities.”
Total
annual gasoline consumption in the United States is approximately 140 billion
gallons. Total annual ethanol consumption represented less than 5% of this
amount in 2007. We believe that the domestic ethanol industry has substantial
potential for growth to initially 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 annually and thereafter up to 36
billion gallons of ethanol annually under the new national Renewable Fuel
Standards, or RFS, by 2022. See “—Governmental Regulation.”
We intend
to reach our goal to be the leading marketer and producer of low carbon
renewable fuels in the Western United States in part by expanding our
relationships with customers and third-party ethanol producers to market higher
volumes of ethanol, by 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 by 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
transportation fuel. In addition, we intend to expand our annual production
capacity to 220 million gallons in 2008, upon completion of our facilities in
Burley, Idaho and Stockton, California, and to 420 million gallons of annual
production capacity in 2010, through new construction or acquisition of
additional ethanol production facilities. We also intend to expand
our distribution infrastructure by increasing 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. 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 extensive business relationships with our customers and suppliers. In
particular, we have developed extensive 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 extensive 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 competitive advantages, including
transportation cost, delivery timing and logistical advantages as well as 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. In
addition to Mr. Koehler, we have seasoned managers with many years of experience
in the ethanol, fuel, energy, construction and feed industries, leading our
various departments. 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 market as well as ethanol that we
produce.
Business
and Growth Strategy
Our
primary goal is to be the leading marketer and producer of low carbon 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 increasing 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 annual production
capacity to 220 million gallons in 2008, upon completion of our facilities under
construction in Burley and Stockton and to 420 million gallons of annual
production capacity in 2010 through new construction or acquisition of
additional ethanol production facilities.
· 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:
o
|
Locations
near fuel blending facilities will enable lower ethanol transportation
costs and enjoy timing and logistical advantages over competing locations
which require ethanol to be shipped over much longer
distances.
|
o
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Locations
adjacent to major rail lines will enable the efficient delivery of corn in
large unit trains from major corn-producing
regions.
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o
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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 new 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. On
January 29, 2008, the Department of Energy included us in a matching award of
$24.3 million to build the first cellulosic ethanol demonstration plant in the
Northwest United States.
· 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 through fixed-price contracts
with our suppliers, as well as, entering into derivative instruments to fix or
establish a range of corn and natural gas prices. To mitigate ethanol inventory
price risks, we may sell a portion of our production forward under fixed- or
index-price contracts, or both. We may hedge a portion of the price risks
associated with index-price 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 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
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 before
blending. In addition, ethanol is commonly added to finished regular grade
gasoline as a means of producing higher octane mid-grade and premium
gasoline.
· Renewable fuels. Ethanol is
blended with gasoline in order to enable gasoline refiners to comply with a
variety of governmental programs, in particular, the national RFS designed to
promote alternatives to fossil fuels. See “—Governmental
Regulation.”
· 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 is done for the purpose of extending the volume of
fuel sold at the gasoline pump. Furthermore, conditions in Brazil, where ethanol
accounts for 40% of all vehicle fuels and is sold in blends with gasoline
ranging from 25% to 100%, suggest that ethanol could capture a much greater
portion of the United States market in the future.
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 Independence and Security Act of 2007, which was signed
into law in December 2007, significantly increased the prior national RFS. The
prior national RFS mandated the use of 5.4 billion gallons of renewable fuels in
2008, which was to rise incrementally and peak at 7.5 billion gallons by 2012.
The new national RFS significantly increases the mandated use of renewable fuels
to 9.0 billion gallons in 2008, which is to rise incrementally and peak at 36.0
billion gallons by 2022. The new national RFS mandates for renewable fuel use
increase each year, with corn-based or “conventional” ethanol reaching a peak of
15.0 billion gallons by 2015. Beginning in 2016, increases in the new national
RFS targets must be met with advanced biofuels, defined as cellulosic ethanol
and other biofuels derived from feedstock other than corn starch. We believe
that these increases will bolster demand for ethanol.
In
January 2007, California’s Governor signed an executive order directing the
California Air Resource Board 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 2020. The State of Oregon implemented a state-wide renewable
fuels standard effective January 2008. This standard requires a 10% ethanol
blend in every gallon of gasoline and is expected to cause the use of
approximately 160 million gallons of ethanol per year in Oregon.
We
believe that the domestic ethanol industry produced approximately 6.5 billion
gallons of ethanol in 2007, an increase of approximately 33% from the
approximately 4.9 billion gallons of ethanol produced in 2006. We believe that
the ethanol market in California alone consumed approximately 1.0 billion
gallons in 2007, representing approximately 15% of the national market. However,
the Western United States has relatively few ethanol plants and local ethanol
production levels are substantially below the local 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 represented less than 5% of this
amount in 2007. We believe that the domestic ethanol industry has substantial
potential for growth to initially 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 annually and thereafter up to 36
billion gallons of ethanol annually required under the new national RFS by
2022.
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 demand depending on the preferences
of petroleum refiners and state policies. See “Risk Factors.”
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 WDG 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 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
2007, 2006 and 2005, we produced or purchased from third parties and resold an
aggregate of approximately 191 million, 102 million and 67 million gallons of
fuel-grade ethanol to approximately 61 customers, 60 customers and 27 customers,
respectively. Sales to our two largest customers in 2007 represented
approximately 32% of our net sales. Sales to our two largest customers in 2006
represented approximately 25% of our net sales. Sales to our three largest
customers in 2005 represented approximately 39% of our net sales. Customers who
accounted for 10% or more of our net sales in 2007 were Chevron Products USA and
Valero Marketing. 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. Sales to each of our other customers
represented less than 10% of our net sales in each of 2007, 2006 and
2005.
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 higher margins. 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 endeavor 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 other feed
ingredients. We expect to be one of the few WDG producers with production
facilities located in the Western United States and we primarily sell our WDG to
dairy farmers in close proximity to our ethanol production
facilities.
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 intend to expand to support the continuing growth of our
business.
During
2007, 2006 and 2005, we purchased an aggregate of approximately 99 million, 88
million and 67 million gallons of fuel-grade ethanol from approximately 33
suppliers, 22 suppliers and 15 suppliers, respectively. Purchases from our four
largest ethanol suppliers in 2007 represented approximately 68% of our total
ethanol purchases. Purchases from our three largest ethanol suppliers in 2006
represented approximately 50% of our total ethanol purchases. Purchases from our
three largest ethanol suppliers in 2005 represented approximately 59% of our
total ethanol purchases. Purchases from each of our other suppliers represented
less than 10% of total ethanol purchases in 2007, 2006 and 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 cheaply and reliably truck 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 on 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 of our existing ethanol production facilities and our
facilities under construction.
|
|
|
|
|
|
|
|
|
|
Location
|
Madera,
CA
|
|
Windsor,
CO
|
|
Boardman,
OR
|
|
Burley,
ID
|
|
Stockton,
CA
|
Quarter/Year
completed or scheduled to be completed
|
4th
Qtr., 2006
|
|
2nd
Qtr., 2006
|
|
3rd
Qtr., 2007
|
|
2nd
Qtr., 2008
|
|
3rd
Qtr., 2008
|
Annual
design basis ethanol production capacity (in millions of
gallons)
|
35
|
|
40
|
|
35
|
|
50
|
|
50
|
Approximate
maximum annual ethanol production capacity (in millions of
gallons)
|
40
|
|
50
|
|
40
|
|
60
|
|
60
|
Ownership
|
100%
|
|
42%
|
|
100%
|
|
100%
|
|
100%
|
Primary
energy source
|
Natural
Gas
|
|
Natural
Gas
|
|
Natural
Gas
|
|
Natural
Gas
|
|
Natural
Gas
|
Estimated
annual WDG production capacity (in thousands of tons)
|
293
|
|
335
|
|
293
|
|
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 in 2008 upon completion of our facilities in Burley and Stockton and to
420 million gallons of annual production capacity in 2010, through new
construction or acquisition of additional ethanol production facilities. In
2007, we began development of an ethanol production facility in the Imperial
Valley near Calipatria, California; however, construction has been suspended
until market conditions improve and we are able to obtain adequate financing. 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 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, a subsidiary of 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 production capacity of up
to 50 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 17% of total United States ethanol production
in 2007. According to the RFA, there are approximately 134 ethanol plants
currently operating with a combined annual production capacity of approximately
7.2 billion gallons. In addition, we believe that approximately 50 new ethanol
plants or expansions of existing plants are currently under construction with an
estimated combined future annual production capacity of approximately 4.4
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 extensive
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 not be realized.
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
Environmental Protection Agency, or 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 facility, 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 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. The RFG program accounts for
about 30% of nationwide gasoline consumption. California refiners blend a
minimum of 2.0% oxygen by weight, which is the equivalent of 5.7% ethanol in
every gallon of gasoline, or roughly 1.0 billion gallons of ethanol per year in
California alone.
National
Energy Legislation
In
addition, the Energy Independence and Security Act of 2007, which was signed
into law in December 2007, significantly increased the prior national RFS. The
prior national RFS mandated the use of 5.4 billion gallons of renewable fuels in
2008, which was to rise incrementally and peak at 7.5 billion gallons by 2012.
The new national RFS significantly increases the mandated use of renewable fuels
to 9.0 billion gallons in 2008, which is to rise incrementally and peak at 36.0
billion gallons by 2022. The new national RFS mandates for renewable fuel use
increase each year, with corn-based or “conventional” ethanol reaching a peak of
15.0 billion gallons by 2015. Beginning in 2016, increases in the new national
RFS targets must be met with advanced biofuels, defined as cellulosic ethanol
and other biofuels derived from feedstock other than corn starch.
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.
In
January 2007, California’s Governor signed an executive order directing the
California Air Resource Board 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 2020.
The State
of Oregon implemented a state-wide renewable fuels standard effective January
2008. This standard requires a 10% ethanol blend in every gallon of gasoline and
is expected to cause the use of approximately 160 million gallons of ethanol per
year in Oregon.
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 California Air Resources
Board. 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 24, 2008, we employed approximately 220 persons on a full-time basis,
including through our subsidiaries. We believe that our employees are
highly-skilled, and our success will depend in part upon our ability to retain
our 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 significant losses and negative operating cash flow in the past
and we may incur significant losses and negative operating cash flow in the
future. Continued losses and negative operating cash flow may hamper our
operations and prevent us from expanding our business.
We have
incurred significant losses and negative operating cash flow in the past. For
the years ended December 31, 2007, 2006 and 2005, we incurred net losses of
approximately $14.4 million, $142,000 and $9.9 million, respectively. For the
year ended December 31, 2006, we incurred negative operating cash flow of
approximately $8.1 million. We expect to rely on cash on hand, cash, if any,
generated from our operations and cash, if any, generated from our future
financing activities to fund all of the cash requirements of our business.
Continued losses and negative operating cash flow may hamper our operations and
prevent us from expanding our business. Continued losses and negative operating
cash flow are also likely to make our capital raising needs more acute while
limiting our ability to raise additional financing on satisfactory
terms.
Various
factors could result in inadequate working capital to fully fund our operations
or meet our capital expenditure requirements, or both.
If
ethanol production margins deteriorate from current levels, if we experience
additional cost overruns at our ethanol production facilities under
construction, if our capital requirements or cash flows otherwise vary
materially and adversely from our current projections, or if other adverse
unforeseen circumstances occur, our working capital may be inadequate to fully
fund our operations or meet our capital expenditure requirements, or both, which
may have a material adverse effect on our results of operations, liquidity and
cash flows and may restrict our growth and hinder our ability to
compete.
We
are seeking additional financing and may be unable to obtain this financing on a
timely basis, in sufficient amounts, on terms acceptable to us or at all. Any
financing we are able to obtain may require us to accept financing on burdensome
terms that may cause significant dilution to our stockholders and impose onerous
financial restrictions on our business.
We are
seeking substantial additional financing. Deteriorating global economic and debt
and equity market conditions may cause prolonged declines in lender and investor
confidence in and accessibility to capital markets. Future financing may not be
available on a timely basis, in sufficient amounts, on terms acceptable to us or
at all. Any equity financing may cause significant dilution to existing
stockholders. Any debt financing or other financing of securities senior to our
common stock will likely include financial and other covenants that will
restrict our flexibility. At a minimum, we expect these covenants to include
restrictions on our ability to pay dividends on our common stock. Any failure to
comply with these covenants could have a material adverse effect on our
business, prospects, financial condition and results of operations because we
could lose any then-existing sources of financing and our ability to secure new
financing may be impaired. In addition, any prospective debt or equity financing
transaction will be subject to the negotiation of definitive documents and any
closing under those documents will be subject to the satisfaction of numerous
conditions, many of which could be beyond our control. We may be unable to
obtain additional financing from one or more lenders or equity investors, or if
funding is available, it may be available only on burdensome terms that may
cause significant dilution to our stockholders and impose onerous financial
restrictions on our business.
Increased
ethanol production may cause a decline in ethanol prices or prevent ethanol
prices from rising, and may have other negative effects, adversely impacting our
results of operations, cash flows and financial condition.
We
believe that the most significant factor influencing the price of ethanol has
been the substantial increase in ethanol production in recent years. Domestic
ethanol production capacity has increased steadily from an annualized rate of
1.7 billion gallons per year in January 1999 to 7.2 billion gallons per year
according to the RFA. In addition, we believe that a significant amount of
ethanol production capacity—approximately 4.4 billion gallons per year—is
currently under construction. This production capacity is being added to address
anticipated increases in demand, including from increased volume requirements
under the Energy Independence and Security Act of 2007. See
“Business—Governmental Regulation.” However, increases in the demand for ethanol
may not be commensurate with increases in the supply of ethanol, thus leading to
lower ethanol prices. Demand for ethanol 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. Increased ethanol production could also have other
adverse effects. For example, increased ethanol production could lead to
increased supplies of co-products generated from ethanol production, such as
WDG. Those increased supplies could lead to lower prices for those co-products.
Also, increased ethanol production could result in increased demand for corn.
Increased demand for corn could cause higher corn prices, resulting in higher
ethanol production costs and lower profit margins. We believe that significantly
higher corn prices and lower profit margins throughout 2007 were predominantly
caused by increased demand for corn resulting from increased ethanol production.
Accordingly, increased ethanol production may cause a decline in ethanol prices
or prevent ethanol prices from rising, and may have other negative effects,
adversely impacting our results of operations, cash flows and financial
condition.
The
raw materials and energy necessary to produce ethanol may be unavailable or may
increase in price, adversely affecting our business, results of operations and
financial condition.
The
principal raw material we use to produce ethanol and its co-products is corn.
Changes in the price of corn can significantly affect our business. In general,
rising corn prices result in 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 prices to our customers
because the price of ethanol is primarily determined by other factors, such as
the supply of ethanol and the price of oil and gasoline. At certain levels, corn
prices may even make ethanol production uneconomical depending on the prevailing
price of ethanol.
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 supply and demand. 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. Average corn prices as measured by the
Chicago Board of Trade increased 44% from 2006 to 2007. The United States
Department of Agriculture’s December 2007 crop report estimated that corn bought
by ethanol plants will represent approximately 22% of the 2007/2008 crop year’s
total corn supply, up from 17% in the prior crop year. We believe that
significantly higher corn costs and lower profit margins throughout 2007 were
substantially caused by increased demand for corn resulting from increased
ethanol production. Additional increases in ethanol production could further
boost demand for corn and result in further increases in corn
prices.
Our
business also depends on the continuing availability of rail, road, port,
storage and distribution infrastructure. In particular, due to limited storage
capacity at our production facilities and other considerations related to
production efficiencies, we depend on just-in-time delivery of corn. The
production of ethanol also requires a significant and uninterrupted supply of
other raw materials and energy, primarily 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 those
resources on acceptable terms. Any disruptions in the ethanol production
infrastructure network, whether caused by labor difficulties, earthquakes,
storms, other natural disasters or human error or malfeasance or other reasons,
could prevent timely deliveries of corn or other raw materials and energy and
may require us to halt production which could have a material adverse effect on
our business, results of operations and financial condition.
Numerous
factors may prevent us from implementing our planned expansion
strategy.
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 substantial additional financing to achieve our business objectives and we
may not have access to the funding required for the expansion of our business or
funding may not be available to us on acceptable terms. We plan to fund the
expansion of our business with additional debt and equity financing. 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 we are initially using
our existing cash to implement this strategy based on the belief that we can
secure additional debt and equity financing in the future in order to complete
our expansion. If we are unable to secure this debt and equity financing, we may
suffer from an acute 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 affected.
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 condition. 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 do not have
any fixed-price construction contracts and we have experienced significant
cost-overruns in the past and may experience additional cost-overruns in the
future. 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 at our
facilities as expected.
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
engage in hedging transactions and other risk mitigation strategies that could
harm our results of operations.
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. In addition, we 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. We also engage in hedging transactions involving
interest rate swaps related to our debt financing activities, the financial
statement impact of which is dependent upon, among other things, fluctuations in
prevailing interest rates. 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 for
a physical commodity is often settled in the same time frame as the physical
commodity is either purchased or sold. Certain 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 from time to time 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 fluctuations in the price of corn, natural
gas, ethanol, unleaded gasoline and prevailing interest rates.
The
market price of ethanol is volatile and subject to large fluctuations, which may
cause our profitability or losses to fluctuate significantly.
The
market price of ethanol is volatile and subject to large fluctuations. The
market price of ethanol is dependent upon many factors, including the supply of
ethanol and the price of gasoline, which is in turn dependent upon the price of
petroleum which is highly volatile and difficult to forecast. For example, our
average sales price of ethanol in 2007 declined by approximately 6% from our
2006 average sales price per gallon, but increased 37% in 2006 from our 2005
average sales price per gallon. Fluctuations in the market price of ethanol may
cause our profitability or losses to fluctuate significantly.
We
have identified two 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 two material weaknesses in our
internal control over financial reporting that existed as of December 31,
2007: (i) we did not have adequate internal control over our accrual
of construction-related costs for our ethanol production facilities; and (ii) we
did not exercise oversight of our personnel or their actions in a manner
reasonably calculated to ensure compliance under the Credit Agreement governing
our credit facility. See “Controls and Procedures.”
Our
management, including our Chief Executive Officer and Chief Financial Officer,
does not expect that our internal control over financial reporting will prevent
all errors 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.
Operational
difficulties at our production facilities could negatively impact our sales
volumes and could cause us to incur substantial losses.
Our
operations are subject to labor disruptions, unscheduled downtime and other
operational hazards inherent in our industry, such as equipment failures, fires,
explosions, abnormal pressures, blowouts, pipeline ruptures, transportation
accidents and natural disasters. Some of these operational hazards may cause
personal injury or loss of life, severe damage to or destruction of property and
equipment or environmental damage, and may result in suspension of operations
and the imposition of civil or criminal penalties. Our insurance may not be
adequate to fully cover the potential operational hazards described above or we
may not be able to renew this insurance on commercially reasonable terms or at
all.
Moreover,
our plants may not operate as planned or expected. All of our plants are
designed to operate at or above a certain production capacity. The operation of
our plants is and will be, however, subject to various uncertainties. As a
result, our plants may not produce ethanol and WDG at the levels we expect. In
the event any of our plants do not run at their expected capacity levels, our
business, results of operations and financial condition may be materially and
adversely affected.
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 have a material adverse effect on 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
or repeal of the national RFS minimum levels of renewable fuels included in
gasoline could have a material adverse affect on our results of
operations.
Shortly
after passage of the Energy Independence and Security Act of 2007, which
increased the minimum mandated required usage of ethanol, a Congressional
sub-committee held hearings on the potential impact of the new national RFS on
commodity prices. While no action was taken by the sub-committee towards repeal
of the new national RFS, any attempt by Congress to re-visit, repeal or grant
waivers of the new national RFS could adversely affect demand for ethanol and
could have a material adverse effect on our results of operations and financial
condition.
While
the Energy Independence and Security Act of 2007 imposes the national RFS, it
does not mandate only the use of ethanol.
The
Energy Independence and Security Act of 2007 imposes the national RFS, but does
not mandate only the use of ethanol. While the RFA expects that
ethanol should account for the largest share of renewable fuels produced and
consumed under the national RFS, the national RFS is not limited to ethanol and
also includes biodiesel and any other liquid fuel produced from biomass or
biogas.
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.
We also
face increasing competition from international suppliers. 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 condition.
In
addition, some of our suppliers are potential competitors and, especially if the
price of ethanol reaches 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 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.
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 likely materially and adversely affect
our sales and profitability.
We
produce and sell our own ethanol but also depend on a small number of
third-party suppliers for a significant portion of the ethanol that we sell. If
any of these suppliers does not 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
produce and sell our own ethanol but also depend on a small number of
third-party suppliers for a significant portion of the ethanol that we sell. Our
largest third-party ethanol suppliers, each of whom accounted for 10% or more of
total ethanol purchases, represented approximately 68% and 50% of the total
ethanol we purchased during 2007 and 2006, respectively. We expect to continue
to depend for the foreseeable future upon a small number of third-party
suppliers for a significant portion of the ethanol that we sell. Our third-party
suppliers are primarily located in the Midwestern United States. The delivery of
ethanol from these suppliers 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 our customers.
If this occurs, our sales, 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
condition.
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 condition.
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
2007, sales to our two largest customers, each of whom accounted for 10% or more
of total net sales, represented an aggregate of approximately 32% of our total
net sales. 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. 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
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 24, 2008, we had outstanding approximately 40.7 million shares of our
common stock. Approximately 7.1 million of these shares were restricted under
the Securities Act of 1933, or Securities Act, including approximately 4.7
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 33.6 million shares.
We have
registered for resale a substantial number of shares of our common stock,
including approximately 10.6 million shares of our common stock underlying our
Series A Preferred Stock. The holder of these shares is 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, or
in 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. and our issuance of Series B Preferred Stock to Lyles United,
LLC, our common stockholders may experience numerous negative effects and most
of the rights of our common stockholders will be subordinate to the rights of
the holders of our preferred stock.
As a
result of our issuance of shares of Series A Preferred Stock to Cascade
Investment, L.L.C. and our issuance of Series B Preferred Stock to Lyles United,
LLC, our common stockholders may experience numerous negative effects, including
dilution from dividends paid in preferred stock and certain antidilution
adjustments. In addition, rights in favor of the holders of our preferred stock
include: seniority in liquidation and dividend preferences; substantial voting
rights; numerous protective provisions; as to the holder of our Series A
Preferred Stock, 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, our outstanding
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 Investment,
L.L.C. has approximately 19% and Lyles United, LLC has approximately 13% of all
outstanding voting power as compared to approximately 8% of all outstanding
voting power held in aggregate by our current executive officers and directors.
Also, in the event that we are profitable, our preferred stock would likewise
result in a decrease in our diluted earnings per share by an aggregate of
approximately 31%, without taking into account cash or stock payable as
dividends on our preferred stock. 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 have a material adverse effect on 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 10,000
square foot office leased for approximately five years. We also rent, under a
two-year lease, an office in Fresno, California, consisting of 2,000 square feet
and, under a five-year lease, an office in Portland, Oregon, consisting of 3,500
square feet.
Our
completed ethanol production facilities are located in Madera, California, at
which a 137 acre facility is located, Boardman, Oregon, at which a 25 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 have acquired sites or options with respect to sites for three
other potential ethanol production facilities that we may develop, or which are
currently under development or construction, including sites at Burley, Idaho
and Stockton, California. See “Business—Production Facilities.”
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 our
predecessor, Accessity Corp., or 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 based 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, or the Order, on the grounds that,
among other things, Mr. Spiegel failed to bring his claims as a derivative
action.
On
February 9, 2007, Mr. Spiegel filed an amended complaint which purported 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. On June 19, 2007, we filed a motion to dismiss the
amended complaint. The Court denied the motion to dismiss the amended complaint
by order dated July 31, 2007. Mr. Spiegel, however, voluntarily dismissed
without prejudice the case against us on August 27, 2007, and therefore we are
no longer a party to the state action.
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
Rule 14a-9 promulgated thereunder, (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 then sought to stay his own federal case, but the Motion
was denied on July 17, 2007. Mr. Spiegel filed his reply to our Motion to
Dismiss and that Motion remains pending. We intend to vigorously defend the
Federal Court Action.
Mercator
Group, LLC
In 2003,
Accessity filed a lawsuit seeking damages in excess of $100 million against: (i)
Presidion Corporation, f/k/a MediaBus Networks, Inc., the parent corporation of
Presidion Solutions, Inc., or Presidion, (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 Accessity and Presidion. In 2004, Accessity dismissed this
lawsuit without prejudice, which was filed in Florida state court. In January
2005, Accessity refiled this action in the State of California, for a similar
amount, as Accessity believed that this was 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 had been scheduled to
commence in July 2007. In April 2007, the arbitration proceedings were suspended
due to non-payment of arbitration fees by Presidion and Taurus. As a result of
non-payment of arbitration fees, a default order was entered against Taurus by
the Los Angeles Superior Court. In July, 2007, we entered into a confidential
settlement agreement with Presidion and its former officers. On July 23, 2007,
we dismissed Presidion from the arbitration. On July 23, 2007, Taurus filed a
Voluntary Petition for Chapter 7 Bankruptcy in the United States District Court,
Central District of California, Case Number SV07-12547 GM. The arbitration
hearings against Mercator began on February 11, 2008 and concluded on February
19, 2008. After the hearings concluded but prior to an award being issued, the
parties engaged in a two day mediation. As a result of the mediation, the
parties entered into a confidential settlement agreement. 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.
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, 2007:
|
|
|
|
|
|
|
First
Quarter (January 1 – March 31)
|
|
$ |
17.85 |
|
|
$ |
14.22 |
|
Second
Quarter (April 1 – June 30)
|
|
$ |
16.50 |
|
|
$ |
12.25 |
|
Third
Quarter (July 1 – September 30)
|
|
$ |
14.86 |
|
|
$ |
8.58 |
|
Fourth
Quarter (October 1 – December 31)
|
|
$ |
9.46 |
|
|
$ |
4.22 |
|
|
|
|
|
|
|
|
|
|
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 24, 2008, we had 40,674,464 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 24, 2008, the closing
sale price of our common stock on the Nasdaq Global Market was $4.94 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, 2007.
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 “Business—Company History.”
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 $100 on December 31, 2002.
|
Cumulative
Total Return ($)
|
|
12/02
|
12/03
|
12/04
|
3/23/05
|
12/05
|
12/06
|
12/07
|
PACIFIC
ETHANOL, INC.
|
100.00
|
151.61
|
382.58
|
583.87
|
698.06
|
992.90
|
529.68
|
THE
NASDAQ STOCK MARKET (U.S.) INDEX
|
100.00
|
149.75
|
164.64
|
155.75
|
168.60
|
187.83
|
205.22
|
SIC
2860—INDUSTRIAL ORGANIC CHEMICALS
|
100.00
|
117.59
|
148.52
|
139.73
|
123.21
|
180.97
|
144.37
|
Dividend
Policy
We have
never paid cash dividends on our common stock and do not intend to pay cash
dividends on our common stock in the foreseeable future. We 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
None.
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers
We have
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 their respective grant dates by and between us and those
employees and directors. Since October 4, 2006, we have granted an aggregate of
869,239 shares of restricted stock, net of deemed repurchases and cancellations,
to our employees and directors, of which an aggregate of 421,145 shares of
restricted stock had vested as of December 31, 2007. 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, during the fourth
quarter of 2007, we withheld an aggregate of 17,464 shares of our common stock
and remitted a cash payment to cover the minimum withholding tax amounts,
thereby effectively repurchasing from the employees the 17,464 shares of common
stock at a deemed purchase price equal to $9.30 per share for an aggregate
purchase price of $162,415.
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, 2007, 2006 and 2005 and the consolidated
balance sheet data at December 31, 2007 and 2006 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.
|
|
Years
Ended December 31,
|
|
|
|
2007 |
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(in
thousands, except per share data)
|
|
Consolidated
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
sales
|
|
$ |
461,513 |
|
|
$ |
226,356 |
|
|
$ |
87,599 |
|
|
$ |
20 |
|
|
$ |
1,017 |
|
Cost
of goods sold
|
|
|
428,614 |
|
|
|
201,527 |
|
|
|
84,444 |
|
|
|
13 |
|
|
|
946 |
|
Gross
profit
|
|
|
32,899 |
|
|
|
24,829 |
|
|
|
3,155 |
|
|
|
7 |
|
|
|
71 |
|
Selling,
general and administrative expenses
|
|
|
30,822 |
|
|
|
24,641 |
|
|
|
12,638 |
|
|
|
2,277 |
|
|
|
648 |
|
Income
(loss) from operations
|
|
|
2,077 |
|
|
|
188 |
|
|
|
(9,483 |
) |
|
|
(2,270 |
) |
|
|
(577 |
) |
Other
income (expense), net
|
|
|
(6,801 |
) |
|
|
3,426 |
|
|
|
(440 |
) |
|
|
(532 |
) |
|
|
(282 |
) |
Income
(loss) before provision for income taxes and noncontrolling interest in
variable interest entity
|
|
|
(4,724 |
) |
|
|
3,614 |
|
|
|
(9,923 |
) |
|
|
(2,802 |
) |
|
|
(859 |
) |
Provision
for income taxes
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Income
(loss) before noncontrolling interest in variable interest
entity
|
|
|
(4,724 |
) |
|
|
3,614 |
|
|
|
(9,923 |
) |
|
|
(2,802 |
) |
|
|
(859 |
) |
Noncontrolling
interest in variable interest entity
|
|
|
(9,676 |
) |
|
|
(3,756 |
) |
|
|
— |
|
|
|
—
|
|
|
|
— |
|
Net
loss
|
|
$ |
(14,400 |
) |
|
$ |
(142 |
) |
|
$ |
(9,923 |
) |
|
$ |
(2,802 |
) |
|
$ |
(859 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock dividends
|
|
$ |
(4,200 |
) |
|
$ |
(2,998 |
) |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Deemed
dividend on preferred stock
|
|
|
(28 |
) |
|
|
(84,000 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Loss
available to common stockholders
|
|
$ |
(18,628 |
) |
|
$ |
(87,140 |
) |
|
$ |
(9,923 |
) |
|
$ |
(2,802 |
) |
|
$ |
(859 |
) |
Loss
per share, basic and diluted
|
|
$ |
(0.47 |
) |
|
$ |
(2.50 |
) |
|
$ |
(0.40 |
) |
|
$ |
(0.23 |
) |
|
$ |
(0.07 |
) |
Weighted-average
shares outstanding, basic and diluted
|
|
|
39,895 |
|
|
|
34,855 |
|
|
|
25,066 |
|
|
|
12,397
|
|
|
|
11,733
|
|
Consolidated
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
5,707 |
|
|
$ |
44,053 |
|
|
$ |
4,521 |
|
|
$ |
— |
|
|
$ |
249 |
|
Working
capital (deficit)
|
|
$ |
(37,886 |
) |
|
$ |
96,094 |
|
|
$ |
(2,894 |
) |
|
$ |
(1,025 |
) |
|
$ |
(358 |
) |
Total
assets
|
|
$ |
651,600 |
|
|
$ |
453,820 |
|
|
$ |
48,185 |
|
|
$ |
7,179 |
|
|
$ |
6,560 |
|
Long-term
debt
|
|
$ |
151,188 |
|
|
$ |
28,970 |
|
|
$ |
1,995 |
|
|
$ |
4,013 |
|
|
$ |
— |
|
Stockholders’
equity
|
|
$ |
282,286 |
|
|
$ |
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. See “Business—Company History.” In
addition, we acquired a minority interest in Front Range on October 17, 2006, at
which date we began treating Front Range, a variable interest entity, as a
consolidated subsidiary, 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, except as
required by law.
Any of
the factors described immediately 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 be the leading marketer and producer of low carbon 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, Oregon, Colorado and
Idaho. We have extensive customer relationships throughout the Western United
States and extensive supplier relationships throughout the Western and
Midwestern United States.
We own
and operate two ethanol production facilities located in Madera, California and
Boardman, Oregon. Our Madera facility has an annual production capacity of up to
40 million gallons and has been in operation since October 2006. Our Boardman
facility has an annual production capacity of up to 40 million gallons and has
been in operation since September 2007. In addition, we own a 42% interest in
Front Range Energy, LLC, or Front Range, which owns and operates an ethanol
production facility with annual production capacity of up to 50 million gallons
in Windsor, Colorado. We have two additional ethanol production facilities under
construction, in Burley, Idaho and Stockton, California, which are expected to
commence operations in the second and third quarters of 2008, respectively. We
also intend to either construct or acquire additional ethanol production
facilities as financial resources and business prospects make the construction
or acquisition of these facilities advisable. See “Business—Production
Facilities.”
Total
annual gasoline consumption in the United States is approximately 140 billion
gallons. Total annual ethanol consumption represented less than 5% of this
amount in 2007. We believe that the domestic ethanol industry has substantial
potential for growth to initially 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 annually and thereafter up to 36
billion gallons of ethanol annually under the new national Renewable Fuel
Standards, or RFS, by 2022. See “Business—Governmental Regulation.”
We intend
to reach our goal to be the leading marketer and producer of low carbon
renewable fuels in the Western United States in part by expanding our
relationships with customers and third-party ethanol producers to market higher
volumes of ethanol, by 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 by 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
transportation fuel. In addition, we intend to expand our annual production
capacity to 220 million gallons in 2008, upon completion of our facilities in
Burley, Idaho and Stockton, California, and 420 million gallons of annual
production capacity in 2010, through new construction or acquisition of
additional ethanol production facilities. We also intend to expand
our distribution infrastructure by increasing 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 $235.1 million, or 104%, to $461.5 million for the year ended
December 31, 2007 from $226.4 million for the year ended December 31, 2006. Our
net loss, however, increased by $14.3 million to $14.4 million for the year
ended December 31, 2007 from $0.1 million for the year ended December 31,
2006.
Factors
that contributed to our results of operations for 2007 include:
·
|
Net sales. The increase
in our net sales in 2007 as compared to 2006 was primarily due to the
following combination of factors:
|
o
|
Higher sales volumes.
Total volume of ethanol sold increased by 87% to 190.6 million gallons in
2007 from 101.7 million gallons in 2006. The increase in sales volume is
primarily due to a full year of ethanol production from our Madera and
Front Range facilities, each of which accounted for less than three months
of production in 2006. Sales also increased in 2007 from startup of
production at our Boardman facility and additional supply purchased from
third-party suppliers under our ethanol marketing agreements;
and
|
o
|
Lower ethanol prices.
The increase in sales volume was partially offset by lower ethanol prices.
Our average sales price of ethanol decreased 6% to $2.15 per gallon in
2007 as compared to $2.28 per gallon in 2006. This decrease is, however,
less than the 21% decline in the average Chicago Board of Trade, or CBOT,
ethanol price to $1.98 per gallon in 2007 as compared to $2.52 per gallon
in 2006.
|
·
|
Lower gross profit margin.
Our gross profit margin decreased to 7.1% for 2007 as compared to
11.0% for 2006. This decrease was primarily due to lower ethanol prices
and higher corn prices. In addition, we had significant fixed-price
contracts and held inventory balances during a period of declining ethanol
prices, both of which reduced our margins. The average price of corn, the
main raw material for ethanol we produce, increased by 48% to $3.61 per
bushel for 2007 from $2.44 per bushel for 2006. The average CBOT price for
corn increased by 44% to $3.74 per bushel for 2007 from $2.60 per bushel
for 2006. Also, gross profit margins from our sale of WDG and other
co-products from our ethanol production declined due to the increase in
corn prices.
|
·
|
Selling, general and
administrative expenses. Our selling, general and
administrative expenses increased by $6.2 million to $30.8 million in 2007
as compared to $24.6 million in 2006 primarily as a result of increases in
administrative staff, amortization of intangible assets and full-year
expenses related to our 42% ownership interest in Front Range. However,
these expenses decreased to 6.6% of our net sales in 2007 as compared to
10.9% of our net sales in 2006 due to the substantial growth in our net
sales over those periods.
|
·
|
Other income (expense).
Our other expense increased by $10.2 million to $6.8 million in
2007 from other income of $3.4 million in 2006. This increase is primarily
due to an increase in interest expense and amortization of finance charges
from our increase in debt. In addition, other expense increased due to
mark-to-market charges in the amount of $5.4 million on future interest
rate positions.
|
Sales
and Margins
Over the
past three years, our sales mix has shifted significantly from sales generated
solely as a marketer of ethanol produced by third parties to now include sales
generated as a producer of our own ethanol. Our cost structure also changed
significantly, predominantly in 2007, as our Madera and Front Range facilities
were in full production and our Boardman facility was in production for more
than three months during the year. The shift in our sales mix greatly altered
our dependency on certain market conditions from that based primarily on the
market price of ethanol to now include the cost of corn, the principal input
commodity for our production of ethanol. Accordingly, our profitability is now
highly dependent on the market price of ethanol and the cost of
corn.
Average
ethanol sales prices dropped significantly in 2007 as compared to 2006.
Specifically, the average CBOT price of ethanol decreased by 21% in 2007 as
compared to the average 2006 price. The decrease in the prevailing market price
of ethanol was the primary cause of the decline in our average ethanol sales
price. However, because of our combination of fixed- and index-priced ethanol
sales contracts, we were able to diminish the decline in our average ethanol
sales price to only 6% in 2007 as compared to our average 2006
price.
Average
corn prices increased significantly in 2007 as compared to 2006. Specifically,
the average CBOT price of corn increased by 44% in 2007 as compared to the
average 2006 price. The increase in the prevailing market price of corn was the
primary cause of the increase in our average corn price. However, our average
corn price increased by 48% in 2007 as compared to our average 2006 price—a rate
greater than the increase in the average CBOT price of corn—because we purchased
more corn in the fourth quarter of 2007, a period during which corn prices were
at their highest levels during the year, as compared to previous quarters in
connection with the commencement of operations at our Boardman
facility.
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
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.
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.
Results
of Operations
The
following selected financial data should be read in conjunction with our
consolidated financial statements and notes to our consolidated financial
statements included elsewhere in this report, and the other sections of
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” contained in this report.
Certain
performance metrics that we believe are important indicators of our results of
operations include:
|
|
|
|
|
Percentage
Variance
From
Prior Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gallons
sold (in millions)
|
|
|
190.6 |
|
|
|
|
101.7 |
|
|
|
|
52.3 |
|
|
|
|
87.4 |
%
|
|
|
|
94.4 |
%
|
|
Average
sales price per gallon
|
|
$ |
2.15 |
|
|
|
$ |
2.28 |
|
|
|
$ |
1.67 |
|
|
|
|
(5.7 |
)%
|
|
|
|
36.5 |
%
|
|
Corn
cost per bushel—CBOT equivalent(1)
|
|
$ |
3.61 |
|
|
|
$ |
2.44 |
|
|
|
|
N/A |
|
|
|
|
48.0 |
%
|
|
|
|
N/A |
|
|
Co-product
revenues as % of delivered cost of corn(2)
|
|
|
24.8 |
%
|
|
|
|
33.4 |
%
|
|
|
|
N/A |
|
|
|
|
(8.6 |
)%
|
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
CBOT ethanol price per gallon
|
|
$ |
1.98 |
|
|
|
$ |
2.52 |
|
|
|
$ |
1.70 |
|
|
|
|
(21.4 |
)%
|
|
|
|
48.2 |
%
|
|
Average
CBOT corn price per bushel
|
|
$ |
3.74 |
|
|
|
$ |
2.60 |
|
|
|
$ |
1.77 |
|
|
|
|
43.9 |
%
|
|
|
|
46.9 |
%
|
|
_____________
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
We
exclude transportation—or “basis”—costs in our corn costs to calculate a
CBOT equivalent in order to more appropriately compare our corn costs to
average CBOT corn prices.
|
|
(2)
|
Co-product
revenues as % of delivered cost of corn shows our yield based on sales of
WDG generated from ethanol we
produced.
|
Year
Ended December 31, 2007 Compared to the Year Ended December 31,
2006
|
|
Years
Ended
|
|
|
Dollar
Variance
|
|
|
Percentage
Variance
|
|
|
Results
as a Percentage
of Net Sales for
the
Years
Ended
|
|
|
|
December
31,
|
|
|
Favorable
|
|
|
Favorable
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars
in thousands)
|
|
Net
sales
|
|
$ |
461,513 |
|
|
$ |
226,356 |
|
|
$ |
235,157 |
|
|
|
103.9 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
Cost
of goods sold
|
|
|
428,614 |
|
|
|
201,527 |
|
|
|
(227,087 |
) |
|
|
(112.7 |
) |
|
|
92.9 |
|
|
|
89.0 |
|
Gross
profit
|
|
|
32,899 |
|
|
|
24,829 |
|
|
|
8,070 |
|
|
|
32.5 |
|
|
|
7.1 |
|
|
|
11.0 |
|
Selling,
general and administrative expenses
|
|
|
30,822 |
|
|
|
24,641 |
|
|
|
(6,181 |
) |
|
|
(25.1 |
) |
|
|
6.6 |
|
|
|
10.9 |
|
Income
from operations
|
|
|
2,077 |
|
|
|
188 |
|
|
|
1,889 |
|
|
|
1,004.8 |
|
|
|
0.5 |
|
|
|
0.1 |
|
Other
income (expense), net
|
|
|
(6,801 |
) |
|
|
3,426 |
|
|
|
(10,227 |
) |
|
|
(298.5 |
) |
|
|
(1.5 |
) |
|
|
1.5 |
|
Income
(loss) before provision for income taxes and noncontrolling interest in
variable interest entity
|
|
|
(4,724 |
) |
|
|
3,614 |
|
|
|
(8,338 |
) |
|
|
(230.7 |
) |
|
|
(1.0 |
) |
|
|
1.6 |
|
Provision
for income taxes
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Noncontrolling
interest in variable interest entity
|
|
|
(9,676 |
) |
|
|
(3,756 |
) |
|
|
(5,920 |
) |
|
|
(157.6 |
) |
|
|
(2.1 |
) |
|
|
(1.7 |
) |
Net
loss
|
|
$ |
(14,400 |
) |
|
$ |
(142 |
) |
|
$ |
(14,258 |
) |
|
|
(10,040.9 |
)% |
|
|
(3.1 |
)% |
|
|
(0.1 |
)% |
Preferred
stock dividends
|
|
|
(4,200 |
) |
|
|
(2,998 |
) |
|
|
(1,202 |
) |
|
|
(40.1 |
) |
|
|
(0.9 |
) |
|
|
(1.3 |
) |
Deemed
dividend on preferred stock
|
|
|
(28 |
) |
|
|
(84,000 |
) |
|
|
83,972 |
|
|
|
100.0 |
|
|
|
(0.0 |
) |
|
|
(37.1 |
) |
Loss
available to common stockholders
|
|
$ |
(18,628 |
) |
|
$ |
(87,140 |
) |
|
$ |
68,512 |
|
|
|
78.6 |
% |
|
|
(4.0 |
)% |
|
|
(38.5 |
)% |
Net
Sales
The
increase in our net sales in 2007 as compared to 2006 was primarily due to a
substantial increase in sales volume, which was partially offset by decreased
average sales prices.
Total
volume of ethanol sold increased by 88.9 million gallons, or 87%, to 190.6
million gallons in 2007 as compared to 101.7 million gallons in 2006. The
substantial increase in sales volume is primarily due to a full year of ethanol
production at our Madera and Front Range facilities in 2007. Our Madera and
Front Range facilities each accounted for less than three months of ethanol
production in 2006. In addition, in 2007, we commenced ethanol production at our
Boardman facility and also generated increased sales from the purchase and
resale of additional supply from third-parties under our ethanol marketing
agreements. The production and sale of ethanol and its co-products from our
Madera and Boardman facilities, and through Front Range, contributed an
aggregate of $194.0 million to our increase in net sales in 2007.
Our
average sales price per gallon declined 6% to $2.15 in 2007 from an average
sales price per gallon of $2.28 in 2006. The average CBOT price per gallon
declined 21% to $1.98 in 2007 from an average CBOT price per gallon of $2.52 in
2006. We believe that we were insulated from some of this decline due to our
fixed-price ethanol contracts which were partially offset by derivative losses
incurred as a result of locking in margins.
Cost
of Goods Sold and Gross Profit
The
increase in our cost of goods sold in 2007 as compared to 2006 was predominantly
due to increased sales volume and increased corn costs which contributed to
higher costs per gallon. Our gross margin declined to 7.1% in 2007 from 11.0% in
2006 primarily due to increased corn costs, lower average sales prices per
gallon and losses on derivatives, as further discussed below.
Although
a large proportion of our sales volume results from the marketing and sale of
ethanol produced by third parties, production of our own ethanol is growing
rapidly and we expect that our production will continue to grow as new
facilities commence operations. Our purchase and sale prices of ethanol produced
by third parties typically fluctuate closely with market prices. As a result,
our average cost of ethanol purchased from third parties decreased in line with
the overall decline in our average sales price per gallon.
Corn is
the single largest component of the cost of our ethanol production. Average corn
prices rose significantly in 2007 as compared to 2006, with greater increases
occurring in the second half of 2007 than in the first half of the year. These
increases pushed our average corn price higher than the average market price for
all of 2007 because our corn requirements increased significantly during the
second half of 2007 due to the commencement of operations at our Boardman
facility in September 2007. Overall, the price of corn had a much larger impact
on our production costs per gallon in 2007 than in 2006 due to the higher
proportion of sales from production of our own ethanol in 2007 as compared to
2006.
Cost of
goods sold also increased by $4,122,000 from net losses on derivatives in 2007
as compared to only a nominal amount in 2006. These losses resulted from
derivatives that we entered in order to lock in margins during the year and were
partially offset by gains from derivatives we entered in order to lock in the
price of corn. Of these losses, $1,649,000 was related to open positions at
December 31, 2007.
Selling,
General and Administrative Expenses
Our
selling, general and administrative expenses, or SG&A, increased by
$6,181,000 to $30,822,000 for 2007 as compared to $24,641,000 for 2006.
SG&A, however, decreased as a percentage of net sales due to our significant
sales growth. The increase in the dollar amount of SG&A is primarily due to
the following factors:
·
|
payroll
and benefits increased by $3,017,000, or 68%, due to increased
administrative staff;
|
·
|
amortization
of intangible assets resulting from our acquisition of our 42% ownership
interest in Front Range increased by $2,117,000, as we incurred a full
year of amortization compared to less than three months in 2006; we expect
these costs to decline to approximately $500,000 for each of the next
seven years;
|
·
|
SG&A
attributable to Front Range increased by $2,042,000 as we incurred a full
year of these expenses as compared to less than three months in
2006;
|
·
|
consulting
and temporary staff expenses increased by $1,950,000, or 126%, due to the
retention of additional consulting and temporary staff personnel to assist
us in meeting our accounting and public reporting requirements, including
as we transitioned our permanent staff to our new corporate headquarters
in Sacramento, California; these consulting and temporary staff personnel
also assisted us in training new administrative staff
members;
|
·
|
recruiting,
hiring and training expenses increased by $709,000, or 1,055%, employee
travel and office setup costs increased by $377,000, or 243%, and rent
expense increased by $457,000, or 221%; each of these increases resulted
primarily from the relocation of our corporate headquarters in early 2007
from Fresno to Sacramento;
|
·
|
external
audit costs increased by $582,000, or 312%, due to our overall growth and
business initiatives; and
|
·
|
travel-related
costs increased by $311,000, or 52%, due to expanded operations and new
office locations.
|
Partially
offsetting the foregoing increases were the following decreases:
·
|
non-cash
compensation expense decreased by $4,023,000, or 64%, due to the
completion of vesting of incentive compensation paid to employees and
consultants;
|
·
|
legal
expenses decreased by $918,000, or 43%, primarily due to one-time costs
associated with greater legal activity from litigation and business
transactions that occurred in 2006;
and
|
·
|
costs
associated with implementing and testing our internal controls and related
compliance required under the Sarbanes-Oxley Act of 2002 decreased by
$902,000, or 76%, as many costs that occurred in 2006 were related
predominantly to our initial implementation and testing of our internal
controls.
|
Other
Income (Expense), Net
Other
expense increased by $10,227,000 to $6,801,000 in 2007 from other income of
$3,426,000 in 2006. The increase in other expense is primarily due to the
following factors:
·
|
interest
expense increased by $1,828,000, or 286%, due to additional borrowings and
a full year of interest accruing on outstanding debt;
and
|
·
|
amortization
of interest and financing costs increased by $3,164,000, or 305%,
primarily due to an amendment to our construction financing credit
facility that reduced its application from five to four facilities and
reduced the total amount of available financing; as a result, we wrote off
$1,962,000 of unamortized costs associated with our Imperial Valley
facility, the construction of which has been suspended;
interest and financing costs incurred under the construction phase of each
of our facilities are being capitalized until the corresponding facility
becomes operational; this increase in amortization of interest and
financing costs is net of approximately $7,823,000 of additional
capitalized amounts over 2006.
|
In
addition, we recognized losses of $119,000 and $5,442,000 of effective and
ineffectiveness positions, respectively, from our interest rate hedges which
required that we mark-to-market our ineffective positions in a declining
interest rate environment. The ineffectiveness related to our interest rate
swaps and primarily resulted from the suspension of construction of our Imperial
Valley facility.
Noncontrolling
Interest in Variable Interest Entity
Noncontrolling
interest in variable interest entity relates to the consolidated treatment of
Front Range, a variable interest entity, and represents the noncontrolling
interest of others in the earnings of Front Range. We consolidate the entire
income statement of Front Range for the period covered. However, because we own
only 42% of Front Range, we must reduce our net income or increase our net loss
for the noncontrolling interest, which is the 58% ownership interest that we do
not own. This amount increased by $5,920,000 to $9,676,000 in 2007 from
$3,756,000 in 2006 due to the consolidation of Front Range’s operations for all
of 2007 as compared to less than three months in 2006.
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, payable 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 2007, we declared and paid dividends
on our Series A Preferred Stock in the aggregate amount of $4,200,000 comprised
of cash dividends in the aggregate amount of $3,150,000 for the first three
quarters and a dividend payment-in-kind in the amount of $1,050,000 that was
issued in shares of Series A Preferred Stock for the fourth
quarter.
Deemed
Dividend on Preferred Stock
We
recorded a deemed dividend on preferred stock of $28,000 for 2007 in connection
with our issuance of shares of Series A Preferred Stock as a dividend
payment-in-kind for the fourth quarter. We also recorded a deemed dividend on
preferred stock of $84,000,000 for 2006 in connection with our initial issuance
of shares of Series A Preferred Stock. These non-cash dividends reflect the
implied economic value to the preferred stockholder of being able to convert
these additional shares into common stock at prices which were in excess of the
fair value of the Series A Preferred Stock at the times 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 $8.21 and $29.27 on the
date of issuance of the additional shares of Series A Preferred Stock for 2007
and 2006, respectively. The fair value allocated to the initial issuance of the
Series A Preferred Stock in 2006 was in excess of the gross proceeds received of
$84,000,000 in connection with the initial sale of the Series A Preferred Stock;
however, the deemed dividend on the Series A Preferred Stock for 2006 is limited
to the gross proceeds received of $84,000,000. 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, 2006 Compared to the Year Ended December 31,
2005
|
|
Years
Ended
|
|
|
Dollar
Variance
|
|
|
Percentage
Variance
|
|
|
Results
as a Percentage
of Net Sales for
the
Years
Ended
|
|
|
|
December
31,
|
|
|
Favorable
|
|
|
Favorable
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars
in thousands)
|
|
Net
sales
|
|
$ |
226,356 |
|
|
$ |
87,599 |
|
|
$ |
138,757 |
|
|
|
158.4 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
Cost
of goods sold
|
|
|
201,527 |
|
|
|
84,444 |
|
|
|
(117,083 |
) |
|
|
(138.7 |
) |
|
|
89.0 |
|
|
|
96.4 |
|
Gross
profit
|
|
|
24,829 |
|
|
|
3,155 |
|
|
|
21,674 |
|
|
|
687.0 |
|
|
|
11.0 |
|
|
|
3.6 |
|
Selling,
general and administrative expenses
|
|
|
24,641 |
|
|
|
12,638 |
|
|
|
(12,003 |
) |
|
|
(95.0 |
) |
|
|
10.9 |
|
|
|
14.4 |
|
Income
(loss) from operations
|
|
|
188 |
|
|
|
(9,483 |
) |
|
|
9,671 |
|
|
|
102.0 |
|
|
|
0.1 |
|
|
|
(10.8 |
) |
Other
income (expense), net
|
|
|
3,426 |
|
|
|
(440 |
) |
|
|
3,866 |
|
|
|
878.6 |
|
|
|
1.5 |
|
|
|
(0.5 |
) |
Income
(loss) before provision for income taxes and noncontrolling interest in
variable interest entity
|
|
|
3,614 |
|
|
|
(9,923 |
) |
|
|
13,537 |
|
|
|
136.4 |
|
|
|
1.6 |
|
|
|
(11.3 |
) |
Provision
for income taxes
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Noncontrolling
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 |
)% |
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 increased by 49.4 million gallons, or 94%, 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 37%, to $2.28
per gallon for 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 $28,064,000 in sales for 2006.
Cost
of Goods Sold and Gross Profit
The
increase in our cost of goods sold in 2006 as compared to 2005 was predominantly
due to increased sales volume. 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 SG&A 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, 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 implementation and testing of
internal controls and procedures in connection with the Sarbanes-Oxley Act of
2002, a $452,000 increase in travel and entertainment and a $250,000 increase in
investor relations expense.
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. 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.
Noncontrolling
Interest in Variable Interest Entity
Noncontrolling
interest in variable interest entity was $3,756,000. As noted above, this amount
relates to the consolidated treatment of Front Range, a variable interest entity
and represents the noncontrolling interest of others in the earnings of Front
Range.
Preferred
Stock Dividends
As noted
above, shares of our Series A Preferred Stock are entitled to quarterly
cumulative dividends. In 2006, we declared and paid cash dividends on shares of
our Series A Preferred Stock in the aggregate amount of $2,998,000.
Deemed
Dividend on Preferred Stock
We
recorded a deemed dividend on preferred stock of $84,000,000 for 2006 in
connection with our initial issuance of shares of Series A Preferred Stock. This
non-cash dividend reflects the implied economic value to the preferred
stockholder of being able to convert the shares into common stock at a price
which was in excess of the fair value of the Series A Preferred Stock at the
time 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 shares of Series A Preferred Stock. The
fair value allocated to the issuance of the Series A Preferred Stock was in
excess of the gross proceeds received of $84,000,000 in connection with the sale
of the Series A Preferred Stock; however, the deemed dividend on the Series A
Preferred Stock for 2006 is limited to the gross proceeds received of
$84,000,000. 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.
Liquidity
and Capital Resources
Overview
During
2007, we funded our operations primarily from our cash on hand, borrowings on
our credit facilities and other loans. In the first half of 2007, we obtained
financing for our first five ethanol production facilities and received the
first draw under this credit facility in the amount of $76.6 million for our
Madera facility. We also received approximately $24.9 million in the first half
of 2007, which represented the remaining balance in a restricted cash account
from our April 2006 sale of our Series A Preferred Stock. These proceeds were
used to fund the continued construction of four ethanol production
facilities.
In the
second half of 2007, we received the second draw under our credit facility in
the amount of $50.4 million for our Boardman facility. In the second half of
2007, we also settled certain cost-overruns at our Boardman facility through the
issuance of a $6.0 million note due in December 2008. Also in the second half of
2007, after evaluating the overall ethanol market and our production capacity
and cost structure, we decided to suspend construction of our Imperial Valley
facility near Calipatria, California. At the time of this decision, we owed
approximately $30.0 million for work already performed on the project. We
borrowed $30.0 million in the fourth quarter of 2007 to help cover these and
other costs. See “—Current and Prospective Capital Needs” and “—Notes Payable”
below.
Sale
of Series B Preferred Stock
On March
27, 2008, we issued to Lyles United, LLC, 2,051,282 shares of our Series B
Preferred Stock and a ten-year warrant to purchase an aggregate of 3,076,923
shares of our common stock at an exercise price of $7.00 per share for an
aggregate purchase price of $40.0 million. Each share of Series B Preferred
Stock is initially convertible into three shares of our common stock. We intend
to use the proceeds from the sale of our Series B Preferred Stock for general
working capital purposes and to further fund the construction of our Burley and
Stockton ethanol production facilities.
Current
and Prospective Capital Needs
We
believe that current and future capital resources, revenues generated from
operations and other existing sources of liquidity, including available proceeds
from our existing debt financing, will be adequate to fund our operations
through 2008 and meet our capital expenditure requirements to reach our goal of
220 million gallons of annual production capacity in 2008 upon completion of our
Burley and Stockton facilities. We will require substantial
additional financing to reach our goal of 420 million gallons of annual
production capacity in 2010 and we plan to reach this goal through new
construction or acquisition of additional ethanol production
facilities. If ethanol production margins deteriorate from current
levels, if we experience additional cost overruns at our ethanol production
facilities under construction, if our capital requirements or cash flows
otherwise vary materially and adversely from our current projections, or if
other adverse unforeseen circumstances occur, our working capital may be
inadequate to fully fund our operations or meet our capital expenditure
requirements, or both. We are presently exploring potential sources of new
financing to provide additional working capital. Our failure to raise
capital if or when needed may have a material adverse effect on our results of
operations, liquidity and cash flows and may restrict our growth and hinder our
ability to compete.
We have
recently raised $30.0 million in debt financing from Lyles United, LLC and $40.0
million through the sale of our Series B Preferred Stock and a warrant to Lyles
United, LLC. Our need for this additional capital was due to numerous
factors that arose or that we identified in the fourth quarter of
2007. We experienced higher than forecast construction costs at our
Burley and Stockton facilities as a result of unanticipated change
orders. We also incurred higher costs related to the completion of
“punch list” items at our Boardman facility and costs related to the suspension
of construction of our Imperial Valley facility. In aggregate, these
cost overruns that arose or that were identified in the fourth quarter of 2007
were approximately $27.0 million. In addition, funding under our
construction loan facility will occur later than previously
anticipated. Consequently, we expect to fund approximately $29.0
million for the ongoing construction of our Burley and Stockton
facilities. We expect a significant portion of the $29.0 million to
be recovered upon completion of our Burley and Stockton facilities, at which
time we expect to draw additional loan proceeds under the terms of our existing
construction loan facility. In addition to the above factors, we also
continued to experience adverse ethanol market conditions during the fourth
quarter of 2007. The effects of lower than expected commodity
margins—the difference between the selling price of ethanol and the cost of
corn—caused our cash generated from operations to be lower than
forecast.
Quantitative
Year-End Liquidity Status
We
believe that the following amounts provide insight into our liquidity and
capital resources. The following selected financial data should be read in
conjunction with our consolidated financial statements and notes to consolidated
financial statements included elsewhere in this report, and the other sections
of “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” contained in this report (dollars in thousands):
|
|
As
of and for the Year Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$ |
82,193 |
|
|
$ |
127,045 |
|
|
|
(35.3 |
)% |
Current
liabilities
|
|
$ |
120,079 |
|
|
$ |
30,951 |
|
|
|
288.0 |
% |
Property
and equipment, net
|
|
$ |
468,704 |
|
|
$ |
196,156 |
|
|
|
138.9 |
% |
Notes
payable, net of current portion
|
|
$ |
151,188 |
|
|
$ |
28,970 |
|
|
|
421.9 |
% |
Cash
provided by (used in) operating activities
|
|
$ |
16,718 |
|
|
$ |
(8,144 |
) |
|
|
305.3 |
% |
Working
capital
|
|
$ |
(37,886 |
) |
|
$ |
96,094 |
|
|
|
(139.4 |
)% |
Working
capital ratio
|
|
|
0.68 |
|
|
|
4.10 |
|
|
|
(83.4 |
)% |
Change
in Working Capital and Cash Flows
Working
capital decreased to a deficit of $37,886,000 at December 31, 2007 from working
capital of $96,094,000 at December 31, 2006 as a result of a decrease in
current assets of $44,852,000 and an increase in current liabilities of
$89,128,000.
Current
assets decreased primarily due to net decreases in cash and cash equivalents and
investments in marketable securities of $38,346,000 and $19,766,000,
respectively, the proceeds of which were predominantly used for costs associated
with the construction of ethanol production facilities, and a decrease in
accounts receivable of $1,288,000, which were partially offset by an increase in
inventory of $10,945,000, primarily resulting from an increase in ethanol held
in inventory, and an increase in all other current assets of
$3,120,000.
Current
liabilities increased primarily due to an increase in construction-related
accounts payable and accrued liabilities of $52,172,000, an increase in trade
accounts payable of $13,683,000, an increase in current portion of long-term
notes payable of $6,973,000, a short-term note payable of $6,000,000, an
increase in contract retentions of $5,001,000, an increase in derivative
liabilities of $10,256,000, an increase in accrued liabilities of $2,440,000 and
an increase in all other liabilities of $1,125,000, which were partially offset
by a net decrease in other liabilities – related parties of
$8,522,000.
The
decrease in working capital was primarily due to construction activity during
the year, requiring the use of our cash and investments in marketable securities
balances and increased construction-related accounts payable and accrued
expenses. The decrease in working capital was also due in part to increased
short- and long-term financing, which increased the current portion of our
debt.
Cash
provided by our operating activities of $16,718,000 resulted primarily from an
increase in accounts payable and accrued expenses of $10,332,000, depreciation
and amortization of intangibles of $17,513,000, non-controlling interest in our
variable interest entity of $9,676,000, derivative losses of $6,617,000,
amortization of deferred financing fees of $4,726,000, non-cash compensation and
consulting expense of $2,225,000 and a decrease in accounts receivable of
$1,230,000, which were partially offset by an increase in inventories of
$10,945,000 and other liabilities – related parties of $8,524,000.
Cash used
in our investing activities of $166,214,000 resulted from purchases of
additional property and equipment of $210,482,000 which were partially offset by
a decrease in restricted cash designated for construction of $24,851,000 and
proceeds from sales of marketable securities of $19,417,000.
Cash
provided by our financing activities of $111,150,000 resulted primarily from
proceeds from our debt financing and lines of credit of $137,725,000 and
proceeds from the exercise of warrants and stock options of $2,257,000, which
were partially offset by cash paid for debt issuance costs of $10,261,000,
principal payments paid on borrowings of $8,678,000 and preferred stock
dividends paid of $4,200,000.
Changes
in Other Assets and Liabilities
Property
and equipment, net, increased to $468,704,000 at December 31, 2007 from
$196,156,000 at December 31, 2006 primarily as a result of the construction of
ethanol plants.
Restricted
cash decreased to $0 at December 31, 2007 from $24,851,000 at December 31,
2006. We received approximately $24,851,000 in the first half of 2007, which
represented the remaining balance in a restricted cash account from our April
2006 sale of our Series A Preferred Stock.
Notes
payable, net of current portion, increased to $151,188,000 at December 31, 2007
from $28,970,000 at December 31, 2006 primarily as a result of loan proceeds
used for construction activities at our ethanol plants under construction. The
proceeds from these notes payable were primarily from our debt financing
arrangement described below.
Debt
Financing
On
February 27, 2007, we closed a debt financing transaction in the aggregate
amount of up to $325,000,000 through certain of our indirectly wholly-owned
subsidiaries. The primary purpose of the debt financing was to provide debt
financing for the development, construction, installation, engineering,
procurement, design, testing, start-up, operation and maintenance of five
ethanol production facilities. On November 27, 2007, we amended the related
credit agreement to apply to four ethanol production facilities, thereby
reducing the aggregate amount of available financing to up to $250,769,000. As
of December 31, 2007, two of the four plants had been funded, with the remaining
two expected to be funded in 2008. As of that date, the outstanding balance
under the debt financing was $101,508,000, comprised of $92,308,000 in
construction loans and $9,200,000 in used lines of credit.
Debt
financing proceeds are subject to customary conditions precedent, including,
among others, the absence of a material adverse effect; the absence of defaults
or events of defaults, which include the existence of any material weakness in
our internal control over financial reporting; the accuracy of certain
representations and warranties; the maintenance of a debt-to-equity ratio that
is not in excess of 65:35; the contribution of all required equity by us to the
Borrowers, which is expected to be approximately $227,000,000 in the aggregate;
and the attainment of at least a 1.5-to-1.0 debt service coverage ratio. Also,
the Borrowers may not be able to fully utilize the debt financing if the
completed ethanol plants fail to meet certain minimum performance standards or
if the corresponding ethanol plants are not timely completed. Borrowings and the
borrowers’ obligations under the debt financing are secured by a first-priority
security interest in all of our equity interests in the borrowers and
substantially all the assets of the borrowers. The security interests granted by
the borrowers under the debt financing restrict the assets and revenues of the
borrowers and therefore may inhibit our ability to obtain other debt
financing.
In March
2008, we became aware of various events or circumstances which constituted
defaults under our Credit Agreement. These events or circumstances included the
existence of material weaknesses in our internal control over financial
reporting as of December 31, 2007, cash management activities that violated
covenants in our Credit Agreement, failure to maintain adequate amounts in a
designated debt service reserve account, the existence of a number of Eurodollar
loans in excess of the maximum number permitted under our Credit Agreement, and
our failure to pay all remaining project costs on our Madera and Boardman
facilities by certain stipulated deadlines. On March 26, 2008, we obtained
waivers from our lenders as to these defaults and were required to pay the
lenders a consent fee in an aggregate amount of up to approximately $600,000. In
addition to the waivers, our lenders agreed to amend the Credit Agreement. These
amendments include an increase in the frequency with which we are to deposit
certain revenues into a restricted account each month, an increase the allowable
Eurodollar loans from a maximum of seven to a maximum of ten, and we are
required to pay all remaining project costs on our Madera and Boardman
facilities by May 16, 2008.
Line
of Credit
In
addition to the above debt financing, in August 2007, we secured a working
capital credit facility in the amount of up to $25,000,000 which expires in July
2009. As of December 31, 2007, we had $6,217,000 outstanding under this credit
facility under two separate variable interest rates of 6.19% and
6.75%.
Notes
Payable
In
November and December 2007, one of our subsidiaries borrowed an aggregate of
$30,000,000 in two separate loans of $15,000,000 each. The loans accrue interest
at a rate equal to the Prime Rate of interest as reported from time to time in
The Wall Street
Journal, plus 2.00%. The November 2007 is due February 25, 2009. The
December 2007 loan is due on March 31, 2008 or, if extended at our discretion,
on March 31, 2009. We intend to extend the due date of the December 2007 loan.
Both loans are secured by substantially all of our subsidiary’s assets. In
addition, we have executed a corporate guaranty that guarantees the repayment of
the loans.
Contractual
Obligations
The following table outlines payments
due under our significant contractual obligations (in
thousands):
Contractual
Obligations
At
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sourcing
commitments(1)
|
|
$ |
76,780 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
76,780 |
|
Debt
principal
|
|
|
13,637 |
|
|
|
53,465 |
|
|
|
7,260 |
|
|
|
17,546 |
|
|
|
5,661 |
|
|
|
70,717 |
|
|
|
168,286 |
|
Debt
interest
|
|
|
14,787 |
|
|
|
13,898 |
|
|
|
9,416 |
|
|
|
8,749 |
|
|
|
7,243 |
|
|
|
18,396 |
|
|
|
72,489 |
|
Operating
leases(2)
|
|
|
2,247 |
|
|
|
2,434 |
|
|
|
2,425 |
|
|
|
2,267 |
|
|
|
1,965 |
|
|
|
10,282 |
|
|
|
21,620 |
|
Firm
capital commitments(3)
|
|
|
118,357 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
118,357 |
|
Preferred
dividends(4)
|
|
|
4,253 |
|
|
|
4,253 |
|
|
|
4,253 |
|
|
|
4,253 |
|
|
|
4,253 |
|
|
|
4,253 |
|
|
|
25,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
commitments
|
|
$ |
230,061
|
|
|
$ |
74,050 |
|
|
$ |
23,354
|
|
|
$ |
32,815 |
|
|
$ |
19,122 |
|
|
$ |
103,648 |
|
|
$ |
483,050 |
|
|
(1)
|
Unconditional
purchase commitments for production materials incurred in the normal
course of business.
|
|
(2)
|
Future
minimum payments under non cancelable operating
leases.
|
|
(3)
|
Construction
commitments for in-progress and contracted ethanol processing
facilities
|
|
(4)
|
Represents
dividends on 5,315,625 shares of Series A Preferred
Stock.
|
The above
table outlines our obligations as of December 31, 2007 and does not reflect the
changes in our obligations that occurred after that date.
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
producer. Sales as a producer consist of sales of our
inventory produced at our
facilities.
|
·
|
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 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 the risk and rewards of inventory ownership remains with
third-party suppliers as we receive a predetermined service fee under
these transactions and therefore act predominantly in an agency capacity.
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 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 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 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 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 have also determined that we are the primary beneficiary and
we are therefore required to treat Front Range as a consolidated subsidiary for
financial reporting purposes rather than use equity investment accounting
treatment. As a result, we have consolidated the financial results of Front
Range, including its entire balance sheet with the balance of the noncontrolling
interest displayed between liabilities and equity, and the income statement
after intercompany eliminations with an adjustment for the noncontrolling
interest in net income since our acquisition on October 17, 2006. 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.
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 Statement of
Financial Accounting Standards (“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 ethanol
production facilities.
We
account for goodwill and intangible assets with indefinite lives in accordance
with SFAS No. 142. We review these assets at least annually, or more frequently
if impairment indicators arise. In our review, we determine the fair value of
these assets 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 statements
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, 2007.
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, including inflation, and capital spending
decisions of our customers. We have not recognized any impairment losses on
long-lived assets through December 31, 2007.
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(R), 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 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 income per share
had the fair value method been applied to all outstanding and unvested awards in
each period are reflected in Note 15 of the consolidated 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 15 of the consolidated 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.
123(R).
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 accumulated other comprehensive income and
later recorded together with the gains and losses to offset related results on
the hedged item in the statements of operations. Companies must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
The
estimated gains (losses) on our derivatives were as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Commodity
futures
|
|
$ |
(6,702 |
) |
|
$ |
646 |
|
Commodity
options
|
|
|
1,371 |
|
|
|
(24 |
) |
Interest
rate options
|
|
|
(5,590 |
) |
|
|
(17 |
) |
Total
|
|
$ |
(10,921 |
) |
|
$ |
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, 2007, as described in Note 1 to
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
in 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 considered 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 statements of operations.
Impact
of New Accounting Pronouncements
In March
2008, the FASB issued SFAS No. 161, Disclosure about Derivative
Instruments and Hedging Activities, an amendment of FASB Statement No.
133. SFAS No. 161 changes the disclosure requirements for derivative
instruments and hedging activities. Entities are required to provide enhanced
disclosures about (a) how and why an entity uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for under
Statement No. 133 and its related interpretations and (c) how derivative
instruments and related hedged items affect an entity’s financial position,
financial performance and cash flows. SFAS No. 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008, with early application encouraged. We are currently evaluating the
impact SFAS No. 161 may have on our consolidated financial
statements.
In
December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS
No. 141(R) retains the fundamental requirements in SFAS No. 141 that the
acquisition method of accounting be used for all business combinations and for
an acquirer to be identified for each business combination. SFAS No. 141(R)
requires an acquirer to recognize the assets acquired, the liabilities assumed,
and any noncontrolling interest in the acquiree at the acquisition date,
measured at their fair values as of that date, with limited exceptions specified
in SFAS No. 141(R). In addition, SFAS No. 141(R) requires acquisition costs and
restructuring costs that the acquirer expected but was not obligated to incur to
be recognized separately from the business combination, therefore, expensed
instead of part of the purchase price allocation. SFAS No. 141(R) will be
applied prospectively to business combinations for which the acquisition date is
on or after the beginning of the first annual reporting period beginning on or
after December 15, 2008. Early adoption is prohibited. We expect to adopt SFAS
No. 141(R) to any business combinations with an acquisition date on or after
January 1, 2009.
In
December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements, an amendment to ARB No. 51. SFAS No.
160 changes the accounting and reporting for minority interests, which will be
recharacterized as noncontrolling interests and classified as a component of
equity. SFAS No. 160 is effective for fiscal years, and interim periods within
those fiscal years, beginning on or after December 15, 2008. Early adoption is
prohibited. We are currently evaluating the impact SFAS No. 160 may have on our
consolidated financial statements.
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 costs 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
do not expect the adoption of SFAS No. 159 to have a material impact on our
financial condition or results of operations.
In
September 2006, the FASB issued SFAS No. 157. 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
original required effective date of SFAS No. 157 was the first quarter of 2008,
however, the FASB issued FASB Staff Position 157-2, Effective Date of FASB Statement No.
157, which deferred the adoption date by one year for all nonfinancial
assets and nonfinancial liabilities. We are currently evaluating the impact SFAS
No. 157 may have on our consolidated financial statements.
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 income. For the year ended December 31, 2007, a
gain from ineffectiveness in the amount of $2,832,000 and an effective loss in
the amount of $1,680,000 were recorded in cost of goods sold. For the year ended
December 31, 2006, losses of ineffectiveness in the amount of $239,000 and an
effective loss in the amount of $438,000 were 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 in sales. Amounts remaining in accumulated other
comprehensive income (loss) will be reclassified to income upon the recognition
of the related purchase or sale. Accumulated other comprehensive loss in the
amount of $455,000 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, 2007 and 2006 was $2,427,000 and $11,588,000,
respectively.
Commodity Risk – Non-Designated
Derivatives
As part
of our risk management strategy, we use forward contracts on corn, crude oil and
reformulated blendstock for oxygenate blending gasoline to lock in prices for
certain amounts of corn, denaturant and ethanol, respectively. These derivatives
are not designated under SFAS No. 133 for special hedge accounting treatment.
The changes in fair value of these contracts are recorded on the balance sheet
and recognized immediately in cost of goods sold. We recognized a loss of
$6,484,000 (of which $3,532,000 is related to settled non-designated hedges) and
$0 as the change in the fair value of these contracts for the year ended
December 31, 2007 and 2006, respectively. The notional balances remaining on the
contracts as of December 31, 2007 and 2006 were $29,999,000 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 and swaps.
The rate for notional balances of interest rate caps ranging from $0 to
$21,588,000 is 5.50%-6.00% per annum. The rate for notional balances of interest
rate swaps ranging from $0 to $63,219,000 is 5.01%-8.16% 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 income. For the year ended December 31, 2007, losses
from ineffectiveness in the amount of $4,836,000, losses from effectiveness in
the amount of $147,000 and losses from undesignated hedges in the amount of
$606,000 were recorded in other income (expense). For the year ended December
31, 2006, ineffectiveness in the amount of $24,000 was recorded in other income
(expense). There was no ineffectiveness for the year ended December 31, 2005.
Amounts remaining in accumulated other comprehensive income will be reclassified
to income upon the recognition of the hedged interest expense. For the year
ending December 31, 2008, we anticipate reclassifying $595,000 to income
associated with our cash flow interest rate caps and swaps.
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 accumulated other comprehensive income.
Accumulated
Other Comprehensive Income
Accumulated
other comprehensive income relative to derivatives for the year ended December
31, 2007 is as follows (in thousands):
|
|
Commodity
Derivatives
|
|
|
Interest
Rate Derivatives
|
|
|
|
|
|
|
|
|
Beginning
balance, January 1, 2007
|
|
$ |
461 |
|
|
$ |
(265 |
) |
Net
changes
|
|
|
(2,596 |
) |
|
|
(1,810 |
) |
Less: Amount
reclassified to cost of goods sold
|
|
|
(1,680 |
) |
|
|
— |
|
Less: Amount
reclassified to other income (expense)
|
|
|
— |
|
|
|
(147 |
) |
Ending
balance, December 31, 2007
|
|
$ |
(455 |
) |
|
$ |
(1,928 |
) |
—————
*Calculated
on a pretax basis
The
estimated fair values of our derivatives were as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Commodity
futures
|
|
$ |
(1,649 |
) |
|
$ |
329 |
|
Interest
rate options
|
|
|
(7,091 |
) |
|
|
125 |
|
Total
|
|
$ |
(8,740 |
) |
|
$ |
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 the 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.
|
Financial
Statements and Supplementary Data.
|
Reference
is made to the financial statements included in this report, which begin at Page
F-1.
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure.
|
None.
We
conducted an evaluation under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Financial 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 Chief Financial Officer concluded as of December
31, 2007 that our disclosure controls and procedures were not effective at a
reasonable assurance level due to the two material weaknesses discussed
immediately below.
In light
of the two material weaknesses described below, we performed additional analysis
and other post-closing procedures to ensure that our consolidated financial
statements were prepared in accordance with generally accepted accounting
principles. Accordingly, we believe that the consolidated financial statements
included in this report fairly present, in all material respects, our financial
condition, results of operations and cash flows for the periods
presented.
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 is defined by the Public Company Accounting Oversight Board’s
Audit Standard No. 5 as being a deficiency, or combination of deficiencies, in
internal control over financial reporting, such that there is a reasonable
possibility that a material misstatement of the company’s annual or interim
financial statements will not be prevented or detected on a timely basis by the
company’s internal controls.
Management
assessed and evaluated the effectiveness of our internal control over financial
reporting as of December 31, 2007. Based on the results of management’s
assessment and evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that as of December 31, 2007, the following two material
weaknesses in our internal control over financial reporting
existed:
|
(1)
|
We
did not have adequate internal control over our accrual of
construction-related costs for our ethanol production facilities;
and
|
|
(2)
|
We
did not exercise oversight of our personnel or their actions in a manner
reasonably calculated to ensure compliance under the Credit Agreement
governing our credit facility.
|
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 Chief Financial Officer
concluded that we did not maintain effective internal control over financial
reporting as of December 31, 2007. If not remediated, these material weaknesses
could result in one or more material misstatements in our reported financial
statements in a future annual or interim period.
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, 2007, we did not maintain effective internal
control over financial reporting.
Our
independent registered public accounting firm, Hein & Associates LLP,
independently assessed the effectiveness of our internal control over financial
reporting. Hein & Associates LLP has issued an attestation report concurring
with management’s assessment, which is included herein.
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
did not have adequate internal control over our accrual of construction-related
costs for our ethanol production facilities, as evidenced by the following
control deficiencies:
·
|
Our
auditors discovered that our accounting staff failed to accrue
construction-related costs represented by certain invoices that were set
aside for review but overlooked by our accounting staff. During the first
quarter of 2008, we implemented the following processes to remediate this
deficiency:
|
o
|
After
our accounts payable subledger is closed for the period, our accounting
staff is to communicate with our construction managers to determine
whether any invoices or progress billings under their review for the
reporting period have not been recorded in our accounts payable subledger;
and
|
o
|
After
our accounts payable subledger is closed for the period, our accounting
staff is to segregate any future invoices received for posting that relate
to the reporting period. These invoices are to be compared to accrual
balances to support the existing construction
accruals.
|
·
|
Our
period-end closing process lacked a method for determining an estimate for
invoices not yet received for construction costs as to which we believe a
contract liability existed at the end of the reporting period. During the
first quarter of 2008, we implemented the following processes to remediate
this deficiency:
|
o
|
During
our period-end closing process, and after our accounts payable subledger
is closed for the period, our accounting staff and senior management are
to perform construction cost trending analyses for subsidiaries with
significant construction related activities during the period. The trend
analyses are to be based on vendor activity and management is to review
the trend for reasonableness.
|
We
believe that we did, however, maintain adequate controls to ensure accruals were
properly recorded for non-construction related invoices received subsequent to
the closing of our accounts payable subledger. This material weakness resulted
in adjustments to our consolidated balance sheet as of December 31, 2007 but had
no impact to our consolidated statements of operations for the year ended
December 31, 2007. If not remediated, this material weakness could, however,
result in one or more material misstatements in our reported financial
statements in a future annual or interim period.
(2) We
did not exercise oversight of our personnel or their actions in a manner
reasonably calculated to ensure compliance under the Credit Agreement governing
our credit facility, as evidenced by the following control
deficiencies:
·
|
Under
the terms of the Credit Agreement, we are generally required to deposit
all revenues related to the production facilities financed under the
Credit Agreement in segregated revenue accounts which are controlled by
our lenders. The Credit Agreement includes specific covenants governing
our use of those funds. On Wednesday, March 12, 2008, our senior
management was informed that an unauthorized deviation from the Credit
Agreement requirements related to the segregated revenue accounts had
occurred. These actions, which we believe began in August 2007,
were apparently undertaken for the purpose of optimizing our cash position
and resulted in the violation of a number of covenants in the Credit
Agreement. Based our current analysis, we believe that the net amount of
cash that was diverted from the segregated revenue accounts to other
internal uses was approximately $3.9 million, which constituted a default
under the Credit Agreement.
|
·
|
The
Credit Agreement required that, on the date of the initial loan fundings
for our Madera and Boardman facilities, a designated debt service reserve
related to the loans should have been deposited into a debt service
reserve account controlled by our lenders. The amount of $3.4
million has not been deposited as required by the Credit Agreement, which
constitutes a default under the Credit
Agreement.
|
·
|
The
Credit Agreement limits us to no more than seven separate Eurodollar loans
outstanding at any time. We had eight Eurodollar loans outstanding, which
constitutes a default under the Credit
Agreement.
|
·
|
The
Credit Agreement provides that the “final completion” of our Madera and
Boardman facilities should already have occurred. One of the conditions to
“final completion” is that the borrowers pay all remaining project costs
related to the construction of the particular plant. We are still in the
process of negotiating final payments with certain
contractors. Both facilities commenced operations and we
received loan fundings for the facilities notwithstanding the failure to
achieve “final completion” by the stated deadline, which constitutes a
default under the Credit Agreement.
|
During
the first quarter of 2008, we implemented the following processes to remediate
these deficiencies:
·
|
We
have reassigned cash management responsibilities to our Chief Financial
Officer.
|
·
|
Our
Chief Financial Officer is to perform a review of all debt covenants in
place as of December 31, 2007 and determine whether we are in compliance
with those covenants; as to any covenants with which we are not in
compliance, our Chief Financial Officer is to undertake remediation
actions to ensure compliance with those covenants in the
future.
|
·
|
Our
Chief Financial Officer is to review, at the end of each future reporting
period, compliance reports prepared by his designee, for all debt
covenants as to which we received waivers from our
lenders.
|
This
material weakness did not result in any adjustments to our 2007 consolidated
financial statements. If not remediated, this material weakness could, however,
result in one or more material misstatements in our reported financial
statements in a future annual or interim period.
Expected
Remediation Date and Expenditures
Management
expects that our internal control over financial reporting as to the material
weaknesses described above will be tested, and the material weaknesses will be
remediated, by September 30, 2008. Management is unable, however, to
estimate our expenditures associated with this remediation, but we do not expect
them to be significant, except that we were required to pay a consent fee in the
aggregate amount of up to approximately $600,000 in connection with the waivers
from our lenders as to certain defaults under our Credit Agreement, including as
a result of the material weaknesses described above that existed as of December
31, 2007.
Changes
in Internal Control over Financial Reporting
There has
been no change in our internal control over financial reporting (as defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently
completed fiscal quarter that has materially affected, or is reasonably likely
to materially affect, our internal control over financial
reporting.
Attestation
Report of Independent Registered Public Accounting Firm
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Audit Committee and Management
Pacific
Ethanol, Inc.
Sacramento,
California
We have
audited Pacific Ethanol, Inc.’s internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
Pacific Ethanol, Inc.’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 included in the
accompanying Management’s
Report on Internal Control Over Financial Reporting. Our responsibility
is to express an opinion on 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, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audit also included 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 generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) 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 deficiency, or a combination of deficiencies, in internal
control over financial reporting, such that there is a reasonable possibility
that a material misstatement of the company’s annual or interim financial
statements will not be prevented or detected on a timely basis. The following
material weaknesses have been identified and included in management’s
assessment.
1.
|
The
Company did not have adequate internal control over its accrual of
construction-related costs for its ethanol production facilities;
and
|
2.
|
The
Company did not exercise oversight of its personnel or their actions in a
manner reasonably calculated to ensure compliance under the Credit
Agreement governing its credit
facility.
|
These
material weaknesses were considered in determining the nature, timing, and
extent of audit tests applied in our audit of the 2007 consolidated financial
statements, and this report does not affect our report dated March 27, 2008 on
those consolidated financial statements
In our
opinion, because of the effect of the material weakness described above on the
achievement of the objectives of the control criteria, Pacific Ethanol, Inc. has
not maintained effective internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Pacific
Ethanol, Inc. as of December 31, 2007 and 2006, and the related consolidated
statements of operations, comprehensive income (loss), stockholders’ equity, and
cash flows for each of the three years in the period ended December 31, 2007, of
Pacific Ethanol, Inc. and our report dated March 27, 2008 expressed an
unqualified opinion thereon.
/s/ HEIN
& ASSOCIATES LLP
Irvine,
California
March 27,
2008
Item
9A(T). Controls and Procedures.
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) Financial
Statements
Reference
is made to the financial statements listed on and attached following the
Index to Consolidated Financial Statements contained on page F-1 of this
report.
(a)(2) 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, 2007 and 2006
|
F-3
|
|
|
Consolidated
Statements of Operations for the Years Ended
|
|
December 31,
2007, 2006 and 2005
|
F-5
|
|
|
Consolidated
Statements of Comprehensive Income (Loss) for the Years
Ended
|
|
December 31,
2007, 2006 and 2005
|
F-6
|
|
|
Consolidated
Statement of Stockholders’ Equity for the Years Ended
|
|
December 31,
2007, 2006 and 2005
|
F-7
|
|
|
Consolidated
Statements of Cash Flows for the Years Ended
|
|
December 31,
2007, 2006 and 2005
|
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, 2007 and 2006, and the related consolidated statements of
operations, comprehensive income (loss), stockholders’ equity, and cash flows
for each of the three years in the period ended December 31, 2007. 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. An audit also includes 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, 2007 and 2006, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2007, 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), Pacific Ethanol, Inc.’s internal control over
financial reporting as of December 31, 2007, based on criteria established in
Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Our report dated March 27, 2008
expressed an opinion that Pacific Ethanol, Inc. had not maintained effective
internal control over financial reporting as of December 31, 2007, based on
criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO).
/s/ HEIN
& ASSOCIATES LLP
Irvine,
California
March 27,
2008
PACIFIC
ETHANOL, INC.
CONSOLIDATED
BALANCE SHEETS
(in
thousands)
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
5,707 |
|
|
$ |
44,053 |
|
Investments
in marketable securities
|
|
|
19,353 |
|
|
|
39,119 |
|
Accounts
receivable, net (including $7 and $1,195 as
of
December 31, 2007 and 2006,
respectively,
from a related party)
|
|
|
28,034 |
|
|
|
29,322 |
|
Restricted
cash
|
|
|
780 |
|
|
|
1,567 |
|
Inventories
|
|
|
18,540 |
|
|
|
7,595 |
|
Prepaid
expenses
|
|
|
1,498 |
|
|
|
1,053 |
|
Prepaid
inventory
|
|
|
3,038 |
|
|
|
2,029 |
|
Derivative
instruments
|
|
|
1,613 |
|
|
|
551 |
|
Other
current assets
|
|
|
3,630 |
|
|
|
1,756 |
|
Total
current assets
|
|
|
82,193 |
|
|
|
127,045 |
|
Property
and equipment, net
|
|
|
468,704 |
|
|
|
196,156 |
|
Other
Assets:
|
|
|
|
|
|
|
|
|
Restricted
cash
|
|
|
— |
|
|
|
24,851 |
|
Deposits
and advances
|
|
|
81 |
|
|
|
9,040 |
|
Goodwill
|
|
|
88,168 |
|
|
|
85,307 |
|
Intangible
assets, net
|
|
|
6,324 |
|
|
|
10,155 |
|
Other
assets
|
|
|
6,130 |
|
|
|
1,266 |
|
Total
other assets
|
|
|
100,703 |
|
|
|
130,619 |
|
Total
Assets
|
|
$ |
651,600 |
|
|
$ |
453,820 |
|
The accompanying notes are an integral part of these consolidated
financial statements.
PACIFIC
ETHANOL, INC.
CONSOLIDATED
BALANCE SHEETS (CONTINUED)
(in
thousands, except shares and par value)
|
|
|
|
LIABILITIES AND
STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
Accounts
payable – trade
|
|
$ |
22,641 |
|
|
$ |
8,958 |
|
Accrued
liabilities
|
|
|
5,570 |
|
|
|
3,130 |
|
Accounts
payable and accrued liabilities – construction-related
|
|
|
55,203 |
|
|
|
3,031 |
|
Contract
retentions
|
|
|
5,358 |
|
|
|
357 |
|
Other
liabilities – related parties
|
|
|
900 |
|
|
|
9,422 |
|
Current
portion – long-term notes payable
|
|
|
11,098 |
|
|
|
4,125 |
|
Short-term
note payable
|
|
|
6,000 |
|
|
|
— |
|
Derivative
instruments
|
|
|
10,353 |
|
|
|
97 |
|
Other
current liabilities
|
|
|
2,956 |
|
|
|
1,831 |
|
Total
current liabilities
|
|
|
120,079 |
|
|
|
30,951 |
|
|
|
|
|
|
|
|
|
|
Notes
payable, net of current portion
|
|
|
151,188 |
|
|
|
28,970 |
|
Other
liabilities
|
|
|
1,965 |
|
|
|
1,091 |
|
Total
Liabilities
|
|
|
273,232 |
|
|
|
61,012 |
|
Commitments
and contingencies (Notes 9, 16 and 17)
|
|
|
|
|
|
|
|
|
Noncontrolling
interest in variable interest entity
|
|
|
96,082 |
|
|
|
94,363 |
|
Stockholders’
Equity:
|
|
|
|
|
|
|
|
|
Preferred
stock, $0.001 par value; 10,000,000 shares authorized; 5,315,625 and
5,250,000 shares issued and outstanding as of December 31,
2007 and 2006, respectively
|
|
|
5 |
|
|
|
5 |
|
Common
stock, $0.001 par value; 100,000,000 shares authorized; 40,606,214 and
40,269,627 shares issued and outstanding as of December 31, 2007 and
2006, respectively
|
|
|
41 |
|
|
|
40 |
|
Additional
paid-in capital
|
|
|
402,932 |
|
|
|
397,536 |
|
Accumulated
other comprehensive income (loss)
|
|
|
(2,383 |
) |
|
|
545 |
|
Accumulated
deficit
|
|
|
(118,309 |
) |
|
|
(99,681 |
) |
Total
stockholders’ equity
|
|
|
282,286 |
|
|
|
298,445 |
|
Total
Liabilities and Stockholders’ Equity
|
|
$ |
651,600 |
|
|
$ |
453,820 |
|
The accompanying notes are an integral part of these consolidated
financial statements.
PACIFIC
ETHANOL, INC.
CONSOLIDATED
STATEMENTS OF OPERATIONS
(in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
sales (including $6,039, $16,985 and $9,060 for the years ended
December 31, 2007, 2006 and 2005, respectively, to a related
party)
|
|
$ |
461,513 |
|
|
$ |
226,356 |
|
|
$ |
87,599 |
|
|