CONSERVATIVE BROADCAST MEDIA & PUBLISHING, INC.
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
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x
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
fiscal year ended: December 31, 2009
or
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¨
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
transition period from _______________ to _______________
Commission
file number: 333-156467
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Crownbutte
Wind Power, Inc.
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|
(Exact
name of registrant as specified in its
charter)
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Nevada
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20-0844584
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|
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(State
or other jurisdiction of
incorporation
or organization)
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(IRS
Employer Identification
No.)
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111
5th Avenue NE, Mandan, ND
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58554
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant’s
telephone number, including area code:
(701)
667-2073
Securities
registered under Section 12(b) of the Act:
None
Securities
registered under Section 12(g) of the Act:
None
Indicate
by check mark if 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 15(d) of the Exchange 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 Exchange Act 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 whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files). Yes
¨
No
¨
Indicate
by check mark if disclosure of delinquent filers pursuant 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.
¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a smaller reporting company. See the
definitions of the “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
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Large
Accelerated Filer
¨
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Accelerated
Filer
¨
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Non-Accelerated
Filer
¨
(Do not check if a smaller
reporting company)
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Smaller
reporting company
x
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes
¨
No
x
On June
30, 2009, the last business day of the registrant’s most recently completed
second fiscal quarter, 10,996,167 shares of its common stock, par value $0.001
per share (its only class of voting or non-voting common equity) were held by
non-affiliates of the registrant. The market value of those shares
was $6,047,891, based on the last sale price of $0.55 per share of common stock
on that date. For this purpose, shares of common stock beneficially
owned by each executive officer and director of the registrant and each
beneficial owner of 10% or more of the common stock outstanding have been
excluded because such persons may be deemed to be affiliates. This
determination of affiliate status is not necessarily a conclusive determination
for other purposes.
As of
April 14, 2010, there were 32,257,472 shares of the registrant’s common stock
issued and outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
None.
TABLE
OF CONTENTS
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Item
Number and Caption
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Page
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Forward-Looking
Statements
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3
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PART
I
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4
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1.
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Business
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4
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1A.
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Risk
Factors
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36
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1B.
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Unresolved
Staff Comments
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59
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2.
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Properties
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59
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3.
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Legal
Proceedings
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61
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4.
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Submission
of Matters to a Vote of Security Holders
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62
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PART
II
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62
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5.
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Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
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62
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6.
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Selected
Financial Data
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65
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7.
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Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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65
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8.
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Financial
Statements and Supplemental Data
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86
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9.
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Changes
in and Disagreements with Accountants on Accounting, and Financial
Disclosure
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86
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9A.[T]
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Controls
and Procedures
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86
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9B.
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Other
Information
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87
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PART
III
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88
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10.
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Directors,
Executive Officers, and Corporate Governance
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88
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11.
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Executive
Compensation
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90
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12.
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Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
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93
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13.
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Certain
Relationships and Related Transactions
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93
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14.
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Principal
Accountant Fees and Services
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94
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PART
IV
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95
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15.
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Exhibits
and Financial Statement Schedules
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95
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2
FORWARD-LOOKING
STATEMENTS
Forward-looking
statements are subject to risks and uncertainties that may change at any time,
and, therefore, our actual results may differ materially from those that we
expected. The forward-looking statements contained in this Annual Report are
largely based on our expectations, which reflect many estimates and assumptions
made by our management. These estimates and assumptions reflect our best
judgment based on currently known market conditions and other factors. Although
we believe such estimates and assumptions are reasonable, we caution that it is
very difficult to predict the impact of known factors and it is impossible for
us to anticipate all factors that could affect our actual results. In addition,
management’s assumptions about future events may prove to be
inaccurate. Management cautions all readers that the forward-looking
statements contained in this Annual Report are not guarantees of future
performance, and we cannot assure any reader that such statements will be
realized or the forward looking events and circumstances will
occur. Actual results may differ materially from those anticipated or
implied in the forward-looking statements due to the factors described in the
“Risk Factors” section and elsewhere in this Annual Report. All
forward-looking statements are based upon information available to us on the
date of this Annual Report. We undertake no obligation to update or revise any
forward-looking statements as a result of new information, future events or
otherwise, except as otherwise required by law.
In this
Annual Report, unless the context requires otherwise, references to the
“Company,” “Crownbutte,” “we,” “our” and “us” refer to Crownbutte Wind Power,
Inc., a publicly traded Nevada corporation formerly known as ProMana Solutions,
Inc., together with its subsidiaries, including Crownbutte Wind Power, Inc., a
North Dakota corporation (“Crownbutte ND”).
3
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ITEM
1.
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BUSINESS
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Overview
of Our Business
Crownbutte
ND was founded in 1999 by our Chief Executive Officer, Timothy H. Simons, with
the goal of addressing the requirements of regional utility companies to satisfy
increasing renewable energy demands. We develop wind parks from green
field to operation, which we have sold to regional utilities. One
park developed by us was purchased directly by Basin Electric Power Cooperative
(2.6 megawatts (MW) near Chamberlain, South Dakota). We also
developed a 20 MW, expandable to 50 MW, project in Baker, MT, which was sold at
late brownfield stage to Montana-Dakota Utilities. In addition to
these two operating parks, we have completed various consulting activities with
regional utilities and international energy companies. Our ultimate
goal is to develop, own and operate merchant wind parks in the 20 to 60 MW
capacity range. Currently, we have 12 projects totaling approximately
638 MW (0 MW currently in operation) of prospective capacity in various phases
of development primarily in North Dakota, South Dakota and Montana, with a total
of over 40,000 acres under lease option. See
“Properties.” Our project management team is also exploring other
opportunities in this region.
Our
principal executive offices are located at 111 5th Avenue NE, Mandan,
ND 58554, and our telephone number is (701) 667-2073. Our
website address is
www.crownbutte.com
.
Recent
Developments
Earlier
this year, the Company was notified by the Midwest Independent Systems Operator
(MISO) that two of our projects were fast-tracked through the interconnection
queue. The two projects, in Elgin, ND and Wibaux, MT, were the only
projects fast-tracked by MISO out of nearly 150 projects in the
region. Fast-tracking status increased the likelihood the Company
would receive an interconnection agreement and be positioned to obtain financing
and begin construction of those projects by the end of 2010 or early
2011. Both of these 20 MW projects may qualify for the U.S. Treasury
Department renewable energy grant program created by the American Recovery and
Reinvestment Act of 2009 (discussed elsewhere in this report), if an
interconnection agreement is received, financing obtained, and at least 5% of
construction begins before December 31, 2010. The grant amount for
most wind projects is equal to 30% of the authorized capital costs of the
project. These projects have entered the final definitive planning
study of the transmission interconnection process, and we expect to obtain
interconnection agreements by fall 2010.
As
indicated in the accompanying consolidated financial statements and Management’s
Discussion and Analysis of Financial Condition and Results of Operations section
of this report, on February 15, 2010, the Company executed a non-binding term
sheet with a private equity firm to provide $37.5 million debt financing for the
Gascoyne I project. Terms of the financing would provide for an 80%
ownership interest to the lender with the Company retaining a 20% stake in the
special-purpose entity. The consummation of this financing is subject
to, among other things, satisfactory completion by the lender of all necessary
technical and legal due diligence and satisfactory negotiation of all required
definitive agreements necessary or desirable to effect the
transaction. We anticipate a construction completion and operational
date by the end of 2010 or early 2011.
4
Corporate
Information and History
We were
incorporated in the State of Nevada on March 9, 2004, under the name ProMana
Solutions, Inc. As ProMana Solutions, our business was to provide
web-based, fully integrated solutions for managing payroll, benefits, human
resource management and business processing outsourcing to small and medium
sized businesses. Following the merger described below, we are no
longer in that web services business.
On July
2, 2008, we amended our Articles of Incorporation to change our name to
Crownbutte Wind Power, Inc.
Crownbutte
ND was formed as a North Dakota limited liability company on May 11,
1999. On May 19, 2008, Crownbutte ND was converted to a North Dakota
corporation.
On July
2, 2008, a special purpose acquisition subsidiary formed by us merged with and
into Crownbutte ND, with Crownbutte ND surviving the merger, thereby becoming
our wholly-owned subsidiary. Following the merger, we continued
Crownbutte ND’s business operations. In connection with the merger,
we changed our name to Crownbutte Wind Power, Inc. Upon the closing of the
merger, the holders of all of the issued and outstanding shares of Crownbutte ND
surrendered all of their shares and received shares of our common stock on a
one-to-one basis. Also on the closing date, holders of issued and
outstanding warrants to purchase shares of Crownbutte common stock received new
warrants to purchase shares of our common stock, also on a one-to-one
basis.
Pursuant
to the merger, we ceased operating as a provider of web-based, fully integrated
solutions for managing payroll, benefits, human resource management and business
processing outsourcing, and acquired the business of Crownbutte ND to develop
wind parks from green field to operation and has continued Crownbutte ND’s
business operations as a publicly-traded company.
At the
closing of the merger, each share of Crownbutte ND’s common stock outstanding
was converted into one share of our Common Stock. As a result, an
aggregate of 18,100,000 shares of our Common Stock were issued to the holders of
Crownbutte ND’s common stock. In addition, warrants to purchase an
aggregate of 10,600,000 shares of Crownbutte ND’s outstanding at the time of the
merger became warrants to purchase an equivalent number of shares of our Common
Stock.
The
merger agreement contains a provision for a post-closing adjustment to the
number of shares of our Common Stock issued to the former Crownbutte ND
stockholders, in an amount up to 2,000,000 shares of our Common Stock, to be
issued on a
pro rata
basis for any breach of the Merger Agreement by us, discovered during the
one-year period following the closing. In order to secure the
indemnification obligations of Crownbutte ND under the merger agreement, 5% of
the shares of our Common Stock to which the former Crownbutte ND stockholders
are entitled in exchange for their shares of Crownbutte ND in connection with
the Merger will be held in escrow for a period of one year.
5
The
merger agreement contained customary representations and warranties and pre- and
post-closing covenants of each party and customary closing
conditions. Breaches of the representations and warranties will be
subject to customary indemnification provisions.
The
merger was treated as a recapitalization of the Company for financial accounting
purposes. Crownbutte ND is considered the acquirer for accounting purposes, and
our historical financial statements before the merger have been replaced with
the historical financial statements of Crownbutte ND before the merger in all
subsequent filings with the Securities and Exchange Commission.
The
parties have taken all actions necessary to ensure that the merger is treated as
a tax-free exchange under Section 368(a) of the Internal Revenue Code of 1986,
as amended.
Contemporaneously
with the merger, the then-existing assets and liabilities of the Company were
transferred to Pro Mana Technologies, Inc., a New Jersey corporation, which at
that time was a wholly-owned subsidiary of the
Company. Contemporaneously with the merger, we transferred all of the
outstanding capital stock of Pro Mana Technologies to certain pre-merger
shareholders of the Company in exchange for the surrender and cancellation of an
aggregate of 144,702 shares of our common stock and warrants to purchase 19,062
shares of our common stock held by those stockholders and certain covenants and
indemnities. We no longer own Pro Mana Technologies.
On July
31, 2008, we effected a reverse stock split, as a result of which each 65.723
shares of our common stock (including those issued in connection with the
merger) then issued and outstanding were converted into one share of our common
stock. Unless otherwise stated herein or the context clearly
indicates otherwise, all share and per share numbers in this prospectus relating
to our common stock have been adjusted to give effect to the reverse stock
split.
General
Philosophy
We have
developed what we believe is a unique process for bringing viable wind parks to
market. While most developers have focused on large projects of 100
MW or more, we have found a niche in the 20-60 MW range. Our focus
will be to bring these smaller parks from concept to operation. The
project sites currently in development by us are located directly on some of the
most ideal wind regimes in the country, with net capacity factors of up to
forty-six percent (46%). These above-average net capacity factors
have a significant impact on the amount of electricity that can be generated and
therefore on future revenues.
Net
capacity factor is one element used in measuring the productivity of a wind
turbine, wind energy project or any other power production
facility. It compares the turbine’s production over a given period of
time with the amount of power the turbine could have produced if it had run at
full capacity for the same amount of time.
|
Amount
of power produced over time (usually measured annually)
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Net
Capacity Factor =
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Power
that would have been produced if turbine operated at full capacity 100% of
the time over the same period of
time
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6
Net
capacity factors are calculated using the following inputs:
|
1)
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The
power curve for the specific turbine that is being used at a given project
site. This comes from the turbine manufacturer and varies
between turbine types.
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2)
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The
wind velocity distribution (Weibull Distribution) at the site of a given
project. This comes from a statistical analysis of the
meteorological data gathered from our proprietary meteorological towers
erected at the site over the course of several years and confirmed with
existing meteorological information from very long term weather stations
and airport and other meteorological towers near the
site.
|
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3)
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A
mathematical model of the wind shear which allows us to extrapolate the
wind speed data gathered from our meteorological towers at three different
heights up to the specific hub-height of the wind turbine
generator.
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4)
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Estimates
of a number of known losses that are incurred during wind turbine
operations. In particular, these
are:
|
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·
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Topographic
efficiency
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·
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Electrical
efficiencies
|
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·
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Availability
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·
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Array
losses
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·
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Icing
and blade degradation
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·
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Substation
maintenance
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·
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Utility
downtime
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·
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Power
curve turbulence variation
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·
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Sector
management
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We
utilize proprietary computer software which incorporates each of these inputs
for a given project site and returns the net capacity factor as its
output.
This
capacity factor is then verified against the net capacity factor calculated by
an independent Certified Consulting Meteorologist (CCM) who is contracted for
each project so that the net capacity factors are certified as correct and thus
can be used in our interconnection requests and financing
negotiations.
When our
results differ from those of the Certified Consulting Meteorologist, it is due
to different estimates in the above list of inputs. For example, the
CCM may use a different Hellman exponent in the wind shear model than we do, or
they may use different estimates of the loss factors. In these cases,
the CCM net capacity factor is assumed to be correct, and we adjust our input
assumptions to conform with those of the CCM.
Our net
capacity factor projections are subject to change and are not intended to
predict the wind at any specific time over the turbine’s 20-year useful
life. Even if our predictions of a wind energy project’s net capacity
factor become validated over time, the energy projects may experience hours,
days, months, and even years that are below our wind resource
projections.
7
Our focus
on smaller projects allows us to install parks where developers of larger
projects would be at a disadvantage, because smaller projects more easily fit
into the current transmission grid, which decreases the costs of upgrading
downstream components. While small projects are the focus of our
strategy, we have not ruled out the possibility of larger projects.
Our
business model focuses on the development of merchant parks. We do
not plan to enter into power purchase agreements (PPAs) unless they are offered
on favorable terms. Currently in the upper Midwest, with the
exception of Minnesota, power purchase agreements tend to be difficult to
obtain. When power purchase agreements are available, they tend to be
at a price per kilowatt hour (kWh) that is less than the market price of
electricity. Merchant parks sell electricity on the open
market. Based on spot prices for electricity over the past five
years, our merchant parks would have received on average $0.042 per
kWh. Selling power on the open market increases the risk of the
projects. However, based on U.S. Department of Energy forecasts and
our own analysis, we believe that over the next decade the market price of
electricity will continue to increase and that this merchant model will allows
us to capture that upside potential.
In the
past, we have been developing and then selling wind parks, in some cases
remaining as a consultant for the party that purchased the park. We
plan to continue to sell developments as a part of our ongoing business, but we
intend to shift the focus of our business towards ownership and operation of
merchant wind parks that we develop. We believe that this will allow
us to grow our balance sheet and increase cash flow.
We intend
to develop sites from “green field” (or blank slate) at a rate of approximately
two to three additions to our pipeline per year, with each site likely to reach
operation in approximately three years.
The first
wind park that we plan to build, own and operate is a 20 MW project called
Gascoyne I located south of Dickinson, North Dakota. As stated
elsewhere in this report and the accompanying notes to audited consolidated
financial statements, financing for the Gascoyne I park is pending due diligence
and final approval by the lender and satisfactory negotiation of all required
definitive agreements pursuant to a non-binding term sheet. Our goal is to
have approximately 20 MW of owned operating capacity by the end of 2010 or early
2011, and we target the construction and commissioning of approximately 40 MW of
owned operating capacity annually thereafter. We do not currently and do not
plan to act as an operator of wind parks we do not own.
To
successfully develop, build and own wind parks, and to acquire other
developments or make business acquisitions, we will need to raise
capital. We plan to raise approximately $1 million through private
placements of equity by the end of 2010, the proceeds of which, together with
cash on hand, will be used for general corporate expenses associated with the
hiring of new staff required to accelerate our development activities, as well
as move into our new owner-operator business model, which requires oversight of
construction of projects, as well as the operations and maintenance of projects
after construction is complete.
We
anticipate that we will need to arrange turbine supply loans to finance
approximately 60 to 90% of the cost of a project’s turbines. After we
have developed a wind energy project that we intend to own to the point where we
are prepared to commence construction, we will need to raise construction
financing to retire turbine indebtedness and to pay construction
costs. Construction loans are generally secured by the project’s
assets and our equity interests in the project companies. In certain
instances we may enter into a construction loan for a single project, while in
other instances we may be able to finance multiple projects through a single
credit facility. We will also use equity capital contributions (our
own and potentially from other investors as described above) to fund a portion
of each project’s construction costs.
8
It is
important to note that we do not plan to enter into PPAs, unless they are
offered at a favorable rate. Instead, we will be selling our
electricity on the open market. This is a deviation from the standard
business model of wind parks, where a PPA is entered into to guarantee a price
for a period of time. In our geographic areas, utilities generally
have not been interested in PPA agreements, except at unattractive
rates. We believe we will benefit from the sale of electricity in the
merchant model because of the higher average price relative to what would be
offered by a utility.
Our
growth strategy is focused on developing parks from green field to
operation. Our project management team is constantly exploring new
opportunities in the North Dakota, South Dakota and Montana area that appear to
be optimal sites. For our business strategy to work, new locations
with excellent potential must continually be found and developed. In
addition to green field developments, we are constantly analyzing the late stage
developments of other wind developers. If a project appears to be
feasible, we will pursue the purchase of the park. The value of a
wind project and the expected level of returns are a function of the electricity
that can be produced and its expected sales value over the lifetime of a wind
farm. As the probability of a viable project reaching operation
increases the market value also increases for that project. Key parts
of the development stage, such as acceptable wind data, an interconnection
agreement and a power off take solution, add the most value to the development
process.
Each
project has a value as it progresses, and projects can be sold at any stage of
development. In our experience, prices for projects under development
can range from $10,000 a MW for an early development stage project to $150,000 a
MW for a project ready to begin construction. Developers looking to
sell development stage projects will usually receive a higher price per MW for
the sale of an entire pipeline of projects.
We are
proceeding with development of our project portfolio. These projects
are in various stages of development with the most advanced project ready to
begin construction. We have focused on siting projects to fit the
existing transmission grid so that our projects will not be subject to major
upgrade costs or delayed because the need for additional transmission
lines. As a result of our “size to fit” emphasis we have a number of
small to mid size projects spaced out across North Dakota, South Dakota and
Montana. Another key aspect of the Crownbutte development process is
our emphasis on obtaining land control and wind data prior to starting the
interconnection studies. Completing this work prior to the
interconnection studies increases the probability that a project will be
successful if an interconnection agreement is secured.
Development
carries significant risk. In total, the process of site development
can take up to five years and cost $200,000 to $300,000. Every step
in the development process must be met precisely to prevent project
failure. As the project completes each step in the development
process the risk of the project decreases.
9
Our
development strategy has several phases, and each phase adds value as a site is
developed. The development phase involves all the preparation for
park installation, up to but not including construction. The steps of
wind park development, construction and operation are listed below:
|
1.
|
Identify
the transmission capacity
suitable for a specific-sized park within
the large but widely scattered transmission system. By starting
with the available transmission capacity we decrease the risk of adverse
transmission system upgrade costs.
|
|
2.
|
Conduct
topographical studies
to determine the most promising locations by
using the available meteorological data. We use this
information to determine the anticipated energy production and associated
project economics.
|
|
3.
|
Configure
an initial park array
to determine the parameters of the park with
regard to transmission capability.
|
|
4.
|
Procure the
necessary land lease options
under the park’s
footprint.
|
|
5.
|
Install
site-specific meteorological instrumentation,
which is always
necessary to obtain site specific meteorological data. In some
cases a meteorological tower is already on site, and historic data is
therefore available. In most cases we will erect a
meteorological tower for meteorological
observation.
|
|
6.
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Accumulate
sufficient meteorological
data.
|
|
7.
|
Select
turbine type
based on performance factors, availability and
financeability.
|
|
8.
|
Prepare a
wind report
. Once sufficient meteorological data has
been accumulated we will retain a certified consulting meteorologist to
prepare a financeable wind report by a certified consulting meteorologist,
which validates that the wind regime will support the project cash flow
model.
|
|
9.
|
Apply for
local, state and federal permitting and transmission queue
position.
The permitting
requirements for a project depend to a large extent on the location of the
project. However, there are normally permitting considerations
for zoning laws, wildlife protection, historical sites and use of air
space.
|
|
10.
|
Secure
interconnect agreements with utility and systems
operator.
Upon completion of the necessary system
studies that follow an interconnection application we will know the
upgrades necessary to tie into the transmission grid. Upon
signing of an interconnection agreement we will be allowed to use the
transmission grid to sell or wheel
electricity.
|
|
11.
|
Prepare
site design.
Prior to construction, we will prepare the
site design, which includes the geotechnical studies for the
foundations.
|
|
12.
|
Execute
turbine supply agreement.
The turbine supply agreement
dictates the relationship between the developer and a turbine
manufacturer. It includes the turbine delivery time lines and
the warranties on the turbines the manufacturer will
provide.
|
10
|
13.
|
Retain
construction subcontractors for each piece of the
construction
. These include high voltage work, crane
use, access road construction, pouring of foundations, and all other
necessary steps to complete the
park.
|
|
14.
|
Prepare
final site designs
, including design of the high voltage systems,
service roads, junction boxes, etc.
|
|
15.
|
Finalize
project financing.
Prior to construction the necessary
arrangements for both construction financing and financing for the
operational project must be secured. The financing normally
includes some mix of developer equity, production tax credit (PTC) equity,
and debt.
|
|
16.
|
Order long
lead-time items
such as the main step-up transformer and substation
steel.
|
|
17.
|
Construction
. Subcontractors
will undertake all construction activities with oversight by us and the
turbine manufacturer’s engineers. Construction on a 20 MW park
generally takes 6-12 months. The majority of costs in
developing a park are recognized during the construction
phase.
|
|
18.
|
Turbine
Commissioning.
Once the turbines are erected, they will
be tested for performance in line within the manufacturer’s
specification. It the tests show the turbine is operation
properly is will be commissioned and begin commercial
operation.
|
|
19.
|
Operation
& Maintenance
. We will manage the operation of the
project upon its commercial
operation.
|
Our
current pipeline of projects includes 12 projects totaling 638 MW (0 MW
currently in operation) of potential capacity.
Buyers
of Wind Parks
The mix
of potential buyers changes as the size of wind projects
increases. Different players in the market place only become
interested when capital requirements for a project reach a certain
level. Larger players need size to justify the time and expense
required to construct or acquire projects. Smaller projects in the
single to high teens of total megawatt output are usually owned by several
different types of parties for specific reasons. Municipalities will
purchase two to ten MW to generate some of their electricity needs from a
renewable energy source. Utilities can also own small projects,
usually as a result of a state mandate which requires the utility to generate a
percentage of their electricity from renewable energy. In other cases
a municipality may have a mandate to support community wind
projects.
11
The
midsize projects have the largest spectrum of potential buyers. These
projects can range from 20 to 200 MW in size. Midsize projects
benefit from economies of scale, and the projects become economically viable
without the assistance of state mandates. Midsize projects are also
more likely to fit into the existing transmission grid. As the
projects get larger, the likelihood of needing substantial system upgrades
increases. Midsize projects have a number of possible investors,
ranging from utilities to financial institutions. Utilities generally
prefer the midsize projects because they provide the generation necessary to
address renewable energy portfolio standards, without buying more generation
than is required. Financial institutions are attracted to the midsize
projects because they are the right size for an efficient capital
campaign. The projects are big enough that raising capital is worth
their time and expense, but also the projects are small enough that an
institution will not be over-exposed to the risks of one
project. When a company is looking to create a portfolio of renewable
energy assets, the midsize projects are most ideally suited to allow for
diversification across geographic area, transmission systems and
technology. According to the American Wind Energy Association, the
average utility-scale wind project size in America is 60 MW. We are
focusing on projects in the 20 to 60 MW range.
Large
projects are 200 MW and greater. Only the biggest developers and
financial institutions have an appetite for these projects. The
capital requirements for these projects are upwards of $400
million. These projects are only viable when new transmission is
being constructed specifically for the project or some other special arrangement
for transmission is in place.
Wind
Turbine and Construction Materials Supply
The
growth of our business is dependent on the availability of turbines and turbine
financing. Wind energy projects require delivery and assembly of
turbines. Supply and logistical issues are of the utmost importance
when developing a wind park. Over the past couple of years, demand
for turbines has softened due to the 2008 financial market
crisis. The industry is beginning to turn around and the rate of
construction of projects has increased since the implementation of the U.S.
Treasury Department renewable energy grant program as part of the American
Recovery and Reinvestment Act of 2009. We have been contacted by
various developers who have excess turbines at discounted prices and are
evaluating the feasibility of purchasing some of these turbines with limited or
no warranty. We are also looking at quotes from GE and from Gamesa
(both established suppliers), as well as from DeWind (a newer entrant into the
U.S. wind turbine market) and ACCIONA, for new turbines. We have seen
some evidence of softening turbine prices and shorter delivery lead times as the
financial market turmoil during the autumn of 2008 has slowed the installation
of new wind capacity. We expect that the turbines we require for our
project development schedule will be available on a timely basis provided that
we are able obtain turbine financing. We may work with several
turbine suppliers to meet our turbine needs.
In
addition, spare parts for wind turbines and key pieces of electrical equipment
will need to be available for the turbines we have in operation. When
we purchase our turbines, we also enter into warranty agreements with the
manufacturer. Along with turbines and electrical equipment, other
construction materials, such as gravel, cement, and rebar are necessary for the
construction of roads and foundations. The combination of all these
issues makes it essential for us to maintain working relationships with all of
our suppliers.
Demand
for Electricity
The
demand for electricity in the U.S. has been steadily increasing. It
is estimated that demand for electricity will increase by 1.1% per year,
resulting in over 5 billion kWh demanded by 2030 (U.S. Department of Energy
Annual Energy Outlook 2008). According to the same source, the retail
price of electricity is also expected to rise to an average price of 9.3 cents
per kWh by 2009 (adjusted to 2006 dollars), and stabilize at a slightly lower
level of 8.5 cents per kWh, or 14.2 cents in nominal currency.
12
As the
U.S. continues in recession, all prices in the economy, including the price of
electricity, will experience downward pressure. To the extent that
Crownbutte intends to use open market venues (
i.e.
, the “merchant” markets)
to sell power, variability of electricity prices are a risk to profitability in
the short term. Over the long term, the demand for electricity is
driven by the number of consumers, the numbers of electricity-powered devices
employed and the efficiency of those devices. There is indication that the U.S.
economy is beginning to recover, although demand for electricity and increases
in price may remain relatively flat for months, and potentially years to
come.
The
population of the U.S. continues to grow, and the popularity of electrical and
electronic appliances has also continued to grow. In addition, there
are trends that hint at the possibility of widespread adoption of electric cars
and plug-in hybrids in the U.S. in coming years. While we expect the
efficiency of all devices to improve over time (with innovation), we expect that
the growing population, the popularity of consumer electronics, and the possible
growth of electric vehicles to all combine to keep the price of electricity
stable and growing moderately over time.
Industry
Overview
Renewable
energy is produced using resources that are naturally replenished, such as wind,
sunlight, geothermal heat, tides and biofuels. Technologies that
produce energy from these renewable sources (other than biofuels) are often
referred to as “clean” or “green” as they produce few, if any, pollutants that
negatively impact the environment. Comparatively, fossil fuels such
as coal, natural gas and oil are exhaustible and release greenhouse gases such
as carbon dioxide or other pollutants into the atmosphere during energy
production. As a result of increased environmental awareness, the
deployment of renewable energy technologies has grown rapidly during the past
several years. According to the Energy Information Administration,
37% of new U.S. power generation capacity in 2007 consisted of renewable
technologies, compared with only 2% in 2003. This increase is
expected to continue, with the American Council on Renewable Energy forecasting
renewable energy capacity to grow by a compounded annual growth rate between 9%
and 11% through 2025, yielding a potential 550,000-700,000 MW of additional
renewable capacity. At this rate, the United States could supply 25% of its
electrical energy requirements with renewable energy by 2025.
13
According
to the U.S. Department of State, wind energy is the fastest-growing renewable
energy generation technology worldwide due to its cost efficiency, technological
maturity and the wide availability of wind resources. We believe that
it has the greatest potential among all renewable energy technologies for
further growth in the United States. Although the United States has
hydroelectric and geothermal resources, many potential hydroelectric sites have
already been developed and geothermal production is confined by geographical
limitations to only certain areas of the United States. In contrast,
according to the American Wind Energy Association, or AWEA, the available
untapped wind resources across the United States remain
vast. Additionally, other renewable energy technologies, such as
solar power, are currently less economically attractive than wind energy, and
others, such as biofuels, emit particulates which have a greater negative impact
on the environment than wind energy.
Growth
in U.S. Wind Energy
We
believe that the growth in U.S. wind energy will continue due to a number of key
factors, including:
|
|
●
|
Increases
in electricity demand coupled with the rising cost of fossil fuels used
for conventional energy generation resulting in increases in electricity
prices;
|
|
|
●
|
Heightened
environmental concerns, creating legislative and popular support to reduce
carbon dioxide and other greenhouse
gases;
|
|
|
●
|
Regulatory
mandates, such as state renewable portfolio standard programs, as well as
federal tax incentives including production tax credits and accelerated
tax depreciation;
|
|
|
●
|
Improvements
in wind energy technology;
|
|
|
●
|
Increasing
obstacles for the construction of conventional fuel plants;
and
|
|
|
●
|
Abundant
wind resources in attractive energy markets within the United
States.
|
From its
beginnings in California, wind energy in the United States has expanded steadily
to 36 of the 50 states. As depicted on the maps below, the total
installed capacity of U.S. wind parks increased by over 680% from 2,500 MW to
over 19,500 MW between December 1999 and June 2008.
14
Source
for December, 1999: U.S. Department of Energy.
Source
for June, 2008: American Wind Energy Association.
According
to the American Wind Energy (AWEA) 2009 Annual Wind Report, installed U.S. wind
capacity increased by 8,545 MW (50.8%) in 2008 and by 5,249 MW (45.3%)
in 2007. Despite this growth, wind energy generation still only
represented just 1.26% of U.S. electricity supply in 2008, and we believe that
the prospects for further growth are very favorable. Additionally, in
May 2008, the U.S. Department of Energy published a feasibility report
discussing the potential for wind power to provide up to 20% of U.S. electricity
needs by 2030, which would require over 300,000 MW of cumulative installed
wind capacity to meet this target.
Increases
in Electricity Demand Coupled with the Rising Cost of Fossil Fuels Used for
Conventional Energy Result in Increases in Electricity Prices
The
demand for electricity has historically exhibited steady growth and has
increased by a cumulative amount of 23% or 728 billion kWh from 1995
through 2007. According to the Energy Information Administration,
electricity demand in the United States is forecasted to continue to grow at a
steady long-term rate with a cumulative increase from 2007 through 2030 of
32%. Most of this demand has historically been supplied by coal- or
natural gas-fired power plants, which accounted for 49% and 21%, respectively,
of U.S. electrical power generation in 2007. In New York, New
England, Texas and California, natural gas accounts for a significant portion of
the electricity production, and this high usage, combined with the increased
presence of natural gas-fired power plants, has made it the fuel that determines
the price of power in these markets.
15
We
believe that the significant volatility in commodity fuel prices has spurred
demand for alternative fuels such as wind energy, although recent drops in
natural gas prices may reduce some of this demand in the short
term. The following two charts are indicative of the volatility in
oil and gas prices in recent years.
Price
of Crude Oil and Natural Gas
Monthly
Average Spot Prices of West Texas Intermediate (WTI) Crude Oil, US$ per Barrel
(through August 2009) – source: The Wall Street Journal
16
Monthly Average U.S. Natural Gas
Price for Electric Power, US$ per thousand cubic feet (through May 2009) –
source: U.S. Energy Information Administration
The
following tables illustrate the price increases in retail electricity in the
United Sates as a whole and in North Dakota.
Annual average retail electricity
price, United States
–
source: U.S. Energy Information
Administration
17
Annual average retail electricity
price, North Dakota
–
source: U.S. Energy Information
Administration
Wind
energy, which has no fuel costs, has become much more competitive by comparison
to traditional electricity generation sources, and has grown dramatically
relative to other non-hydroelectric renewable sources (including biofuels,
geothermal and solar) in recent years, as shown in the following two
charts.
Comparative
Cost of Electric Power Generation
Source:
National Association of Regulatory Utility Commissioners. For each generation
source, cost is calculated by taking the mid-point of the range described in the
report by Lazard — “Levelized Cost of Energy Analysis —
Version 2.0,” June 2008
18
United
States Wind Generation Growth
Source:
Energy Information Administration
Non-hydro
renewables consist of wind, solar, geothermal and biomass.
Wind
energy also offers an attractive method of managing commodity price risk while
maintaining strict environmental standards, as it provides a stable, affordable
hedge against the risk of increases in the price of coal, natural gas and other
fuels over time. Increasing the use of wind energy also has the
implied benefit of lowering overall demand for natural gas, particularly during
winter peak demand.
We
believe that concern over the recent volatility in fuel prices in the United
States, coupled with the country’s significant dependence on fossil fuels, has
been and will continue to be a factor in the political and social movement
towards greater use of clean energy.
Heightened
Environmental Concerns, Creating Legislative and Popular Support to Reduce
Carbon Dioxide and Other Greenhouse Gases
The
growing concern over global warming caused by greenhouse gas emissions has also
contributed to the growth in the wind energy industry. According to
the Intergovernmental Panel on Climate Change Fourth Assessment Report, experts
have noted that eleven of the last twelve years (1995-2006) rank among the
warmest years since 1850. Additionally, the global average sea level
has risen at an average rate of 1.8 millimeters per year since 1961 and at 3.1
millimeters per year since 1993, due to the melting of glaciers, ice caps and
polar ice sheets, coupled with thermal expansion of the oceans. The
importance of reducing greenhouse gases has been recognized by the international
community, as demonstrated by the signing and ratification of the Kyoto
Protocol, which requires reductions in greenhouse gases by the 177 (as of March
2008) signatory nations. While the United States did not ratify the
Kyoto Protocol, state-level initiatives have been undertaken to reduce
greenhouse gas emissions. California was the first state to pass
global warming legislation, and ten states on the east coast have signed the
Regional Greenhouse Gas Initiative, which proposes to require a 10% reduction in
power plant carbon dioxide emissions by 2019.
Substituting
wind energy for traditional fossil fuel-fired generation would help reduce CO2
emissions due to the environmentally-friendly attributes of wind
energy. According to the Energy Information Administration, the
United States had the highest CO2 emissions of all countries in the world in
2005, contributing approximately 20% of the world’s CO2
emissions. Since 1990, CO2 emissions from the United States’ electric
power industry have increased by a cumulative amount of 27%, from
1.9 billion metric tons to 2.5 billion metric tons.
19
Indexed
Electric Power Industry CO
2
Emissions:
1990–2006
Source:
Energy Information Administration
1990:
100% = 1.9 Billion Metric Tons of CO2
Environmental
legislation and regulations provide additional incentives for the development of
wind energy by increasing the marginal cost of energy generated through
fossil-fuel technologies. Such legislation and regulations have been
designed to, for example, reduce ozone concentrations, particulate emissions,
haze and mercury emissions and can require conventional energy generators to
make significant expenditures, implement pollution control measures or purchase
emissions credits to meet compliance requirements. These measures
have increased fossil fuel-fired generators’ capital and operating costs and put
upward pressure on the market price of energy. Because wind energy
producers are price takers in energy markets, these legislative measures
effectively serve to make the return on wind energy more attractive relative to
other sources of generation.
We
believe there is significant support in the United States to enact legislation
that will attempt to reduce the amount of carbon produced by electrical
generators. Although the ultimate form of legislation is still being
debated, the two most likely alternatives are (i) a direct emissions tax or
(ii) a cap-and-trade regime. We believe either of these
alternatives would likely result in higher overall power prices, as the marginal
cost of electricity in the United States is generally set by carbon intensive
generation assets which burn fossil fuels such as oil, natural gas and
coal. As a non-carbon emitter and a market price taker, we are
positioned to benefit from these higher power prices.
Regulatory
Mandates, Such as State Renewable Portfolio Standard Programs, as Well as
Federal Tax Incentives Including Production Tax Credits and Accelerated Tax
Depreciation
Growth in
the U.S. wind energy market has also been driven by state and federal
legislation designed to encourage the development and deployment of renewable
energy technologies. This support includes:
|
●
|
Renewable Portfolio
Standards.
In response to the push for cleaner power
generation and more secure energy supplies, many states have enacted
renewable portfolio standard programs. These programs either
require electric utilities and other retail energy suppliers to produce or
acquire a certain percentage of their annual electricity consumption from
renewable power generation resources, or, as the case in New York,
designate an entity to administer the central procurement of renewable
energy certificates for the state. Wind energy producers
generate renewable energy certificates due to the environmentally
beneficial attributes associated with their production of
electricity.
|
20
The
number of states with renewable portfolio standard programs has doubled in the
last six years and as of August 2008, 32 states and the District of Columbia had
adopted some form of renewable portfolio standard program. The
District of Columbia and 26 of the 32 states have mandatory renewable portfolio
standard requirements and combined, these 26 states represent over 50% of total
U.S. electrical load. A number of states, including Arizona,
California, Colorado, Massachusetts, Nevada, New Jersey, New Mexico and Texas
have been so successful in meeting their original renewable portfolio standard
targets that they have revised their programs to include higher
targets. Among the states in which we currently have projects, Texas
and Montana have renewable portfolio standards. Other states such as
Missouri, North Dakota, South Dakota, Utah, Vermont and Virginia have adopted
state goals, which set targets, not requirements, for certain percentages of
total energy to be generated from renewable resources. The states
that have adopted renewable portfolio standard programs or set state goals, as
well as the related requirements or targets, are set forth in the following
map.
U.S.
Renewable Portfolio Standard Programs and Goals for Renewable Energy
Generation
Source:
Database of State Incentives for Renewables & Efficiency, August
2008.
|
|
1.
|
RE
– Renewable Energy.
|
|
|
2.
|
IOUs
– Investor-Owned Utilities.
|
|
|
3.
|
Xcel
– Xcel Energy, an electric and gas company that operates in the
Midwest.
|
|
|
4.
|
Class
I Renewables – Electricity derived from solar, wind, wave or tidal action,
geothermal, landfill gas, anaerobic digestion, fuel cells using renewable
fuels, and certain other forms of sustainable
biomass.
|
|
|
5.
|
Co-op
– Customer-owned electric utility that distributes electricity to its
members.
|
|
|
6.
|
Munis –
Municipalities.
|
|
●
|
Almost
every state that has implemented a renewable portfolio standard program
will need considerable additional renewable energy capacity to meet its
renewable portfolio standard requirements. Much of Emerging
Energy Research’s forecasted 50,000 MW of installed wind capacity by 2015
will be driven by current and proposed renewable portfolio standard
targets, along with additional demand from states without renewable
standards.
|
21
|
●
|
Renewable Energy Certificates
(“RECs”).
A renewable energy certificate is a
stand-alone tradable instrument representing the attributes associated
with one MWh of energy produced from a renewable energy
source. These attributes typically include reduced air and
water pollution, reduced greenhouse gas emissions and increased use of
domestic energy sources. Many states use renewable energy
certificates to track and verify compliance with their renewable portfolio
standard programs. Retail energy suppliers can meet the
requirements by purchasing renewable energy certificates from renewable
energy generators, in addition to producing or acquiring the electricity
from renewable sources. Under many renewable portfolio standard
programs, energy providers that fail to meet renewable portfolio standard
requirements are assessed a penalty for the shortfall, usually known as an
alternative compliance payment. Because renewable energy
certificates can be purchased to satisfy the renewable portfolio standard
requirements and avoid an alternative compliance payment, the amount of
the alternative compliance payment effectively sets a cap on renewable
energy certificate prices. In situations where renewable energy
certificate supply is short, renewable energy certificate prices approach
the alternative compliance payment, which in several states is in the
$50-$59/MWh range. As a result, renewable energy certificate
prices can rival the price of energy and renewable energy certificates can
represent a significant additional revenue stream for wind energy
generators.
|
|
●
|
Production Tax
Credits.
The production tax credit provides wind energy
generators with a credit against federal income taxes, annually adjusted
for inflation, for a duration of ten years from the date that the wind
turbine is placed into service. In 2008, the production tax
credit was $20.78/MWh. Wind energy generators with insufficient
taxable income to benefit from the production tax credit may take
advantage of a variety of investment structures to monetize the tax
benefits.
|
The
production tax credit was originally enacted in 1992 for wind parks placed into
service after December 31, 1993 and before July 1,
1999. The production tax credit subsequently has been extended five
times, but has been allowed to lapse three times (for periods of three, six and
nine months) prior to retroactive extension. Currently, the
production tax credit is scheduled to expire on December 31, 2012, unless
an extension or renewal is enacted into law.
|
●
|
Accelerated Tax
Depreciation.
Tax depreciation is a non-cash expense
meant to approximate the loss of an asset’s value over time and is
generally the portion of an investment in an asset that can be deducted
from taxable income in any given tax period. Current federal
income tax law requires taxpayers to depreciate most tangible personal
property placed in service after 1986 using the modified accelerated cost
recovery system under which taxpayers are entitled to use the 200% or 150%
declining balance method depending on the class of property, rather than
the straight line method. In addition, under the modified
accelerated cost recovery system, a significant portion of wind park
assets is deemed to have depreciable life of five years which is
substantially shorter than the 15 to 20 year depreciable lives of
many non-renewable power supply assets. This shorter
depreciable life and the accelerated depreciation method results in a
significantly accelerated realization of tax depreciation for wind parks
compared to other types of power projects. Wind energy
generators with insufficient taxable income to benefit from this
accelerated depreciation often monetize the accelerated depreciation,
along with the production tax credits, through forming a limited liability
company with third parties.
|
22
Improvements
in Wind Energy Technology
Wind
turbine technology has improved considerably in recent years with significant
increases in capacity and efficiency. Multiple types and sizes of
turbines are now available to suit a wide range of wind resource characteristics
and landscapes. Modern wind turbines are capable of generating
electricity for 20 to 30 years.
There
have been two major trends in the development of wind turbines in recent
years:
|
●
|
According
to the Danish Wind Industry Association and the U.S. Department of Energy,
individual turbine capacity has increased dramatically over the last
25 years, with 30 kW machines that operated in 1980 giving way to the
1.5 MW machines that are standard today;
and
|
|
●
|
Wind
park performance has improved significantly, according to the U.S.
Department of Energy, as turbines installed in 2004 through 2006 averaged
a 33%-35% net capacity factor (the ratio of the actual output over a
period of time and the output if the wind park had operated at full
capacity over that time period) as compared to the 22% net capacity factor
realized by turbines installed prior to
1998.
|
Additionally,
as wind energy technology has continued to improve, according to AWEA, the
capital cost of wind energy generation has fallen by approximately 80% over the
past 20 years.
Increasing
Obstacles for the Construction of Conventional Fuel Plants
In
addition to the impediments presented by the extensive and growing environmental
legislation, new power plants that use conventional fuels, such as coal and
nuclear technologies, face a difficult, lengthy and expensive permitting
process. Furthermore, increasing opposition from public environmental
groups towards coal-fired power plants, coupled with rising construction costs,
contributed to the cancellation of many planned coal plants in
2007. According to Resource Media, a public relations firm
representing environmental groups in the western United States, the construction
of 31 coal-fired plants totaling 24,250 MW was canceled or delayed in
2007. As a result, despite increasing gross margins, only about 2,000
MW of net new capacity from coal and nuclear plants was brought online between
2003 and 2006. Additionally, in October 2007, the Kansas Department
of Health and Environment became the first government agency in the United
States to cite carbon dioxide emissions as the reason for rejecting an air
permit for a proposed coal-fired electricity generating plant, saying that the
greenhouse gas threatens public health and the
environment. Traditional energy developers and utilities are likely
to face similar permitting and restricted supply issues in the
future. As a result, alternative energy sources such as wind will
need to be developed to meet increasing electricity demand and will be able to
capitalize on the resulting higher energy prices.
23
Abundant
Wind Resources in Attractive Energy Markets within the United
States
The
potential for future growth in the U.S. wind energy market is supported by the
large land area available for turbine installations and the availability of
significant wind resources. According to AWEA, annual average wind
speeds of 11 miles per hour or greater are required for grid-connected wind
parks. As shown in the map below, a large portion of the United
States exhibits wind speeds sufficient for wind park development.
Source:
United States Department of Energy—National Renewable Energy
Laboratory.
A chart
describing the potential for wind power in billions of kWh is included
below. Note that according to this source, North Dakota offers the
best wind resource in the United States. The wind is exceptional in
the Great Plains (and North Dakota especially), the actual installed capacity is
minimal. Assuming a net capacity factor of 35%, current North Dakota
wind parks only generate a small fraction of the state’s potential
output. In fact, even with the projects planned for construction in
the next year, less than 1% of potential will be realized.
THE
TOP TWENTY STATES
for Wind
Energy Potential
as
measured by annual energy potential in the billions of kWh, factoring in
environmental and land use exclusions for wind class of 3 and
higher.
|
B kWh/Yr
|
B kWh/Yr
|
|||||||||
|
1.
|
North
Dakota
|
1,210
|
11
.
|
Colorado
|
481
|
|||||
|
2.
|
Texas
|
1,190
|
12
.
|
New
Mexico
|
435
|
|||||
|
3
.
|
Kansas
|
1,070
|
13
.
|
Idaho
|
73
|
|||||
|
4
.
|
South
Dakota
|
1,030
|
14
.
|
Michigan
|
65
|
|||||
|
5.
|
Montana
|
1,020
|
15.
|
New
York
|
62
|
|||||
|
6.
|
Nebraska
|
868
|
16.
|
Illinois
|
61
|
|||||
|
7.
|
Wyoming
|
747
|
17
.
|
California
|
59
|
|||||
|
8
.
|
Oklahoma
|
725
|
18
.
|
Wisconsin
|
58
|
|||||
|
9.
|
Minnesota
|
657
|
19.
|
Maine
|
56
|
|||||
|
10.
|
|
Iowa
|
|
551
|
|
20.
|
|
Missouri
|
|
52
|
Source:
An Assessment of the Available Windy Land Area and Wind Energy Potential in the
Contiguous United States, Pacific Northwest Laboratory, August 1991.
PNL-7789
24
Wind
Energy Fundamentals
The term
“wind energy” refers to the process used to generate electricity through wind
turbines. The turbines convert wind’s kinetic energy into electrical
power by capturing it with a three blade rotor mounted on a nacelle that houses
a gearbox and generator. When the wind blows, the combination of the
lift and drag of the air pressure on the blades spins the blades and rotor,
which turns a shaft through the gearbox and generator to create
electricity.
Wind
turbines are typically grouped together in what are often referred to as “wind
parks.” Electricity from each wind turbine travels down a cable
inside its tower to a collection point in the wind park and is then transmitted
to a substation for voltage step-up and delivery into the electric utility
transmission network, or “grid.” Today’s wind turbines can
efficiently generate electricity when the wind speed is between 11 and 55 miles
per hour.
A key
factor in the success of any wind park is the profile and predictability of the
wind resources at the site. Extensive studies of historical weather
and wind patterns have been performed across North America and many resources,
in the forms of charts, graphs and maps, are available to wind energy
developers. The most attractive wind park sites offer a combination
of land accessibility, power transmission, proximity to construction resources
and strong and dependable winds.
When wind
energy developers identify promising sites, they perform detailed studies to
provide greater certainty with respect to the long-term wind characteristics at
the site and to identify the most effective turbine siting
strategy. The long-term annual output of a wind park is assessed
through the use of on-site wind data, publicly available reference data and
sophisticated software. Wind speeds are estimated in great detail for
specific months, days or even hours, and are then correlated to turbine
manufacturers’ specifications to identify the most efficient turbine for the
site. Additional calculations and adjustments for turbine
availability (which is principally affected by planned and unplanned maintenance
events), wake effects (wind depletion caused by turbines sited upwind), blade
soiling and icing and other factors are made to arrive at an estimate of net
expected annual kilowatt hour electricity production at the site.
Sources
of Revenue for Wind Generators
Wind
energy generators primarily derive revenue from three sources:
|
|
·
|
Energy
sales.
Energy sales are derived from the sale of energy
into a wholesale market or to a specific customer, such as a utility or
power marketer;
|
|
|
·
|
Renewable energy certificate
sales.
In many states, conventional energy producers are
required either to produce a certain percentage of their energy from
renewable sources or to purchase renewable energy certificates from
renewable energy producers. Renewable energy certificates
represent the environmental attributes associated with electricity from
renewable sources. Renewable energy certificates are a tradable
instrument that can be sold separately from the electricity produced by a
renewable generation source, thereby providing an additional revenue
stream; and
|
25
|
|
·
|
Capacity
sales.
In some states, but not the states in which we
are developing wind parks, payments are made to energy generators,
including wind parks, as a market incentive to promote the development and
continued operation of capacity sufficient to meet regional load and
reserve requirements. Market systems have been established to
ensure that generators receive these payments based on their availability
to generate electricity. Payments are generally allocated to
wind parks based on the previous year’s capacity for the super-peak hours
during winter and summer qualifying
periods.
|
Crownbutte’s
Portfolio Management
We have
been involved with all stages of the development process for wind energy
projects. We believe this experience has given us knowledge to
develop wind energy projects efficiently and effectively. We seek to
develop well sited and well planned wind energy projects. Revenues
generated in the past from the sale of brown-field and completed projects have
been reinvested into our project portfolio by continuing to develop additional
projects. Selling developed projects prior to construction provides
returns for the capital invested in the development process. However,
the sale is a onetime occurrence from the developer’s standpoint, and developing
projects just to sell them is a relatively high risk business
strategy.
Operating
wind projects allows the project owner to receive revenues over the life of a
project. We view ownership and operation of wind energy projects as
the next step in our expansion strategy. We believe that operational
projects will provide the Company with better risk adjusted returns on
capital. Ownership may also give us upside potential if electricity
prices continue to rise or if the value of an operational wind energy project
increases. We anticipate that both of these values will continue to
increase over the long term, as they have in the past several
years.
The
upside potential for ownership in wind energy projects is driven mainly by the
price of electricity. A wind energy project receives payment for the
power it generates in one of two ways: either through a power purchase agreement
(PPA) or selling into an open market for electricity. The PPA is the most common
method of power off-take for wind energy projects. The agreements are
almost always with a utility and normally require the utility to buy all
electricity a project may generate at a set rate. The agreements
normally have a price increase every year and can run for up to 20
years. The PPA rates are usually below the market rate for
electricity. The guaranteed price that a PPA offers reduces the risk
of a project. Additionally projects with PPAs will usually be able to
secure higher levels of debt financing and/or lower interest rates on the
debt.
In many
areas of the country another viable strategy for power off-take is to sell the
electricity into a power spot market. Projects that sell electricity
in this manner are referred to as “merchant” projects. There are
several systems that provide real time and day-ahead spot markets for
electricity such as Midwest ISO, PJM, ERCOT and Cal ISO. To decrease
risk and increase financing options, some projects will sell into the spot
markets but hedge their exposure with electricity futures contracts that trade
on exchanges like the NYMEX.
26
Our
portfolio of projects is located in the Midwest, and therefore our merchant
projects would sell into the Midwest ISO’s spot market. We view
selling power from our projects into the MISO market as a better off-take
strategy than a PPA. This view is based on the fact that we believe
the price of electricity will continue to rise and that a merchant project model
will allow us to most effectively participate in upward price
movement. The historically increasing costs are reflected in the
year-over-year rise in the spot price on the MISO market. See the
chart under “Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Our Strategy.” As the U.S. continues in
recession, all prices in the economy, including the price of electricity, will
experience downward pressure. To the extent that Crownbutte intends
to use open market venues (
i.e.
, the “merchant” markets)
to sell power, variability of electricity prices are a risk to profitability in
the short term. Over the long term, the demand for electricity is
driven by the number of consumers, the numbers of electricity-powered devices
employed and the efficiency of those devices.
We
continue to identify new green-field sites to build our pipeline of
projects. Upon successfully reaching commercial operation with a
project, we will continually evaluate the most ideal mix of projects in the
portfolio. In the event a buyer is identified and the sale of a
project would, in our judgment, provide better returns than operation, the
project may be sold off after it is in commercial operation. The sale
of projects could be used to assist in the financing of additional projects that
may provide higher returns for the Company.
Regulation
The
following is a summary overview of certain applicable regulations in the United
States and should not be considered a full statement of the law or all related
issues.
Energy
Regulation
FPA
Under the
Federal Power Act, or “FPA”, the Federal Energy Regulatory Commission (“FERC”)
has exclusive rate-making jurisdiction over wholesale sales of electricity and
transmission in interstate commerce. The FPA subjects “public
utilities” within the meaning of the FPA, among other things, to rate and
corporate regulation by FERC. In particular, sellers of electricity
at wholesale in interstate commerce and transmitters of electricity in
interstate commerce are regulated by FERC with respect to: the review of the
terms and conditions of wholesale electricity sales and transmission of
electricity; the need to obtain advance approval of certain dispositions of
public utility facilities, mergers, purchases of securities of other public
utilities, acquisitions of existing generation facilities and changes in
upstream ownership interests; the regulation of their borrowing and securities
issuances and assumption of liabilities; and the review of interlocking
directorates. Future issuances of our equity securities may be
subject to FERC approval under Section 203 of the FPA. FERC has
authority under Section 206 of the FPA in certain circumstances to order
refunds and, under FPA amendments pursuant to the Energy Policy Act of 2005,
FERC has expanded authority to assess civil penalties of up to $1 million
per day for violations of the FPA. We can offer no assurance that, at
some future time, the U.S. Congress will not change the relevant provisions of
the FPA, or that FERC will not change its regulations implementing the
requirements of the FPA.
27
Wholesale
electricity sellers authorized by FERC to sell at market-based rates may obtain
waivers or blanket pre-approvals as to certain of the regulatory requirements of
the FPA, including waiver of FERC’s accounting regulations and blanket
pre-authorization with respect to its regulation of issuances of securities and
assumption of liabilities. We can offer no assurance that FERC will
not revisit its policies at some future time with the effect of limiting
market-based rate authority, regulatory waivers and blanket
authorizations. We have been granted market-based rate authority for
one project to date and are familiar with the legal procedures and requirements
to be granted market-based rate authority. Therefore, we expect our
wind parks to be granted market-based rate authority, and as a result, to be
permitted to sell electric energy and capacity at market or otherwise negotiated
rates. Wind parks with market-based rate authorization are subject to
regulation by FERC as a “public utility” pursuant to the FPA. FERC’s
orders that grant market-based rate authority reserve the right to revoke or
revise that authority if FERC subsequently determines that the market-based rate
seller can exercise market power in transmission or generation, create barriers
to entry or engage in abusive affiliate transactions. FERC may impose
various forms of market mitigation measures, including price caps and operating
restrictions, where it determines market power may exist and that the public
interest requires such potential market power to be mitigated. Such
wind parks are also required to report to FERC any material changes in status
that would reflect a departure from the characteristics that FERC relied upon
when granting market-based rate authority, make quarterly electronic filings
with FERC providing information on sales of electricity and comply with market
behavior and manipulation rules. If any of our wind parks were to be
unable to obtain, or were to lose once obtained, its market-based rate
authority, it would be required to obtain FERC’s acceptance of cost-of-service
rate schedules and would become subject to the accounting, record-keeping and
reporting requirements that are imposed on utilities with cost-based rate
schedules.
In
addition to direct regulation by FERC, our wind parks will be subject to rules
and terms of participation imposed and administered by regional transmission
operators and independent system operators, in particular MISO for our current
projects. Although these entities are themselves ultimately regulated
by FERC, they can impose rules, restrictions and terms of service on market
participants, like our wind parks, that can have a material impact on our
business. For example, independent system operators and regional
transmission operators may impose bidding and scheduling rules, both to curb
market power and to ensure functioning markets. The act of obtaining
an Interconnect Agreement with MISO is coincident with obtaining FERC “Notice of
Filing” that acknowledges the Interconnect Agreement (see Table
below).
FERC
rules for the establishment, approval and enforcement of Electric Reliability
Standards will require each of our wind parks to register with the North
American Electric Reliability Council and the regional Electric Reliability
Organization. We are also required to comply with applicable
Reliability Standards approved by FERC.
PUHCA
and PURPA
The
Public Utility Holding Company Act of 2005, or “PUHCA,” in relevant part,
provides that any entity that owns, controls or holds power to vote 10% or more
of the outstanding voting securities of a “public utility company” (which is
defined to include an “electric utility company”) or a company that is a
“holding company” of a public utility company or public utility holding company,
is subject to certain regulations granting FERC access to books and records and
oversight over certain affiliate transactions. State regulatory
commissions may in some instances also have access to books and records of
holding companies. Entities that are holding companies solely by
virtue of their ownership of “qualifying facilities” (or QF) pursuant to the
Public Utility Regulatory Policies Act, or PURPA, and “exempt wholesale
generators” are exempt from FERC access to books and records under
PUHCA.
28
In order
to obtain exempt wholesale generator status pursuant to PUHCA, the owner of a
generating facility must demonstrate that it is engaged directly, or indirectly
through one or more affiliates, and exclusively in the business of owning and/or
operating facilities used exclusively for the generation of electricity for sale
at wholesale.
In order
to obtain qualifying facility status, a generating facility must qualify as a
small power production facility or cogeneration facility that has either filed a
self-certification of qualifying facility status with, or has received a
qualifying facility certification order from, FERC. A wind generation
facility may qualify as small power production qualifying facility if it is less
than 80 MW. Certain QFs, including renewable energy facilities
with a generating capacity of 30 MW or less, are exempt from certain
provisions of the FPA, including the accounting and reporting requirements, and
mergers and acquisitions oversight, facility disposition regulations and several
other provisions of the FPA. Additionally, renewable energy
facilities with a generating capacity of 30 MW or less are exempt from
FERC’s ratemaking authority under the FPA. A QF has the right to
require an electric utility to interconnect it to the utility’s electric system,
and to purchase firm power service, back-up power and supplementary power from
that interconnected electric utility at reasonable and non-discriminatory
rates. Finally, a QF is exempt from the laws of the states, which
otherwise regulate the ownership, rates and terms of sales, corporate governance
and financing of electric utilities.
We intend
that each of our wind parks will file a self-certification with the FERC that it
is an exempt wholesale generator. As a result, under current federal
law, we would not be subject to regulation as a holding company under PUHCA and
would not be subject to this regulation as long as each “public utility company”
in which we have an interest is (i) a QF, (ii) an exempt wholesale
generator (“EWG”) or (iii) subject to another exemption or
waiver. However, there can be no assurance that applicable law will
not change.
State
Regulation
Some of
our wind parks will be subject to varying degrees of regulation by state public
utility commissions. State public utility commissions have
historically had broad authority to regulate both the rates charged by, and the
financial activities of, electric utilities that sell electricity at retail, and
a number of other matters relating to electric utilities, as described
below. State laws may also impose certain regulatory and reporting
requirements on other owners and operators of generation
facilities. Independent power producers are considered to be public
utilities in some states and are subject to varying degrees of regulation by
state public utility commissions, ranging from a requirement to obtain a
“certificate of public convenience and necessity” in order to construct and
operate a generating facility, to regulation of organizational, accounting,
financial and other corporate matters. While FERC has exclusive
jurisdiction over the rates for wholesale sales of electric energy, states may
assert jurisdiction over the location and construction of electric generating
facilities, and in certain situations, over the issuance of securities and the
sale or other transfer of assets by these facilities.
29
County
Regulation
All
projects in our development pipeline will, before construction can begin,
require approval from the zoning boards of the relevant county governments in
which the parks are located. When appropriate in the development
timeline (
i.e.
, before
construction is to begin), we obtain the necessary zoning/conditional use
permits (see Table below).
Historical
Societies
Permits
or licenses are not required for construction of wind parks, but if items of
archaeological interest are discovered during construction, then there is a risk
of delays or outright stoppages while the findings are
investigated. To reduce or eliminate the risk of such findings, it is
appropriate to conduct literature searches regarding the history of the specific
sites under development. Crownbutte makes it a practice to conduct
such literature surveys and to obtain letters certifying that such due diligence
had been conducted (see Table below).
Federal
Aviation Administration and North Dakota Aeronautics Commission
This
regulatory dimension focuses on the potential safety-related impact of wind park
development on regional and local air traffic, whether commercial, military, or
private, regarding the projected siting of wind parks in relation to their
proximity to airports and air traffic corridors. Based on the
latitude and longitude of each park, the FAA or NDAC may make a “Determination
of No Hazard” on flight paths for wind towers erected at that
location. Crownbutte endeavors to secure such letters for all of its
sites (see Table below).
Environmental
Regulation
Our wind
park development activities are not at this time subject to specific
environmental laws or regulations in the State of North Dakota, including
environmental impact review requirements and regulations governing the discharge
of fill materials into protected wetlands. Occasionally, letters
certifying “no impact” may be obtained as a show of good faith on the part of
developers that appropriate due diligence was performed at the time of site
selection (see Table below). Where possible, Crownbutte
seeks to obtain such letters to certify “no impact.” However, there
can be no assurances that there will not be new regulations passed in the
future. In the State of New York, for example, the State
Environmental Quality Review Act requires a wind developer to evaluate the
potential environmental impacts caused by wind parks, including assessments of
visual and noise impacts, effects on wildlife (primarily birds and bats) and
impacts to historical and cultural resources, and to implement measures to
mitigate those impacts to the extent practicable.
Local
laws may in the future also regulate other aspects of our wind park development
and operation, by setting limits on the use of local roads, setback requirements
and noise standards. If we fail to comply with these possible future
requirements, or with other regulatory standards, we may be denied permits that
are required for construction or operation or become subject to regulatory
enforcement actions. Project opponents frequently use environmental
impact review statutes as a basis for mounting legal challenges to the issuance
of permits and approvals. Legal challenges or enforcement actions,
even if ultimately defeated, can result in substantial delays in the completion
of a wind park and may have a material adverse effect on our business, results
of operations and financial condition.
30
Our wind
parks are designed to have minimal operational impact on the
environment. Operation of a wind park does not produce significant
wastes, generate air emissions or result in wastewater
discharges. While most environmental regulatory obligations arise
during or prior to the construction stage for some wind parks, significant
environmental obligations may still exist even after construction is
complete. For example, wind parks in New York are obligated to
monitor impacts on avian species and to adopt mitigating measures if we detect
substantial impacts. In most cases, the precise nature of this potential
mitigation is not specified in the wind parks’ permits. While we do
not currently anticipate that such regulation will be adopted in the State of
North Dakota, we cannot offer any assurance that they will not, or that the
mitigation will not have an adverse effect on our business, results of
operations or financial condition.
|
LETTERS OF ”NO HAZARD” or ”NO IMPACT”
|
||||||||||||||||
|
Project
|
County
|
State
|
Zoning/
Cond Use
|
FERC Notice of
Filing
|
FAA/ NDAC
|
State Hist Society
|
State Game &
Fish
|
Fed. Fish &
Wildlife
|
||||||||
|
Gascoyne
I
|
Bowman
|
ND
|
Complete
|
Complete
|
Complete
|
Complete
|
Complete
|
Complete
|
||||||||
|
Gascoyne
II
|
Bowman/Adams
|
ND
|
Not
yet applied
|
Not
yet applied
|
Pending
|
Pending
|
Pending
|
Pending
|
||||||||
|
New
England
|
Hettinger
|
ND
|
Not
yet applied
|
Not
yet applied
|
Pending
|
Complete
|
Pending
|
Pending
|
||||||||
|
Elgin
|
Grant
|
ND
|
Complete
|
Not
yet applied
|
Complete
|
Complete
|
Complete
|
Complete
|
||||||||
|
Wibaux
|
Wibaux
|
MT
|
n/a
|
Not
yet applied
|
Pending
|
n/a
|
Pending
|
Pending
|
||||||||
|
Berthold
|
Ward
|
ND
|
Not
yet applied
|
Not
yet applied
|
Pending
|
Complete
|
Pending
|
Pending
|
||||||||
|
Carson
|
Grant
|
ND
|
Not
yet applied
|
Not
yet applied
|
Pending
|
Complete
|
Pending
|
Pending
|
||||||||
|
Monarch
|
Fallon
|
MT
|
n/a
|
Not
yet applied
|
Pending
|
n/a
|
Pending
|
Pending
|
||||||||
|
Tappen
|
Kidder
|
ND
|
Not
yet applied
|
Not
yet applied
|
Pending
|
Complete
|
Pending
|
Pending
|
||||||||
|
Mobridge
|
Campbell
|
SD
|
Not
yet applied
|
Not
yet applied
|
Pending
|
Not
yet applied
|
Pending
|
Pending
|
||||||||
|
Scobey
|
|
Daniels
|
|
MT
|
|
Not
yet applied
|
|
Not
yet applied
|
|
Pending
|
|
Not
yet applied
|
|
Pending
|
|
Pending
|
|
Big
Sandy
|
Chouteau
|
MT
|
Not
yet applied
|
Not
yet applied
|
Pending
|
Not
yet applied
|
Pending
|
Pending
|
||||||||
Competition
In the
United States, large utility companies dominate the energy production industry
and coal continues to be the primary resource for electricity
production. Electricity generated from wind energy faces competition
from other traditional resources such as nuclear, oil and natural
gas. The advantages of conventional production of electricity are
that:
|
|
·
|
the
technology and infrastructure already exist for the use of fossil fuels
such as coal, oil and natural gas,
|
|
|
·
|
commonly-used
fossil fuels in liquid form such as light crude oil, gasoline and
liquefied petroleum gas are easy to distribute,
and
|
|
|
·
|
petroleum
energy density (an important element in land and air transportation fuel
tanks) in terms of volume (cubic space) and mass (weight) is superior to
some alternative energy sources.
|
However,
energy produced by conventional resources also faces a number of challenges
including:
|
|
·
|
dependence
on fossil fuels from volatile regions or countries of the world creates
energy security risks for dependent
countries,
|
|
|
·
|
the
inefficient atmospheric combustion (burning) of fossil fuels leads to the
release of pollution into the atmosphere including carbon dioxide which is
largely considered the primary cause of global
warming,
|
31
|
|
·
|
extraction
of fossil fuels is becoming more expensive and more dangerous as
readily-available resources are exhausted and mines get deeper and oil
rigs must drill deeper and further out in oceans,
and
|
|
|
·
|
fossil
fuels are non-renewable, unsustainable resources which will eventually
decline in production and become exhausted resulting in a major impact on
the societies that utilize these
technologies.
|
In
contrast, electricity generated from wind energy:
|
|
·
|
produces
no water or air pollution that can contaminate the environment because
there are no chemical processes involved in wind power generation;
therefore, there are no waste by-products such as carbon
dioxide,
|
|
|
·
|
does
not contribute to global warming because it does not generate greenhouse
gases, and
|
|
|
·
|
is
a renewable source of energy which means that energy source will never be
depleted.
|
However,
wind energy producers also face certain obstacles including:
|
|
·
|
the
reality that wind is unpredictable in the short run and, therefore, wind
power is not predictably available, and when the wind speed decreases,
less electricity is generated,
|
|
|
·
|
residents
in communities where wind farms exist may consider them an “eyesore”
and
|
|
|
·
|
wind
farms, depending on the location and type of turbine, may negatively
affect bird migration patterns and may pose a danger to the birds
themselves; however, newer, larger wind turbines have slower moving blades
which seem to be visible to most
birds.
|
We expect
that primary competition for the wind power industry will continue to come from
utility company producers of electricity generated from coal and other
non-renewable energy sources.
Within
the U.S. wind power market itself, there is also a high degree of competition,
with growth opportunities in all sectors of the industry regularly attracting
new entrants. For example, in 2007, over 15 utility-scale wind
turbine manufacturers were selling turbines in the United States market, up from
only six in 2005.
Non-utility
entrants in the wind power development market, however, face certain barriers to
entry. The capital costs of buying and maintaining turbines are
high. Other significant factors include the cost of land acquisition,
the availability of transmission lines and the cost to tie into those lines,
land use considerations and the environmental impact of construction and
operations. Finally, another critical barrier to entry into the wind
power development business is the necessary experience required to bring project
to the point where they are able to secure interconnection agreements, power
purchase agreements and project financing for construction.
32
We are
aware of several other companies that are working to develop medium size wind
energy projects and which management views as being competitive with certain
aspects of our Company. They are:
|
|
·
|
Nacel
Energy
- A community wind development company founded in 2006 and
focused on developing community wind projects in Wyoming, Texas and
Kansas.
|
|
|
·
|
Wind
Energy America
- This company is located in and focused on wind
power in Minnesota and is currently employing a strategy where it
purchases rights to current or developing wind
projects.
|
|
|
·
|
Juhl
Wind
- A wind energy developer focused developing medium to
large-scale wind farms jointly owned by local communities, farm owners and
the developer. It has a number of projects currently operating
with additional projects in
development.
|
However,
none of these companies is currently directly competing with us in the
geographic areas in which we are active. There are many other private
wind energy companies active in our region, but it is our belief that our most
significant competitors will be the utilities themselves. As the
relative advantages or disadvantages of wind over fossil fuel-based generation
play out, and unfolding carbon legislation emerges, utilities themselves will
likely elect to develop wind farm assets themselves. The advantages
that utilities have in this regard are both deep financial pockets, ownership of
the transmission infrastructure, and a mechanism to sell to the end customer
directly without the need for a merchant market. Montana-Dakota
Utility, Basin Electric Power Cooperative, and Florida Power & Light
(NextEra) have all constructed, purchased, or are in the process of developing
wind energy in the North Dakota and surrounding areas.
Our
Competitive Advantages
We
believe that we have a number of competitive advantages in the wind energy
production industry; one of our key advantages is that we try to develop
projects that fit into the existing transmission system. By focusing
on projects that fit, we decrease the likelihood of major transmission upgrade
costs and therefore increase the percentage of successful
projects. Generally projects that will fit into the transmission grid
are medium-size projects which take up less land, and therefore the turbines are
sited in a more ideal wind regime. We believe that our projects will
generally receive better production per turbine than larger projects that need
to make the project fit on the available land and, as a result, must site their
turbines in less than ideal locations. Also, because we focus on
projects that fit into the transmission grid, we believe we will be able to
avoid curtailment issues that larger projects and regions with greater wind
development often face.
We
believe our management’s understanding of deregulated energy markets enables us
to maximize the value of our development portfolio. Our team has
experience in site selection, market analysis, land acquisition, community
relations, permitting, financing, regulation and construction.
33
For wind
energy projects to be completed successfully, projects must be constructed in a
cost-effective manner. In the course of completing our project
developed for, and sold turnkey to, a utility (Chamberlain, SD), we have been
able to demonstrate that we can build wind farms on a cost-effective
basis.
Employees
We employ
approximately five full-time employees. We do not have any
collective bargaining agreements with our employees and consider our employee
relations to be good.
Patents
and Trademarks
We have
no trademarks or other proprietary rights registered with the United States
Patent and Trademark Office.
Seasonality
Although
our operating history is limited, we do not believe our business is
significantly seasonal. The prices for electricity in the relevant
nodes of the MISO area have shown price increases during peak summer months, so
it is possible that, after construction of our first project, we will find some
seasonality to the revenues from the sale of electricity. Based on
our wind reports, we do not believe that wind speed will be significantly
seasonal at our project sites.
Research
and Development
During
the last two fiscal years, the Company engaged in the following research and
development activities, as disclosed in the accompanying notes to audited
consolidated financial statements (see “Note 12 – Project Development Costs and
Interconnect Application Deposits”):
On May
27, 2008 the Company entered into a joint venture agreement with Westmoreland
Power, Inc., a coal company, under the name of Gascoyne II Wind Project to
develop, construct, manage, and operate a 200 MW wind power project in southwest
North Dakota. The Company received $200,000 from Westmoreland as
compensation in order to participate in the joint venture. The
Company recognized sale of development rights revenues for this amount for the
year ended December 31, 2008. Crownbutte is the managing
party. For the years ended December 31, 2009 and 2008, the Company
expensed development costs of $11,130 and $5,126, respectively, for this
project.
On June
20, 2008 the Company entered into an agreement with a wind development company
to purchase the rights to develop a wind park near New England, ND for
$100,000. Assets purchased by the Company consist of one met tower,
3.5 years meteorological data, and a land lease cooperation
agreement. For the years ended December 31, 2009 and 2008, the
Company expensed development costs of $13,901 and $89,427, respectively, for
this project.
34
On
September 18, 2008 the Company entered into an agreement with a wind development
company to purchase the rights to develop a 10 MW wind park near Ralls, TX for
$1,500,000. The agreement calls for a non-refundable down payment of
$200,000, another payment of $1,000,000 by March 10, 2009, and a final payment
of $300,000 upon beginning construction of the wind park, but no later than
September 18, 2009. Assets purchased by the Company consist of
meteorological data, land lease option agreements, permits, licenses, assignable
interconnect agreement, right-of-ways to substations and power lines, and FFA
determination. Should the Company default on any payments, the seller
would be entitled to take back the assets purchased by the
Company. As of December 31, 2008, the Company expensed development
costs totaling $210,270 for this project.
As of
December 31, 2008, the Company abandoned the Ralls, TX project forfeiting the
development rights and related assets. All assets were expensed as
research and development costs and were included in the $210,270 expensed as of
December 31, 2008. No additional costs were incurred in
2009.
In 2007,
the Company sold project development rights for a 20 MW wind park near Gascoyne,
ND to a wind energy company. The Company recognized $75,000 revenue
in 2006 for preliminary development work completed and earned in
2006. For the year ended December 31, 2007, additional revenue of
$250,000 for sale of project development rights was earned and recognized for
final development work completed prior to transfer of ownership. In
2008, the Company decided to repurchase the project. On September 30,
2008, the Company entered into an agreement with the wind development company to
repurchase the development rights for the 20 MW Gascoyne, ND wind park for
$325,000. For the years ended December 31, 2009 and 2008, the Company
expensed development costs totaling $93,667 and $333,476, respectively, for this
project as it has not yet deemed the project probable of being technically,
commercially, and financially viable.
For the
years ended December 31, 2009 and 2008 the Company expensed an additional
$38,178 and $282,799, respectively, in development costs for smaller projects
not listed above.
Financial
Statements and “Going Concern” Opinion
The
auditor’s report accompanying our audited financial statements for the years
ended December 31, 2009 and 2008, included in this Annual Report, contained an
explanation that our financial statements were prepared assuming that we will
continue as a going concern. The report cites operating losses,
negative cash flows from operating activities, and working capital and
accumulated deficits. Our ability to continue operating as a going
concern will depend on the sale of one or more greenfield projects, obtaining
additional financing to develop the properties, the realization of profits
through future production or sale of properties, and/or our ability to derive
sufficient funds from sales of equity and/or debt securities and, thereafter, to
generate sufficient funds to allow us to effectuate our business
plan. We cannot provide any assurance that we will have sufficient
sales or that sufficient financing will be available to us on terms or at times
that we may require. Failure in any of these efforts may materially
and adversely affect our ability to continue our operations.
35
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ITEM
1A.
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RISK
FACTORS
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This
Annual Report on Form 10-K contains certain forward-looking
statements. You are cautioned that such statements are only
predictions and are subject to various risks and uncertainties, many of which
are beyond our control, and that actual events or results may differ
materially. In evaluating such statements, you should specifically
consider the various factors identified in this Annual Report on Form 10-K,
including the matters set forth below, which could cause actual results to
differ materially from those indicated by such forward-looking
statements. If any of the following risks actually occurs, our
business, prospects, financial condition and results of operations could be
materially adversely affected. In that case, the trading price of our
common stock would likely decline and you may lose all or a part of your
investment.
Risks
Related to Our Business and the Wind Energy Industry
We
have limited experience in completing development of wind parks and no operating
history as an owner-operator of wind parks.
To date,
we have developed and sold only two wind parks. We plan to continue
to sell developments as a part of our ongoing business, but we intend to shift
the focus of our business towards ownership and operation of merchant wind parks
that we develop. We have no history as an owner-operator of wind
parks from which you can evaluate our business plan, and our past performance
cannot be taken as indicative of future results, especially as we change our
business strategy. As we transition from being only a developer to
being a developer-owner-operator of wind energy projects, our success will
depend on our ability to take on those additional roles and to manage the
challenges that the growth of our business will entail. Our
organization has to date consisted of a small number of employees. We
will be required to commence and manage significant operations, to manage growth
in personnel and operations and to manage our costs as we expand our
business. Our failure or inability to meet these challenges could
have a material adverse effect on our business, financial condition and results
of operations.
The
growth of our business depends upon our ability to convert our pipeline of
projects under development into operating projects.
We
currently do not own or operate any wind parks (and therefore have no megawatts
of capacity in operation). We may not be successful in completing our
pipeline of development projects as anticipated or at all. Our
portfolio of wind energy projects includes approximately 638 megawatts of
capacity in various stages of development. (See “Item 1.
Business.”) We expect to start construction on three 20 megawatt
projects in 2010 and 2011. Our goal is to have approximately
20 megawatts of owned operating capacity by the end of 2010, and we target
the construction and commissioning of approximately 40 megawatts in
2011. However, there can be no assurance we will achieve these
goals.
The
development and construction of wind energy projects involves numerous risks and
uncertainties, including:
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access
to liquid independent systems operator markets or negotiation of
power purchase agreements,
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36
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availability
of transmission lines with adequate
capacity,
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●
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obtaining
necessary land rights,
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●
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turbine
procurement,
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●
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availability
of turbine, construction and permanent
financing,
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obtaining
necessary governmental and regulatory approvals and permits,
and
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negative
public or community response,
|
many of
which are subject to intense competition and all of which may be beyond our
control. We discuss each of these risks in additional detail
below. These risks and uncertainties may prevent projects from
progressing to construction and may cause us to fail to meet the targets of our
development plan.
We
may be unable to secure the project financing required to construct the projects
currently in our portfolio.
If we
fail to secure the project financing required for construction of these wind
parks ($1.8-$2 million per megawatt of generating capacity), then Crownbutte
will be relegated to being a green-field developer of prospective wind farm
sites, whose income options will be limited to selling the development rights
for those sites to entities that are capable of assembling the project financing
required to construct, own, and operate wind farms. In such a case,
Crownbutte’s financial position and prospects for income would be significantly
impaired. The possibility of our failure to secure project finance
therefore makes investment into Crownbutte risky.
We
may elect not to proceed with projects currently in our portfolio.
We may
elect not to proceed with projects currently in our portfolio. Our
current portfolio of approximately 638 megawatts in development (we have no
megawatts in operation) does not include projects representing 30 megawatts
of prospective capacity that we have, since 2000, actively developed and then
elected not to pursue. To date costs incurred with respect to
projects we have elected not to pursue have been minimal, but this may not
always be the case.
Our
revenues may be inconsistent, creating a liquidity risk.
Until we
make the transition to owner/operator, our revenues depend on making a small
number (one to two transactions per year) of sales of the development rights to
parks in our pipeline. The negotiation and lead-time to completing
such transactions are not easily predictable, and may not occur at the prices or
on the timing we desire. Revenues therefore can be zero for extended
periods, which can result in significant liquidity risk for the
company.
37
Development
of our projects depends on access to liquid independent systems operator
markets.
We do not
plan to enter into power purchase agreements unless they are offered on
favorable terms. Our business model focuses on the development of
merchant parks, which sell electricity into a power spot
market. There are several systems that provide real time and
day-ahead spot markets for electricity such as Midwest Independent Transmission
System Operator, PJM, Electric Reliability Council of Texas and California
Independent System Operator. Our portfolio of projects is located
predominately in the Midwest, and therefore our merchant projects would sell
into the Midwest Independent Transmission System Operator’s spot
market.
It is
possible that the Midwest Independent Transmission System Operator spot market
becomes illiquid due to withdrawal of its member system owners, problems in the
physical transmission infrastructure, or fundamental changes in the supply or
demand of electricity. In the event that the spot market no longer
functions efficiently, any income streams from the sale of electricity would
have a material adverse effect on Crownbutte’s financial condition and
operations.
We
will depend on the availability of transmission lines with adequate
capacity.
We expect
to generally depend on electric transmission lines owned and operated by third
parties to deliver the electricity we will sell. Some of our wind
energy projects in development may have limited access to interconnection and
transmission capacity. The Midwest Independent Transmission System
Operator will inform Crownbutte in such cases during the feasibility studies and
systems impact studies that are part of the interconnection agreement
process. We may not be able to secure access to the limited available
interconnection or transmission capacity at reasonable systems upgrade cost, or
at all. Since this interconnection agreement must be in place before
any construction or turbine costs are incurred, this is a moderate financial
risk for Crownbutte.
However,
in the event of a failure in the transmission facilities
after
a project is completed,
we may experience lost revenues. In addition, transmission
limitations may cause us to curtail our production of electricity, impairing our
ability to fully capitalize on the particular wind energy project’s
potential. Any such failure could have a material adverse effect on
our business, financial condition or results of operations.
The
growth of our business depends on locating and obtaining control of suitable
operating sites.
Wind
energy projects require wind conditions that are found in limited geographic
areas and particular sites. Further, wind energy projects must be interconnected
to electricity transmission or distribution networks in order to deliver
electricity. Once we have identified a suitable operating site, our ability to
obtain requisite land control or other land rights (including access rights,
setback and/or other easements) with respect to the site is subject to growing
competition from other wind energy producers that have sufficient financial
capacity to research, locate and obtain control of such sites and to obtain
required electrical interconnection rights. Our competitors may impede our
development efforts by acquiring control of all or a portion of a project site
we desire to develop or obtaining a right to use land necessary to connect a
project site to a transmission or distribution network. If a competitor obtains
land rights critical to our project development efforts, we could incur losses
as a result of stranded development costs. If we succeed in securing the
property rights necessary to construct and interconnect our projects, such
property rights must be insurable and otherwise satisfactory to our financing
counterparties. Obtaining adequate property rights may delay development of a
project, or may not be feasible. Any failure to obtain insurable property rights
that are satisfactory to our financing counterparties would preclude our ability
to obtain third-party financing and could prevent ongoing development and
construction of the relevant projects.
38
Our
wind energy projects’ use and enjoyment of real property rights obtained from
third parties may be adversely affected by the rights of lien holders and lease
holders whose rights are superior to those of the grantors of these real
property rights.
Each of
our wind energy projects is or will be located on land occupied pursuant to
various easements and leases. Our rights pursuant to these easements and leases
allow us to install wind turbines, related equipment and transmission lines for
the projects and to operate the projects. The ownership interests in the land
subject to these easements and leases may be subject to mortgages securing loans
or other liens (such as tax liens) and other easement and lease rights of third
parties (such as leases of oil, gas, coal or other mineral rights) that were
created prior to our easements and leases. As a result, our rights under these
easements or leases may be subject and subordinate to the rights of such third
parties.
A default
by a landowner at one or more of our wind energy projects under a mortgage could
result in foreclosure of the landowner’s property and thereby terminate our
easements and leases required to operate the projects. Similarly, it is possible
that another lien holder, such as a government authority with a tax lien, could
foreclose upon a parcel and take ownership and possession of the portion of the
project located on that parcel. In addition, the rights of a third party
pursuant to a superior lease could result in damage to or disturbance of the
equipment at a project, or require relocation of project assets.
If any of
our wind energy projects were to suffer the loss of all or a portion of its wind
turbines or related equipment as a result of a foreclosure by a mortgagee or
other lien holder of a land parcel, or damage arising from the conduct of
superior lease holders, our operations and revenues could be adversely
affected.
Development
of wind projects is dependent on the availability of turbines and turbine
financings.
Wind
energy projects require delivery and assembly of turbines. The prices
of turbines and electrical and other equipment have increased in recent years
and may continue to increase as the demand for such equipment increases more
rapidly than supply, or if the prices of key components and raw materials used
to build the equipment increase. We may encounter supply and/or
logistical issues in securing turbines due to the limited number of turbine
suppliers and current high demand for turbines. While we have
received quotes from turbine suppliers and have seen some evidence of softening
turbine prices and shorter delivery lead times as the financial market turmoil
during the autumn of 2008 has slowed the installation of new wind capacity, we
currently have no turbines under contract but expect to have a turbine supply
agreement by May 2010. We may not be able to purchase a sufficient
quantity of turbines from suppliers, and suppliers may give priority to other
customers. Turbine suppliers may delay the performance of or be
unable to meet contractual commitments, or components and equipment may be
unavailable, which would have a material adverse effect on our business,
financial condition and results of operations.
39
In
addition, we expect to require third-party turbine supply loans or other
financing for our turbine purchases, which account for the majority of the total
cost of a wind energy project. An inability to obtain such financing
on attractive terms in the future may preclude us from obtaining additional
turbines, severely limiting our growth. Moreover, a significant
increase in the cost of obtaining such financing could have a material adverse
effect on the investment returns we achieve from our projects.
In
addition, spare parts for wind turbines and key pieces of electrical equipment
may be unavailable to us. If we were to experience a serial failure
of any spare part we would incur delays in waiting for shipment of these items
to the site. In addition, we do not carry spare substation main
transformers. These transformers are designed specifically for each
wind energy project, and the current lead time to order this equipment is up to
one year. If we have to replace any of our transformers, we would be
unable to sell electricity from the affected wind energy project.
When we
purchase our turbines, we also enter into warranty agreements with the
manufacturer. Damages payable by the manufacturer under these
agreements are typically subject to an aggregate maximum cap that is a portion
of the total purchase price of the turbines. Losses in excess of
these caps will be our responsibility. Since our turbine warranties
generally expire within a certain period of time after the turbine delivery date
or the date such turbine is commissioned, we may lose all or a portion of the
benefit of the warranties if we are unable to deploy turbines we have purchased
upon delivery.
We will need to
raise additional capital
to meet our
business requirements, and such capital raising may be costly or difficult to
obtain and could dilute current stockholders’ ownership
interests.
To date,
our capital expenditures and working capital requirements have been funded by
income from operations and equity capital. Our income from operations
will not be sufficient to fund our business plan. We plan to
raise approximately $1 million through private placements of equity by the end
of 2010, the proceeds of which, together with cash on hand, will be used for
general corporate expenses associated with the hiring of new staff required to
accelerate our development activities, as well as move into our new
owner-operator business model, which requires oversight of construction of
projects, as well as the operations and maintenance of projects after
construction is complete. However, we may be unable to secure this
additional financing on terms acceptable to us, or at all, at times when we need
such financing. These fundings do not include financing of project
construction and operation. See “
Our projects will entail significant
capital expenditures and construction costs, and we will require additional
financing to construct and operate them
” below.
40
If we are
unable to obtain such additional equity financing on a timely basis, we may
have to curtail our development activities or be forced to sell assets, perhaps
on unfavorable terms, which would have a material adverse effect on our
business, financial condition and results of operations. We may incur
substantial costs in pursuing future capital financing, including investment
banking fees, legal fees, accounting fees, securities law compliance fees,
printing and distribution expenses and other costs. We may also be
required to recognize non-cash expenses in connection with certain securities we
may issue, such as convertible notes, restricted stock, stock options and
warrants, which may adversely impact our financial condition. See
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” below.
Any
future issuance of our equity or equity-backed securities may dilute
then-current stockholders’ ownership percentages. See “
You may experience dilution of your
ownership interests due to the future issuance of additional shares of our
common stock
” below.
Our
projects will entail significant capital expenditures and construction costs,
and we will require additional financing to construct and operate
them.
We are in
a capital intensive business, and our projects in development and construction
have entailed and will entail significant capital expenditures and construction
costs, and recovery of the capital investment in a wind energy project generally
occurs over a lengthy period of time. The capital investment required
to construct a wind energy project is primarily based on the costs of fixed
assets required for the project. We will require additional
financing, including tax equity financing transactions (described below), to
complete the construction of and to operate our existing
projects. Additional financing may not be available on acceptable
terms or at all.
After we
have developed a wind energy project that we intend to own to the point where we
are prepared to commence construction, we would expect typically to enter into a
limited recourse construction loan. Proceeds from construction loans
would typically be used to retire turbine indebtedness and to pay construction
costs, including costs to construct roads, substations, transmission lines and
the balance of plant. Construction loans are generally secured by the
project’s assets and our equity interests in the project
companies. In certain instances we may enter into a construction loan
for a single project, while in other instances we may be able to finance
multiple projects through a single credit facility. We will also
likely use equity capital contributions (our own and potentially from other
investors as described above) to fund a portion of each project’s construction
costs.
We would
forego the need for construction loans (as well as turbine supply loans) if we
are able to secure 100% debt or 100% equity-based investment for any given
project. A 100% debt financing would be done on a limited recourse
basis and be secured by the project assets and our equity. In a 100%
equity financing, the outside equity investors would contribute all of the
project costs as equity in return for an 80% to 90% share of the
returns. However, while we are exploring these possibilities, these
structures have not in the past been the norm in the wind generation industry
and may not be available. Our proposed financing for the Gascoyne I
project with 100% debt and an 80% ownership stake is a unique transaction, and
we do not expect it to be the norm for financing additional parks.
Once
construction of a wind energy project is completed and commercial operations
commence, we will seek to finance the project on a long-term basis through a
combination of term loans and tax equity financing, to the extent
available. (See “
We
expect to be materially dependent on tax equity financing arrangements for
projects financed after 2010
” below.)
41
The
unprecedented upheaval in the debt and equity markets in the U.S. and around the
world in recent months has made all categories of financing more difficult to
secure. See ”Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Project Finance.”
Our
strategy of relying on a merchant park model may make project financing more
difficult and may adversely affect results of operations.
Our
business model focuses on the development of merchant parks. We do
not plan to enter into power purchase agreements unless they are offered on
favorable terms. Merchant parks sell electricity on the open
market. The reliance on the merchant market (
i.e.
, the lack of power
purchase agreements) can be a significant barrier to achieving construction
financing and project financing with equity investors (as described below), many
of whom seek the security of long-term power purchase agreements with power
off-takers.
Our
efforts to secure project finance have confirmed that investment banks and other
financial institutions that have brokered or directly financed wind projects in
the past have a continued desire to see power purchase agreements as the
off-take arrangement in place for projects they seek to represent or
finance. Such a desire for a power purchase agreement on the part of
financiers is natural, but may not be possible to achieve by
Crownbutte. There are no federal or state mandates in place that
require utilities to offer power purchase agreements in North Dakota, where the
bulk of Crownbutte’s projects are located.
Crownbutte
to date has not secured project financing for any of its parks in development,
although we are currently in the due diligence phase for funding for the
Gascoyne I project. If power purchase agreements cannot be secured,
and financiers decline to fund any of Crownbutte’s merchant park model projects,
there will be a significant adverse effect on Crownbutte’s finances and
operations. While we anticipate closing the finance deal for Gascoyne
I in the second quarter of 2010, there is no guarantee the funding will be
approved.
We
expect to be materially dependent on tax equity financing arrangements for
projects financed after 2010.
Beyond
the three projects we believe may qualify for the U.S. Treasury Department
renewable energy grant program, the majority of our projects will require other
types of financing. For those projects, we intend to seek tax equity
financing to provide the majority of the permanent capital needs for each
project we will own. The availability of tax equity financing depends
on federal tax attributes that encourage renewable energy
development. These attributes primarily include (i) renewable energy
federal production tax credits, which are federal income tax credits related to
the quantity of renewable energy produced and sold during a taxable year and
(ii) accelerated depreciation of renewable energy assets as calculated under the
Modified Accelerated Cost Recovery System of the Internal Revenue
Code. We do not expect to generate sufficient taxable income from
owned projects to use all of the production tax credits or the accelerated
depreciation expected to be available to us under these programs. Although the
economic downturn and financial market turmoil of 2008 lingers, the tax appetite
of financial institutions may rebound sooner than anticipated, making the tax
equity financing more available. Under the U.S. Treasury Department
renewable energy grant program, a non-taxable cash grant equal to 30% of a
project’s authorized capital costs can be received in lieu of investment tax
credits or production tax credits. The U.S. Treasury Department
renewable energy grant program is scheduled to expire on December 31,
2010. We believe the availability of the grant program is more
attractive than tax equity financing to most investors, however, we anticipate
that will change upon expiration of the grant program. As the economy
recovers, institutional profits will increase and tax appetite for PTC and
accelerated depreciation tax benefits will return.
42
In a
typical tax equity financing, we would receive a capital investment in exchange
for an equity interest in our subsidiary that owns the project. These
equity interests entitle the investors to receive a substantial portion of the
project’s cash distributions from electricity sales and related hedging
agreements, production tax credits and taxable income or loss until such
investors reach an agreed rate of return on their investment. As a
result, a tax equity financing substantially reduces the cash distributions from
the applicable projects available to us for other uses, and the period during
which the tax equity investors receive cash distributions from electricity sales
and related hedging agreements may last longer than expected if our wind energy
projects perform below our expectations.
Moreover,
there are a limited number of potential tax equity investors, they have limited
funds and wind energy developers compete with other renewable energy developers
and others for tax equity financing. To date, the wind industry’s tax
equity investors have been large financial institutions with significant taxable
income. The unprecedented upheaval in the debt and equity markets in
the U.S. and around the world in recent months has resulted in lower profits for
many financial institutions, making tax equity investing less available in
general. Furthermore, as the renewable energy industry expands, the
cost of tax equity financing may increase and there may not be sufficient tax
equity financing available to meet the total demand in any year. If
we are unable to enter into tax equity financing agreements with attractive
pricing terms or at all, we may not be able to use the tax benefits provided by
production tax credits and accelerated tax depreciation, which could have a
material adverse effect on our business, financial condition and results of
operations.
In
addition, our tax equity financing agreements are expected to provide our tax
equity investors with a number of approval rights with respect to the applicable
project or projects, including approvals of annual budgets, indebtedness,
incurrence of liens, sales of assets outside the ordinary course of business and
litigation settlements. As a result of these restrictions, the manner
in which we conduct our business may be
limited. See ”Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Project Finance.”
The
growth of our business depends upon the extension of the expiration date of the
production tax credit/investment tax credit, which currently expires on
December 31, 2012, and other federal and state governmental policies and
standards that support renewable energy development.
We depend
heavily on government policies supporting renewable energy that make the
development and operation of wind energy projects economically
feasible. In particular, we cannot economically develop and construct
our pipeline of development projects without the federal production tax credit,
which will expire on December 31, 2012, unless legislation is enacted to
extend it. The production tax credit currently provides a $21 federal
tax credit per megawatt hour for a renewable energy facility that uses wind,
geothermal or closed-loop biomass fuel sources in each of the first ten years of
its operation and applies to facilities that are placed in service before the
end of 2012. These facilities will continue to benefit from the
current production tax credit incentive until the end of the ten-year period
from the date on which the wind turbines are placed in
service. Without an extension of the expiration date of the
production tax credit, wind energy projects may not be economically feasible to
develop and construct.
43
An option
to the production tax credit is the 30% investment tax credit wherein a taxpayer
may claim 30% of investment amount as a tax credit in lieu of the production tax
credit.
As part
of the American Recovery and Reinvestment Act of 2009, a project placed in
service in 2009 or 2010 may receive a cash grant from the U.S. Treasury
Department in lieu of investment tax credits or production tax
credits. The grant amount for most wind projects would equal to 30%
of the authorized capital costs of the project. The grant does not
constitute taxable income.
In
addition to the production tax credit/investment tax credit, we rely on other
incentives that support the sale of energy generated from renewable sources,
including state adopted Renewable Portfolio Standards
programs. Renewable Portfolio Standards programs often operate in
tandem with a credit trading system through which generators can buy or sell
Renewable Energy Certificates that are issued by the state to generators of
renewable energy to meet mandated renewable requirements. At this
time, North Dakota has no Renewable Portfolio Standards, and it is not
anticipated that they will have Renewable Portfolio Standards in the near
future. Other states including Montana and Minnesota provide a range
of incentives through Renewable Portfolio Standards programs.
While
federal and state governments have promoted renewable energy in the past,
policies may be adversely modified or support of renewable energy development,
particularly wind energy, may not continue. If governmental
authorities fail to continue supporting, or reduce their support for, the
development of renewable energy projects, particularly wind energy projects, it
could materially adversely affect our ability to develop and construct our
pipeline of development projects and grow our business.
The
design, construction and operation of wind energy projects are highly regulated
and the failure of being granted operating and construction permits could
materially adversely affect our business, financial condition and results of
operations.
The
design, construction and operation of wind energy projects are highly regulated
activities requiring various material governmental and regulatory approvals and
permits. Procedures for the granting of operating and construction
permits vary by jurisdiction and certain jurisdictions may deny requests for
permits for a variety of reasons. Further, we may not be able to
renew construction and operating permits when required. Failure to
procure and maintain the necessary permits may prevent ongoing development,
construction and continuing operation of our projects. In addition,
in some circumstances we may have to commence construction prior to obtaining
all required permits, which exposes us to the risk that we may subsequently be
unable to secure all of the permits required to complete the
project. If this were to occur, we could experience considerable
losses as a result of our prior investment.
44
Our
projects may be subject to regulation by the Federal Energy Regulatory
Commission under the Federal Power Act or other regulations that regulate the
sale of electricity, which may adversely affect our business.
Certain
of our projects may be able to obtain qualifying facility status under the
Public Utility Regulatory Policies Act, or PURPA. Qualifying
facilities are exempt from certain provisions of the Federal Power Act,
including the accounting and reporting requirements, and mergers and
acquisitions oversight, facility disposition regulations and several other
provisions of the Federal Power Act. Additionally, renewable energy
facilities with a generating capacity of 30 megawatts or less are exempt from
the Federal Energy Regulatory Commission’s ratemaking authority under the
Federal Power Act.
Exempt
wholesale generators are generation owning public utilities (including producers
of renewable energy, such as wind projects) that are engaged exclusively in the
business of owning and/or operating generating facilities and selling electric
energy at wholesale. The owner of a renewable energy facility that
has been certified as an exempt wholesale generator in accordance with the
Federal Energy Regulatory Commission’s regulations is subject to the Federal
Power Act and to the Federal Energy Regulatory Commission’s ratemaking
jurisdiction, but the Federal Energy Regulatory Commission typically grants
exempt wholesale generators the authority to charge market-based rates as long
as the exempt wholesale generator can demonstrate that it does not have, or has
adequately mitigated, market power and cannot otherwise erect barriers to market
entry. The Federal Energy Regulatory Commission generally grants an
exempt wholesale generator waivers from many of the requirements that are
otherwise imposed on public utilities under the Federal Power Act.
The
Public Utility Holding Company Act of 2005 in part provides that any entity that
owns, controls or holds power to vote 10% or more of the outstanding voting
securities of a “public utility company” (which is defined to include an
“electric utility company”) or a company that is a “holding company” of a public
utility company or public utility holding company, is subject to certain
regulations granting the Federal Energy Regulatory Commission, access to books
and records and oversight over certain affiliate transactions. State
regulatory commissions may in some instances also have access to books and
records of holding companies. However, entities that are holding
companies solely by virtue of their ownership of qualifying facilities and
exempt wholesale generators are exempt from most of the Public Utility Holding
Company Act requirements.
We intend
that each of our wind parks will file a self-certification with the Federal
Energy Regulatory Commission that it is an exempt wholesale
generator. As a result, under current federal law, we would not be
subject to regulation as a holding company under Public Utility Holding Company
Act and would not be subject to this regulation as long as each “public utility
company” in which we have an interest is (i) a qualifying facility,
(ii) an exempt wholesale generator or (iii) subject to another
exemption or waiver.
Although
the sale of electric energy has been to some extent deregulated, the industry is
subject to increasing regulation and even the threat of
re-regulation. Due to major regulatory restructuring initiatives at
the federal and state levels, the U.S. electric industry has undergone
substantial changes over the past several years. We cannot predict
the future design of wholesale power markets or the ultimate effect ongoing
regulatory changes will have on our business. Other proposals to
re-regulate may be made and legislative or other attention to the electric power
market restructuring process may delay or reverse the movement towards
competitive markets. If the deregulation of the electric power
markets is reversed, discontinued or delayed, our business prospects and
financial results could be negatively affected. See
“Business—Regulation” for more information.
45
Negative
public or community response to wind energy projects may adversely affect our
ability to construct our projects.
There has
been negative public and/or community response to wind energy projects in some
areas of the United States, and such factors may adversely affect our ability to
construct our projects in certain areas. In addition, legal challenges may
result in an injunction against construction or operation, impeding our ability
to place projects in operation according to schedule, meet our development and
construction targets or generate revenues. An increase in opposition to the
granting of permits or unfavorable outcomes of such challenges could materially
and adversely affect our development plans.
Projects
that reach construction may not be completed or, if completed, may not meet our
return expectations.
Those
projects that do progress to construction may not be completed on a timely basis
or at all or, if completed, may not meet our return expectations, due to factors
such as:
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schedule
delays,
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cost
overruns,
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failure
to receive turbines or other critical components and equipment from third
parties on schedule and according to design
specifications
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unsatisfactory
completion of construction,
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shortfalls
of anticipated capacity factor,
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adverse
weather,
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lower
natural gas prices,
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lower
than forecast spot electricity prices,
and
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force majeure
or other
events out of our control.
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Any of
the above factors could give rise to construction delays and construction costs
in excess of our budgets, which could prevent us from completing construction of
a project, cause defaults under our financing transactions and impair our
business, financial condition and results of operations.
46
In a
situation where a power purchase agreement is in place, if we fail to construct
a wind energy project in a timely manner or do not deliver electricity in
accordance with the applicable power purchase agreement, the power purchase
agreement may be terminated and/or we could be required to pay liquidated
damages.
Wind
energy project revenues are highly dependent on suitable wind and associated
weather conditions.
The
energy and revenues generated at a wind energy project are highly dependent on
climatic conditions, particularly wind conditions, which are variable and
difficult to predict. Turbines will only operate within certain wind
speed ranges that vary by turbine model and manufacturer, and there is no
assurance that the wind resource at any given project site will fall within such
specifications.
When we
develop a wind energy project, we evaluate the quality of the wind resources at
the selected site through a number of means, and we retain third-party experts
to assist us in this evaluation. We base our investment decisions
with respect to each wind energy project on the findings of wind studies
conducted on-site before starting construction. We use the wind data
that we gather to develop projections of the wind energy project’s performance,
revenue generation, operating profit, debt capacity, tax equity capacity and
return on investment, which are fundamental elements of our business
planning. Wind resource projections at the start of commercial
operations can also have a significant impact on the amount of third-party
capital that we can raise, including the expected contributions by tax equity
investors. However, actual climatic conditions at a project site,
particularly wind conditions, may not conform to the findings of these wind
studies, and, therefore, our wind energy projects may not meet anticipated
production levels, which could adversely affect our forecasted
profitability. In addition, global climate change could change
existing wind patterns; such effects are impossible to predict.
Inaccurate
wind resource projections on the performance of one or more of our wind energy
projects resulting in unfavorable projected net capacity factor levels, could
materially adversely affect our business, financial condition and results of
operations.
We
project the net annual capacity factor for each project in our development
portfolio. Net capacity factor is one element used in measuring the
productivity of a wind turbine, wind energy project or any other power
production facility. It compares the turbine’s production over a
given period of time with the amount of power the turbine could have produced if
it had run at full capacity for the same amount of time.
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Amount
of power produced over time (usually measured annually)
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Net
Capacity Factor =
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Power
that would have been produced if turbine operated at full capacity 100% of
the time over the same period of
time
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Our net
capacity factor projections are subject to change and are not intended to
predict the wind at any specific time over the turbine’s 20-year useful
life. Even if our predictions of a wind energy project’s net capacity
factor become validated over time, the energy projects may experience hours,
days, months, and even years that are below our wind resource
projections.
47
Projections
of net capacity factor depend on wind resource projections, which rely upon
assumptions such as wind speeds, interference between turbines, effects of
vegetation and land use and terrain effects. The amount of
electricity generated by a wind energy project depends upon many factors in
addition to the quality of the wind resource, including turbine performance,
aerodynamic losses resulting from wear on the wind turbine, degradation of
turbine components, icing and the number of times an individual turbine or
entire wind energy project may need to be shut down for maintenance or to avoid
damage. In addition, conditions on the electrical transmission
network can affect the amount of energy we can deliver to the
network. Wind energy projects in our portfolio may fail to meet our
energy production expectations in any given time period. If our wind
energy projections are not realized, we could face a number of material issues,
including:
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our
energy sales may be significantly lower than we
forecast;
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our
energy hedging arrangements may be adversely
affected;
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we
may not produce sufficient energy to meet our forward Renewable Energy
Certificate sales and, as a result, we may have to buy Renewable Energy
Certificates on the open market to cover our
position;
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we
may earn fewer production tax credits than projected, which would increase
the period during which we must make certain distributions and allocations
to our tax equity investors; and
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our
wind energy projects may not generate sufficient cash flow to make
payments on principal and interest as they become due on our project
related debt.
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If, as a
result of inaccurate wind resource projections, the performance of one or more
of our wind energy projects falls below our projected net capacity factor
levels, our business, financial condition and results of operations could be
materially adversely affected.
Volatile
natural gas prices may adversely impact the market price for
electricity.
Natural
gas is one of the major sources of energy for the generation of electricity in
the U.S. The prices for natural gas have been very volatile in recent
months and years, with temporary highs in June-July of 2008 that were four times
the prices in January 2002. Since June, the prices for natural gas
used in electricity generation have fallen back to levels seen in December 2007
and January 2008. It is not possible to reliably predict what the
price behavior for natural gas will be in the future. If prices
continue to fall, they will adversely impact the economics for wind power, since
natural gas-based generation is one of the chief competitors to wind
energy. While there can be no assurance, in the long term we expect
that the continuing need to control greenhouse gas emissions, and the fact that
all fossil fuels are a finite resource, will allow wind power to continue to
compete favorably with natural gas.
48
A
sustained decline in market prices for electricity may materially adversely
affect our revenues and the growth of our business.
We may
not be able to develop or operate our pipeline of development projects
economically if there is a sustained material decline in market prices for
electricity. Electricity prices are affected by various factors and
may decline for many reasons that are not within our control, including changes
in the cost or availability of fuel, regulation and acts of governments and
regulators, changes in supply of generation capacity, changes in power
transmission or fuel transportation capacity, seasonality, weather conditions
and changes in demand for electricity. In addition, other power
generators may develop alternative technologies to produce power, including fuel
cells; clean coal and coal gasification; micro turbines; photovoltaic (solar)
cells or tidal current based generators, or improve upon traditional
technologies and equipment, such as more efficient gas turbines or nuclear or
coal power plants with simplified and safer designs, among
others. Advances in these or other technologies could cause a
sustained decline in market prices for electricity. If there is a
sustained decline in the market prices of electricity, we may not develop and
construct our pipeline of development projects and grow our business, and/or we
may not be able to operate completed projects economically, which would have a
material adverse effect on our revenues.
While we
will explore the viability of hedging against the possible drop of local
electricity prices, in our anticipated spot market solid hedging instruments
(with high correlations to the local power market price histories) may not be
available, which would represent an overall risk to the success of the business
model, and is a possible barrier to achieving project financing.
The
continuing U.S. recession will adversely affect the price of electricity in the
near term.
As the
U.S. continues in recession, all prices in the economy, including the price of
electricity, will experience downward pressure. To the extent that
Crownbutte intends to use open market venues (
i.e
., the “merchant” markets)
to sell power, variability of electricity prices are a risk to profitability in
the short term. Over the long term, the demand for electricity is
driven by the number of consumers, the numbers of electricity-powered devices
employed and the efficiency of those devices.
A
sustained decline in market prices for Renewable Energy Certificates may
materially adversely affect our revenues and the growth of our
business.
Similarly,
if there is a sustained material decline in Renewable Energy Certificates
prices, we may not be able to achieve expected revenues, which would have an
adverse effect on the investment returns on our projects. A Renewable
Energy Certificate is a stand-alone tradable instrument representing the
attributes associated with one megawatt hour of energy produced from a renewable
energy source. These attributes typically include reduced air and
water pollution, reduced greenhouse gas emissions and increased use of domestic
energy sources. Many states use Renewable Energy Certificates to
track and verify compliance with their Renewable Portfolio Standards (“RPS”)
programs, which vary among states, but generally require power suppliers to
provide a minimum percentage or base amount of electricity from specified
renewable energy sources for a given period of time. Retail energy suppliers can
meet the requirements by purchasing Renewable Energy Certificates from renewable
energy generators, in addition to producing or acquiring the electricity from
renewable sources.
49
Our
hedging strategy may not adequately manage our commodity price risk, may expose
us to significant losses and may limit our ability to benefit from higher
electricity prices.
Our
ownership and operation of wind energy projects will expose us to volatility in
market prices of electricity and Renewable Energy Certificates. In an
effort to stabilize our returns from electricity sales, we intend to carefully
review the electricity sale options for each of our development
projects. As part of this review, we will assess the appropriateness
of entering into a fixed price power purchase agreement and/or a financial
hedge. If we sell our electricity into a liquid independent systems
operator market, we may enter into a financial hedge with institutional
investors in order to stabilize our projected revenue stream.
Under the
terms of our anticipated financial hedges, we would not be obligated to
physically deliver or purchase electricity, but we would receive payments for
certain quantities of electricity based on a fixed price and would be obligated
to pay the market electricity price for the same quantities of
electricity. Thus, if market prices of electricity increase, we are
obligated to make payments under these financial hedges. Our
financial hedges will cover quantities of electricity that we estimate we can
produce with a high degree of certainty. As a result, gains or losses
under the financial hedges should be offset by decreases or increases in our
revenues from spot sales of electricity in liquid independent systems operator
markets. However, the actual amount of electricity we generate from
operations may be materially different from our estimates for a variety of
reasons, including variable wind conditions, catastrophic events such as fires,
earthquakes, storms and changes in weather patterns due to climate
change. To the extent actual amounts produced fall short of the
quantities covered in our financial hedges, we will not be hedged and we will be
exposed to commodity price risk. In the event a project does not
generate the amount of electricity covered by the related hedge, we could incur
significant losses under the financial hedge if electricity prices rise
substantially above the fixed prices provided for in the hedge. If a
project generates more electricity than is covered by the relevant hedge, the
excess production will not be hedged and the revenues we derive will be subject
to market price fluctuations.
We may
seek to sell forward a portion of our Renewable Energy Certificates in an effort
to hedge against future declines in Renewable Energy Certificate
prices. If our projects are unable to generate the amount of
electricity required to earn the Renewable Energy Certificates sold forward or
if we are unable for any reason to qualify our electricity for Renewable Energy
Certificates in relevant states, we may incur significant losses.
We may be
required to post cash collateral and issue letters of credit for obligations
under hedging arrangements, which may not be available on acceptable terms and
if available would reduce our capacity to borrow for other
purposes. Our inability to effectively manage market risks and our
hedging activities may have a material adverse effect on our business, financial
condition or results of operations. In addition, our hedging activities may also
limit our ability to realize the full benefit of increases in electricity prices
and Renewable Energy Certificates. See “Management’s Discussion and
Analysis of Financial Condition and Results of
Operations—Hedging.”
50
We
will be dependent upon the continued and uninterrupted operation of a limited
number of operating wind parks in a limited geographic area.
We intend
to shift the focus of our business towards ownership and operation of merchant
wind parks, but we currently have no owned wind energy projects in operation,
and we anticipate having only a limited number of wind parks in operation over
the next two years. As a result, in future our operations may be
subject to material interruption if any of our wind parks is damaged or
otherwise adversely affected by one or more accidents, severe weather or other
natural disasters. Tornados, lightning strikes, floods, severe
storms, wildfires or other exceptional weather conditions or natural disasters
could damage our wind energy projects and related facilities and decrease
production levels. These events could have a material adverse effect
on our revenues, particularly to the extent that they affect multiple wind
energy projects and project sites. In addition, a majority of our
planned wind parks will be located in the three-state region of North Dakota,
South Dakota and Montana. If any of our future operating wind parks
experiences material interruptions or if the regulatory environment or energy
market characteristics in these states were to change in a manner adverse to us,
it could have an adverse effect on our business, results of operations and
financial condition.
Factors
beyond our control could cause us to experience increased costs with respect to
our wind energy projects.
Factors
such as:
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increases
in the costs of labor or materials,
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higher
than anticipated financing costs for our wind energy
projects,
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non-performance
by third-party suppliers or
subcontractors,
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turbine
breakdowns,
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electricity
network and other utility service failures,
and
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major
incidents and/or catastrophic events, such as fires, earthquakes or
storms,
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may cause
us to experience increased costs with respect to our wind energy
projects and have a material adverse effect on our business, financial
condition and results of operations.
The cost
of repairing or replacing damaged equipment may be considerable, and repeated or
prolonged interruption may result in termination of contracts, litigation and
substantial damages or penalties for regulatory or contractual non-compliance,
reduced cash flows and increased financing costs. Moreover, these
amounts may not be recoverable under insurance policies or contractual claims
and, in relation to network failures, network service providers and market
operators may also benefit from contractual limitations of liability, which
would reduce any recovery of damages from them.
In
addition, our wind turbines and associated equipment will also require routine
maintenance in order to continue to function properly. If the level
of maintenance and capital expenditure exceeds our projected or contracted
level, the cash flow available from the projects will be reduced, which may have
an adverse impact on our results of operations and financial
condition.
51
Our
key suppliers may experience technical issues with their wind turbine
technology.
Wind
turbine technology is constantly changing and improving, and it is possible that
turbine types installed by us may become obsolete. In addition, as
turbine manufacturers expand or are purchased by another company, support of
existing turbine models may cease. Supplier-related deficiencies may
result in a prolonged shutdown of a number of turbines. In addition,
a failure of performance may adversely affect our ability to arrange and close
turbine supply loans, tax equity financing transactions or construction loans
involving turbines. Moreover, turbine suppliers may not be able to
fund the obligations they may owe us or their other customers under outstanding
warranty agreements.
We
expect to rely on a limited number of key customers.
We do not
plan to enter into power purchase agreements unless they are offered on
favorable terms. However, to the extent we do enter into power
purchase agreements, we expect to depend on sales of electricity under those
power purchase agreements to a limited number of utilities. We also
expect to depend on sales of Renewable Energy Certificates to certain key
customers and on electricity marketing agreements with a limited number of
system owners and power marketing firms. Our operations will be
highly dependent upon such customers’ and marketers’ fulfilling their
contractual obligations under their agreements with us. Our customers
may not comply with their contractual payment obligations or may become subject
to insolvency or liquidation proceedings during the term of the relevant
contracts, and the credit support received from such customers may not be
sufficient to cover our losses in the event of a failure to
perform. An inability or failure by such customers to meet their
contractual commitments or insolvency or liquidation of our customers could have
a material adverse effect on our business, financial position and results of
operations.
We will
use utilities or power marketing firms to dispatch electricity from any projects
that do not have a power purchase agreement. These firms will act as
an intermediary between us and system operators, such as Midwest Independent
Transmission System Operator, who act as market makers for electricity
pricing. The failure or inability of these firms to properly sell our
electricity into the open market may lead to lower than expected project
revenues.
Our
development activities and operations are subject to environmental regulation
and risks from environmental hazards.
We are
subject to various safety, environmental and natural resource protection laws
and regulations in each of the jurisdictions in which we
operate. These laws and regulations require us to obtain and maintain
permits and approvals, undergo environmental review processes and implement
required environmental, health and safety programs and procedures to control
risks associated with the siting, construction, operation and decommissioning of
wind energy projects. We cannot predict whether all permits required
for a given project will be granted, whether the conditions associated with such
permits will be achievable or whether such permits will be the subject of
significant opposition. The denial of a permit essential to a project
or the imposition of conditions with which it is not practicable or feasible to
comply could impair or prevent our ability to develop a
project. Significant opposition and delay in the environmental review
and permitting process also could impair or delay our ability to develop a
project.
52
If we
fail to comply with our permits, we may be required to pay fines or curtail
production at our facilities. Violations of environmental laws in
certain jurisdictions, including with respect to certain violations of laws
protecting migratory birds and endangered species, may also result in criminal
penalties.
We have
incurred and will continue to incur capital and operating expenditures and other
costs in the ordinary course of business in complying with safety and
environmental laws and regulations in the jurisdictions in which we
operate. In addition, we may incur costs outside of the ordinary
course of business to compensate for any environmental harm caused by our
facilities, which may have a material adverse effect on our business, financial
condition and results of operations.
Operation
of wind parks may expose us to liability for injury to persons or
property.
The
nature of wind turbines as large rotating machinery, as well as the presence of
high voltage electrical systems, may result in personal injury and loss of life
and severe damage to or destruction of property and equipment, which could
result in suspension or termination of operations as well as the imposition of
civil or criminal penalties.
We
are not able to insure against all potential risks and may become subject to
higher insurance premiums.
In
addition to potential liability for injury to persons or property, our business
is exposed to many other risks inherent in the construction and operation of
wind energy projects, such as breakdowns, manufacturing defects, natural
disasters, terrorist attacks and sabotage. We are also exposed to
environmental risks. We believe we will be able to obtain insurance
with respect to our proposed activities as an owner-operator of wind parks with
coverages and limits customary for similarly situated businesses, but there can
be no assurance that such insurance will be or will remain available at rates
that are economic or at all. Failure to obtain insurance may hinder
or prohibit our ability to secure project financing. Our existing
insurance policies cover, and we would expect future policies to cover, losses
as a result of
force
majeure
, and natural disasters, but not terrorist attacks and
sabotage. In addition, our insurance policies are and will be subject
to annual review by our insurers, and these policies may not be renewed at all
or on similar or favorable terms. If we were to incur a serious
uninsured loss or a loss significantly exceeding the limits of our insurance
policies, the results could have a material adverse effect on our business,
financial condition and results of operations.
The
loss of one or more members of our senior management or key employees may
adversely affect our ability to implement our strategy.
We depend
on our skilled and experienced management team, including Timothy H. Simons, our
Chief Executive Officer. We would be materially adversely affected in
the event that the services of Mr. Simons or other management or key personnel
for any reason ceased to be available and adequate replacement personnel were
not found. We have not obtained key-man insurance on the life of Mr.
Simons. Such insurance may not be available in the future on terms
acceptable to us, and there can be no assurance we will be able to secure such
insurance. We also depend on our ability to attract qualified new
employees in order to meet our business objectives. If we lose a
member of the management team or a key employee, we may not be able to replace
him or her. Integrating new employees into our management team could
prove disruptive to our daily operations, require a disproportionate amount of
resources and management attention and ultimately prove
unsuccessful. An inability to attract and retain sufficient technical
and managerial personnel could limit or delay our development efforts, which
could have a material adverse effect on our business, financial condition and
results of operations.
53
Technological
changes in the energy industry could render existing wind energy projects and
technologies uncompetitive or obsolete.
The
energy industry, and especially the renewable energy industry, is rapidly
evolving and is highly competitive. Technological advances may result
in lower costs for sources of energy, and may render existing wind energy
projects and technologies uncompetitive or obsolete. Wind parks have
a long life (generally about 20 years), and cannot easily, or without
substantial expense, be upgraded to new turbine technology. Our
inability or failure to adopt new technologies as they are developed could have
a material adverse affect our business, financial condition and results of
operations.
Factors
over which we have little or no control may cause our operating results to vary
widely from period to period, which may cause our stock price to
decline.
Our
operating results may fluctuate significantly from period-to-period depending on
several factors, including varying weather conditions; changes in regulated or
market electricity prices; electricity demand, which follows broad seasonal
demand patterns; changes in market prices for Renewable Energy Certificates;
marking to market of our hedging arrangements and unanticipated development or
construction delays. Thus, a period-to-period comparison of our
operating results may not reflect long-term trends in our business and may not
prove to be a relevant indicator of future earnings. These factors
may harm our business, financial condition and results of operations and may
cause our stock price to decline.
Current
or future litigation or administrative proceedings could have a material adverse
effect on our business, financial condition and results of
operations.
Various
individuals and interest groups may sue to challenge the issuance of a permit
for a wind energy project or seek to enjoin construction of a wind energy
project. The costs related to investigation, as well as our own
internal investigation, could be significant. Unfavorable outcomes or
developments relating to hypothetical proceedings or investigations, such as
judgments for monetary damages and other remedies, including injunctions or
revocation of permits, could have a material adverse effect on our financing
plans, business, financial condition and results of operations, and we could
settle claims that could adversely affect our financial position and results of
operations.
54
Requirements
associated with being a public company will increase our costs significantly, as
well as divert significant company resources and management attention, which
could negatively impact our results of operations and/or distract management
from the business of project development and financing.
As a
reporting company under U.S. securities laws, and we will be obliged to comply
with the provisions of applicable U.S. laws and regulations, including the
Securities Act of 1933, as amended (the “Securities Act”), the Securities
Exchange Act of 1934 (the “Exchange Act”) and the Sarbanes-Oxley Act of 2002 and
the related rules of the Securities and Exchange Commission, and the rules and
regulations of the relevant U.S. market. We are working with our legal,
independent accounting and financial advisors to identify those areas in which
changes should be made to our financial and management control systems to manage
our growth and fulfill our obligations as a public company. These
areas include corporate governance, corporate control, internal audit,
disclosure controls and procedures, financial reporting and accounting
systems. We have made, and will continue to make, changes in these
and other areas. Preparing and filing annual and quarterly reports
and other information with the Securities and Exchange Commission, furnishing
audited reports to stockholders and other compliance with these rules and
regulations will involve a material increase in regulatory, legal and accounting
expenses and the time and attention of management, and there can be no assurance
that we will be able to comply with the applicable regulations in a timely
manner, if at all.
In
addition, being a public company could make it more difficult or more costly for
us to obtain certain types of insurance, including directors’ and officers’
liability insurance, and we may be forced to accept reduced policy limits and
coverage or incur substantially higher costs to obtain the same or similar
coverage.
Applicable
regulatory requirements, including those contained in and issued under the
Sarbanes-Oxley Act, may make it difficult for us to retain or attract qualified
officers and directors, which could adversely affect the management of our
business and our ability to obtain or retain listing of our common
stock.
We may be
unable to attract and retain those qualified officers, directors and members of
board committees required to provide for effective management because of the
rules and regulations that govern publicly held companies, including, but not
limited to, certifications by principal executive and financial
officers. The enactment of the Sarbanes-Oxley Act has resulted in the
issuance of a series of rules and regulations and the strengthening of existing
rules and regulations by the Securities and Exchange Commission, as well as the
adoption of new and more stringent rules by the stock exchanges. The
perceived increased personal risk associated with these changes may deter
qualified individuals from accepting roles as directors and executive
officers.
Further,
some of these changes heighten the requirements for board or committee
membership, particularly with respect to an individual’s independence from the
corporation and level of experience in finance and accounting
matters. We may have difficulty attracting and retaining directors
with the requisite qualifications. If we are unable to attract and
retain qualified officers and directors, the management of our business and our
ability to obtain or retain listing of our common stock on any stock exchange
(assuming we elect to seek and are successful in obtaining such listing) could
be adversely affected.
55
Risks
Related to Our Securities
There
is not now, and there may not ever be, an active market for our common
stock.
There
currently is a limited public market for our common stock. Further,
although our common stock is currently quoted on the OTC Bulletin Board (the
“OTCBB”), trading of our common stock may be extremely sporadic. For
example, several days may pass before any shares may be traded. As a
result, an investor may find it difficult to dispose of, or to obtain accurate
quotations of the price of, the common stock. There can be no
assurance that a more active market for the common stock will develop, or if one
should develop, there is no assurance that it will be sustained. This
severely limits the liquidity of the common stock, and would likely have a
material adverse effect on the market price of the common stock and on our
ability to raise additional capital.
We
cannot assure you that our common stock will become liquid or that it will be
listed on a securities exchange.
Until our
common stock is listed on a national securities exchange such as the New York
Stock Exchange or the Nasdaq National Market, we expect our common stock to
remain eligible for quotation on the OTCBB, or on another over-the-counter
quotation system. In those venues, however, an investor may find it
difficult to obtain accurate quotations as to the market value of our common
stock. In addition, if we fail to meet the criteria set forth in SEC
regulations, various requirements would be imposed by law on broker-dealers who
sell our securities to persons other than established customers and accredited
investors. Consequently, such regulations may deter broker-dealers
from recommending or selling our common stock, which may further affect the
liquidity of our common stock. This would also make it more difficult
for us to raise capital.
Our
common stock is subject to the “penny stock” rules of the SEC and the trading
market in our common stock is limited, which makes transactions in our common
stock cumbersome and may reduce the value of an investment in the
stock.
The SEC
has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for
the purposes relevant to us, as any equity security that has a market price of
less than $5.00 per share or with an exercise price of less than $5.00 per
share, subject to certain exceptions. For any transaction involving a
penny stock, unless exempt, the rules require:
|
|
·
|
that
a broker or dealer approve a person’s account for transactions in penny
stocks; and
|
|
|
·
|
the
broker or dealer receive from the investor a written agreement to the
transaction, setting forth the identity and quantity of the penny stock to
be purchased.
|
In order
to approve a person’s account for transactions in penny stocks, the broker or
dealer must:
|
|
·
|
obtain
financial information and investment experience objectives of the person;
and
|
56
|
|
·
|
make
a reasonable determination that the transactions in penny stocks are
suitable for that person and the person has sufficient knowledge and
experience in financial matters to be capable of evaluating the risks of
transactions in penny stocks.
|
The
broker or dealer must also deliver, prior to any transaction in a penny stock, a
disclosure schedule prescribed by the SEC relating to the penny stock market,
which, in highlight form sets forth:
|
|
·
|
the
basis on which the broker or dealer made the suitability determination;
and
|
|
|
·
|
that
the broker or dealer received a signed, written agreement from the
investor prior to the transaction.
|
Generally,
brokers may be less willing to execute transactions in securities subject to the
“penny stock” rules. This may make it more difficult for investors to dispose of
common stock and cause a decline in the market value of stock.
Disclosure
also has to be made about the risks of investing in penny stocks in both public
offerings and in secondary trading and about the commissions payable to both the
broker-dealer and the registered representative, current quotations for the
securities and the rights and remedies available to an investor in cases of
fraud in penny stock transactions. Finally, monthly statements have to be sent
disclosing recent price information for the penny stock held in the account and
information on the limited market in penny stocks.
The
price of our common stock may become volatile, which could lead to losses by
investors and costly securities litigation.
A trading
market for our common stock may not develop or be liquid. If you
invest in shares of our common stock, you may not be able to resell your shares
above the price you pay and may suffer a loss of some or all of your
investment.
Broad
market and industry factors may adversely affect the market price of our common
stock, regardless of our actual operating performance. The trading
price of our common stock is likely to be highly volatile and could fluctuate in
response to factors such as:
|
|
·
|
uncertainty
associated with the timing of project development and
completion;
|
|
|
·
|
extension
or expiration of the production tax credit and other changes in government
policy;
|
|
|
·
|
actual
or anticipated variations in quarterly operating
results;
|
|
|
·
|
volatility
in market prices for electricity and Renewable Energy
Certificates;
|
|
|
·
|
weather
conditions that may affect our
production;
|
|
|
·
|
changes
in financial estimates by us or by any securities analysts who may cover
our stock or our failure to meet the estimates made by securities
analysts;
|
57
|
|
·
|
changes
in the market valuations of other companies operating in our
industry;
|
|
|
·
|
announcements
by us or our competitors of significant acquisitions, strategic
partnerships or divestitures;
|
|
|
·
|
additions
or departures of key personnel; and
|
|
|
·
|
sales
of our common stock, including sales of our common stock by our directors
and officers or by our other principal
stockholders.
|
The stock
market is subject to significant price and volume fluctuations. In
the past, following periods of volatility in the market price of a company’s
securities, securities class action litigation has often been initiated against
the company. Litigation initiated against us, whether or not
successful, could result in substantial costs and diversion of our management’s
attention and resources, which could harm our business and financial
condition.
We
currently do not intend to pay dividends on our common stock for the foreseeable
future. As a result, your only opportunity to achieve a return on your
investment is if the price of our common stock appreciates.
We
currently do not expect to declare or pay dividends on our common stock for the
foreseeable future. We expect to use future earnings, if any, to fund
business growth. Therefore, stockholders will not receive any funds
absent a sale of their shares. We may also enter into agreements in
the future that prohibit or restrict our ability to declare or pay dividends on
our common stock. As a result, your only opportunity to achieve a
return on your investment will be if the market price of our common stock
appreciates and you sell your shares at a profit.
Securities
analysts may not initiate coverage or continue to cover our common stock, and
this may have a negative impact on its market price.
The
trading market for our common stock will depend in part on the research and
reports that securities analysts publish about our business and our
Company. We do not have any control over these
analysts. There is no guarantee that securities analysts will cover
the common stock. If securities analysts do not cover the common
stock, the lack of research coverage may adversely affect its market
price. If we are covered by securities analysts, and our stock is the
subject of an unfavorable report, our stock price would likely
decline. If one or more of these analysts ceases to cover our Company
or fails to publish regular reports on us, we could lose visibility in the
financial markets, which could cause our stock price or trading volume to
decline.
58
You
may experience dilution of your ownership interests due to the future issuance
of additional shares of our common stock.
We are in
a capital intensive business and we do not have sufficient funds to finance the
growth of our business or the construction costs of our development projects or
to support our projected capital expenditures. As a result, we will
require additional funds from further financings, including tax equity financing
transactions or sales of common or preferred stock, or other securities that are
convertible into or exercisable for our common or preferred stock, to complete
the development of new projects, fund project equity and pay the general and
administrative costs of our business. We may also issue such
securities in connection with hiring or retaining employees and consultants
(including stock options issued under our equity incentive plans), as payment to
providers of goods and services, in connection with future acquisitions or for
other business purposes. Our Board of Directors may at any time
authorize the issuance of additional common or preferred stock without common
stockholder approval, subject only to the total number of authorized common and
preferred shares set forth in our articles of incorporation. The
preferences and rights of any preferred stock we issue will be as determined by
our Board of Directors. The terms of equity securities issued by us
in future transactions may be more favorable to new investors, and may include
dividend and/or liquidation preferences, superior voting rights and the issuance
of warrants or other derivative securities, which may have a further dilutive
effect. The future issuance of such additional shares of common stock
or preferred stock or other securities may create downward pressure on the
trading price of our common stock. Any such future issuances of such
additional shares of common stock or preferred stock or other securities may be
at a price (have an exercise price) below the price you paid for your common
stock or the price at which shares of the common stock are then
traded.
|
ITEM
1B.
|
UNRESOLVED
STAFF COMMENTS
|
None.
|
ITEM
2.
|
PROPERTIES
|
Properties
We
generally do not own the property underlying our wind parks. Instead,
we usually obtain easements from the landowners that give us the right to
install our meteorological equipment, turbines, transmission lines and related
equipment and prohibit the landowners from building other structures that would
interfere with the operation or maintenance of the wind park. The
terms of the easement agreements vary, but usually cover a development period, a
construction period and a 20-year operational period, with our option to extend
the operational period for an additional 30 years. Our easement
agreements generally obligate us to make payments to the landowner based on
revenues to be generated from assets located on the landowner’s
property. During the construction phase of a particular wind park, we
may acquire land for the siting of facilities needed by the transmission system
operator to accommodate the wind park; we typically transfer these real estate
interests to the transmission system operator once construction of the wind park
is complete.
The land
control agreements for our projects in development start as a lease
option. The provisions of our land leases are substantially similar
for all of our land-control contracts—both Lease Option Agreements and Lease
Agreements. We will trigger the shift from lease option agreement to
lease agreement when construction on a project begins. We have no
leases currently, only lease options. Specific terms for individual
landowners may differ occasionally, but none of our current leases options
differs significantly from the general structure, which is summarized
here:
59
|
Option Agreement
|
Lease Agreement
|
|||
|
Term:
|
5
years
|
40
years
|
||
|
Annual
Payment:
|
$400/section
|
$2,500
per turbine plus
|
||
|
(640
acres)
|
$1,000
per MW nameplate
capacity
|
The lease
option agreement provides us with the right to conduct wind studies, access the
land, install meteorological towers and begin the permitting process with the
landowners’ cooperation. The term of the option agreement is five
years. We have a right of first refusal on other land owned by the
landowner within one half mile of the proposed site. We pay the
landowner at a rate of $100 per quarter-section of land (160 acres) annually, as
well as a one-time payment for any crop loss.
Once the
option to lease the land is exercised, the lease lays out the permitted uses of
the property, which include wind resource evaluations, wind energy conversion
systems, transmission facilities, waiver of setback and meeting with the
owner. It also gives us the right to travel across the land, as well
as to use access routes available. The lease prohibits the landowner
from constructing any building on the land without prior approval, to prevent
the obstruction of the wind.
The term
of the lease is forty years from the date it is the lease option exercised, and
we have the right to terminate the lease with 30 days notice, as can the
landowner, but only if there are no improvements built for the wind
park.
We pay
the landowner annually $2,500 per turbine plus $1,000 per megawatt of nameplate
capacity. If there are no turbines on the land, but there are
improvements made, such as underground lines or roads, the landowner will
receive a one-time payment of $2 per foot of underground improvement and $3 per
foot of above ground improvement. The increase in real estate taxes
caused by the increased value of the land due to turbines will be paid by us,
while the original value of the real estate taxes will be paid by the
landowner. Conservation Reserve Program (CRP) lands will be released
from the CRP program if necessary, and we will pay any applicable fees/fines and
will compensate the landowner for the loss of income through a one-time
payment. Crop loss is also covered by using a calculation of current
market price, number of acres damaged and average yield on the
land. In addition, Crownbutte is required to maintain $1,000,000 in
liability insurance.
Crownbutte
may elect to make debt payments on behalf of the landowner in order to preserve
its rights in the land by preventing foreclosure by a lender. The
Company’s lease payment obligations would be offset by the amount of any such
debt payment.
We also
have the right to encumber our interests with debt to finance the wind
park. We have the obligation to return the land to its original
condition at the end of the lease term by removing all turbines and removing
concrete down to four feet below the surface of the soil.
60
Description
of Corporate Offices
We lease
our corporate offices (approximately 3,000 square feet) at 111 5th Avenue NE,
Mandan, ND 58554. The current lease for our office space
is month-to-month, with a monthly rent of $1,500. We believe that our
current facilities are adequate for our operations as currently conducted and if
additional facilities are required, that we could obtain them at commercially
reasonable prices. Once we have owned projects in operation, we will
also require on-site project office space, which we intend to lease in the form
of office trailers or existing built out space.
|
ITEM
3.
|
LEGAL
PROCEEDINGS
|
From time
to time, we may become involved in various lawsuits and legal proceedings which
arise in the ordinary course of business. However, litigation is
subject to inherent uncertainties, and an adverse result in these or other
matters that may arise from time to time that may harm business.
Except
for the matter described below, other than routine litigation arising in the
ordinary course of business that we do not expect, individually or in the
aggregate, to have a material adverse effect on us, there is no currently
pending legal proceeding and, as far as we are aware, no governmental authority
is contemplating any proceeding to which we are a party or to which any of our
properties is subject, other than the Company’s applications for permits to
install or erect wind turbines or weather-monitoring equipment, which are
incidental to the business of the Company.
Although
there can be no assurance as to the ultimate outcome, we have denied liability
in the case pending against us, and we intend to defend vigorously such
case. Based on information currently available, we believe the
amount, or range, of reasonably possible losses in connection with the action
against us not to be material to our consolidated financial condition or cash
flows. However, losses may be material to our operating results for
any particular future period, depending on the level of income for such
period.
On August
19, 2008, Centre Square Capital, LLC filed a claim with the American Arbitration
Association in the amount of $3,000,000 plus attorneys’ fees, interest, and
arbitration costs in a demand for arbitration, claiming that the Company has not
compensated it for introducing the Company to the firm that identified the
Company’s private placement investors in March 2008 and
thereafter. The Company maintained that the agreement pertains only
to funds raised as a result of business with the People’s Republic of
China. On March 16, 2009, the court dismissed the plaintiff’s claim
and awarded the Company reimbursement of all attorney fees and costs related to
the claim. A reimbursement of approximately $129,227 is payable to
the Company.
As of the
date of this report and as disclosed in the accompanying notes to audited
consolidated financial statements for the year ended December 31, 2009, the
Company has received $0 of the damages awarded on March 16, 2009. We
believe there will be no recovery of this award.
Subsequent
to the damages award, the Company was threatened with litigation over
non-payment of attorney fees related to the Centre Square Capital arbitration
and defense. On November 3, 2009, the Company was served with a
lawsuit filed in the Philadelphia County Court of Common Pleas by Stradley,
Ronon, Stevens & Young, LLP, seeking to recover $93,526 plus interest,
attorneys’ fees, and costs. On December 14, 2009, the Company
received a Notice of Intent to Take Default Judgment for the unpaid balance of
$93,526. The Company has been working with the plaintiff to make
payments on the debt. In exchange, the plaintiffs have agreed to
postpone execution of the judgment.
61
As of the
date of this report, the Company owes Stradley, Ronon, Stevens & Young, LLP
$78,526. We anticipate paying the balance in full upon closing of the
Gascoyne I financing, which is scheduled to occur on or before April 30,
2010. There is no guarantee the financing will be approved or that we
will have the capital available to pay this debt.
If the
Gascoyne I financing does not materialize or the Company cannot raise sufficient
capital through the sales of its equity securities, there is no guarantee the
judgment against us will not be exercised. Should they do so, the
only liquid assets available to satisfy the judgment are the Company’s
interconnect application deposits. Forfeiture of the deposits would
significantly impair the status of our project queue positions. Loss
of queue position may require new applications, additional deposits and
development costs, and several years to obtain shovel-ready status.
|
ITEM
4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY
HOLDERS
|
No
matters were submitted to a vote of security holders, through the solicitation
of proxies or otherwise, during the fourth quarter of the fiscal year covered by
this Annual Report.
Market
Information and Holders
As of
April 14, 2010, there were 32,257,472 shares of our common stock issued and
outstanding and 8,350,034 shares issuable upon exercise of outstanding
warrants. On that date, there were approximately 74 holders of record
of shares of our common stock.
We have
no outstanding shares of preferred stock.
Since
December 2, 2009, our common stock has been quoted on the OTCBB under the
trading symbol “CBWP.OB.” Through December 1, 2010, trades of our
common stock were reported on the Pink Sheets (www.pinksheets.com) under the
symbol “CBWP.PK.” The last reported sale price of our common stock on
the OTCBB on April 14, 2010 was $0.29.
Trades in
our common stock may be subject to Rule 15g-9 under the Exchange Act, which
imposes requirements on broker/dealers who sell securities subject to the rule
to persons other than established customers and accredited
investors. For transactions covered by the rule, broker/dealers must
make a special suitability determination for purchasers of the securities and
receive the purchaser’s written agreement to the transaction before the
sale.
62
The SEC
also has rules that regulate broker/dealer practices in connection with
transactions in “penny stocks.” Penny stocks generally are equity
securities with a price of less than $5.00 (other than securities listed on
certain national exchanges, provided that the current price and volume
information with respect to transactions in that security is provided by the
applicable exchange or system). The penny stock rules require a
broker/dealer, before effecting a transaction in a penny stock not otherwise
exempt from the rules, to deliver a standardized risk disclosure document
prepared by the SEC that provides information about penny stocks and the nature
and level of risks in the penny stock market. The broker/dealer also
must provide the customer with current bid and offer quotations for the penny
stock, the compensation of the broker/dealer and its salesperson in the
transaction, and monthly account statements showing the market value of each
penny stock held in the customer’s account. The bid and offer quotations, and
the broker/dealer and salesperson compensation information, must be given to the
customer orally or in writing before effecting the transaction, and must be
given to the customer in writing before or with the customer’s
confirmation. These disclosure requirements may have the effect of
reducing the level of trading activity in the secondary market for shares of our
common stock. As a result of these rules, investors may find it
difficult to sell their shares.
The
following table sets forth (i) for the period from December 2, 2009 through
April 14, 2010, the high and low closing bid prices for our common stock, as
reported on the OTCBB and (ii) for the period from January 1, 2008 through
December 1, 2009, the range of high and low closing quotations for our common
stock, as reported by Pink OTC Markets Inc. on its web site located at
www.pinksheets.com. The quotations reflect inter-dealer prices,
without retail mark-up, mark-down or commission and may not represent actual
transactions. Our common stock is thinly traded and, thus, pricing of
our common stock on the OTCBB does not necessarily represent its fair market
value.
|
High
|
Low
|
|||||||
|
Fiscal
Year Ended December 31, 2010
|
||||||||
|
January
1, 2010 – April 14, 2010
|
0.910000 | 0.200000 | ||||||
|
Fiscal
Year Ended December 31, 2009
|
||||||||
|
December
2, 2009 – December 31, 2009
|
0.280000 | 0.130000 | ||||||
|
October
1, 2009 – December 1, 2009
|
0.360000 | 0.110000 | ||||||
|
Quarter
ended September 30, 2009
|
0.550000 | 0.062000 | ||||||
|
Quarter
ended June 30, 2009
|
0.550000 | 0.050000 | ||||||
|
Quarter
ended March 31, 2009
|
4.400000 | 0.500000 | ||||||
|
Fiscal
Year Ended December 31, 2008
|
||||||||
|
Quarter
ended December 31, 2008
|
0.550000 | 0.250000 | ||||||
|
Quarter
ended September 30, 2008
|
6.570302 | 0.006570 | ||||||
|
Quarter
ended June 30, 2008
|
0.006570 | 0.006570 | ||||||
|
Quarter
ended March 31, 2008
|
0.013141 | 0.006570 | ||||||
Dividends
On March
11, 2008, a distribution of $153,333 was made by Crownbutte ND in conjunction
with its change from “S corporation” to “C corporation” tax
status. We have otherwise never declared or paid cash dividends on
our equity securities. We do not intend to pay cash dividends on our
common stock for the foreseeable future, but currently intend to retain any
future earnings to fund the development and growth of our
business. The payment of dividends, if any, on the common stock will
rest solely within the discretion of our Board of Directors and will depend,
among other things, upon our earnings, capital requirements, financial
condition, and other relevant factors.
63
Securities
Authorized for Issuance under Equity Compensation Plans
As of the
end of the most recently completed fiscal year, we have not adopted any
compensation plan (including any individual compensation arrangement) under
which our equity securities are authorized for issuance.
See
“Executive Compensation” for information regarding individual equity
compensation arrangements received by our executive officers pursuant to their
employment agreements with our Company.
Recent
Sales of Unregistered Securities
On
February 22, 2010, we had a closing of a private placement offering for an
aggregate of 557,141 units of our securities at a purchase price of $0.35 per
unit, for an aggregate cash consideration of $195,000, before deducting offering
costs. Each unit consists of (i) one share of our common stock, (ii)
a warrant to purchase one share of our common stock, exercisable for a period of
four years at an exercise price of $1.50 per share, and (iii) a warrant to
purchase one share of our common stock, exercisable for a period of four years
at an exercise price of $2.50 per share.
The
private placement offering was conducted pursuant to the exemption from the
registration requirements of the federal securities laws provided by Regulation
D and Regulation S promulgated under the Securities Act and Section 4(2) of the
Securities Act. The common stock was offered and sold only to
“accredited investors,” as that term is defined by Rule 501 of Regulation D,
and/or to persons who were neither resident in, nor citizens of, the United
States. No commissions were paid in connection with the
offering.
On March
29, 2010, the Company issued a total of 400,000 shares of common stock in
exchange for short-term loans from two of the Company’s
stockholders. Terms of the loans are $100,000 payable in 60 days for
150,000 shares of common stock in lieu of interest, and $100,000 payable in 60
days for 250,000 shares of common stock in lieu of
interest. Principal payments on both loans are due June 7,
2010. Our issuance of the shares in connection with the promissory
notes was not registered under the Securities Act in reliance upon the exemption
from registration provided by Section 4(2) of the Securities Act, which exempts
transactions by an issuer not involving any public offering.
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers
Except in
connection with the issuances described above, during the fourth quarter of the
fiscal year covered by this Annual Report, no purchases were made by or on
behalf of the Company or any “affiliated purchaser,” as defined in Rule
10b-18(a)(3) under the Exchange Act, of shares or other units of any class of
the Company’s equity securities.
64
Not
applicable.
The
following discussion and analysis of financial condition and results of
operations should be read in conjunction with our consolidated financial
statements and related notes included elsewhere in this Annual Report on Form
10-K. This discussion contains forward-looking statements that involve risks,
uncertainties and assumptions. See “Note Regarding Forward-Looking Statements.”
Our actual results could differ materially from those anticipated in the
forward-looking statements as a result of certain factors discussed in “Risk
Factors” and elsewhere in this Annual Report on Form 10-K.
Overview
Based in
Mandan, ND, Crownbutte Wind Power, Inc. is an independent wind energy company
focused exclusively on the development, ownership and operation of wind energy
projects. One wind park developed by us from “green-field” or blank
state to operation was purchased directly in 2002 by Basin Electric Power
Cooperative (2.6 megawatts (MW) near Chamberlain, South Dakota. In
addition to this operating park, we have completed various consulting activities
with regional utilities and international energy companies. Our goal
is to develop, own and operate merchant wind parks in the 20-60 MW capacity
range. As of December 31, 2010, our portfolio of wind energy projects
included approximately 638 MW (0 MW currently in operation) of prospective
capacity in various stages of development primarily in the Dakotas and
Montana.
The first
wind park that we plan to build, own and operate is a 20 MW project called
Gascoyne I located south of Dickinson, North Dakota. Our goal is to
have approximately 20 MW of owned operating capacity by the end of 2010, and we
target the construction and commissioning of approximately 40 MW of owned
operating capacity in 2011. We do not currently and do not plan to
act as an operator of wind parks we do not own.
Our
business model focuses on the development of merchant parks. We do
not plan to enter into power purchase agreements unless they are offered on
favorable terms.
Going
Concern
As
indicated in the accompanying consolidated financial statements, we have
incurred recurring losses from operations resulting in an accumulated deficit at
December 31, 2009 of $5,539,075. These conditions raise substantial
doubt as to our ability to continue as a going concern. There can be
no assurance that we can sell stock or debt or that financing will be available
to us in the future. In the event that we cannot create a source of
recurring revenues or that we do not receive funds from other sources, we may be
unable to continue to operate as a going concern. Our consolidated
financial statements do not include any adjustments that might be necessary if
we are unable to continue as a going concern.
65
Major
Events and Material Transactions
Chamberlain,
SD
In April
2001, we sold a fully-constructed 2.6 MW wind park near Chamberlain, SD, to
Basin Electric Power Cooperative for $2,567,149 plus a maintenance contract
through the end of 2002 worth $24,200.
Buffalo
Ridge, MN
In July
2002, we entered into a consulting/advisory agreement with Suzlon Energy
Limited, regarding a 20 MW wind park to be developed and constructed near
Buffalo Ridge, MN. The agreement expired in December
2002.
Gascoyne
I, ND
In
December 2006, we sold development rights to a 20 MW park near Gascoyne, ND, to
Boreal Energy Inc. for $325,000. Boreal did not proceed with
construction of this park. In September, 2008, we re-acquired
development rights to this site (Gascoyne I) from Boreal Energy for the same
amount ($325,000).
As
indicated in the accompanying consolidated financial statements, on February 15,
2010 the Company executed a non-binding term sheet with a private equity firm to
provide $37.5 million debt financing for the Gascoyne I
project. Terms of the financing provide for an 80% ownership interest
to the lender with the Company retaining a 20% stake in the special-purpose
entity. The consummation of this financing is subject to, among other
things, satisfactory completion by the lender of all necessary technical and
legal due diligence and satisfactory negotiation of all required definitive
agreements necessary or desirable to effect the transaction. We
anticipate a construction completion and operational date by the end of 2010 or
early 2011.
Financing
of this project may result in a development fee to Crownbutte of approximately
$1 million. This project may also be eligible for a U.S.
Treasury Department renewable energy grant equal to 30% of the authorized
capital costs. This grant, if approved, would total approximately $10
million and provide additional funds to the Company through a 20% distribution
of net profits/cash flow from the special purpose entity.
Baker,
MT
In July
2007, we completed a consulting/advisory engagement with Montana-Dakota Utility
(MDU) to oversee development and construction of a 19.5 MW wind park near Baker,
MT, for total consideration of $473,000 (of which 400,000 was received in 2007
and the balance in 2008).
Berthold,
ND
In
January 2008, we entered into a joint development agreement with Evergreen
Energy (the land owner) regarding a 60 MW park located near Berthold,
ND. The parties agreed to split proceeds (2/3 Crownbutte, 1/3
Evergreen) in the event that the park is sold.
66
Gascoyne
II, ND
In 2007,
we received $70,100 to conduct feasibility analysis for a 200 MW site near
Gascoyne, ND (different from the Gascoyne I project) on behalf of Westmoreland
Coal. If the project was deemed feasible, then Westmoreland would
have the right of first refusal to jointly develop the Gascoyne II site
alongside Crownbutte. In May 2008, we elected to move forward on this
site, and sold 40% of the rights to develop, construct, manage, and operate this
200 MW wind power project in southwest North Dakota to Westmoreland
Coal. Westmoreland paid us $200,000 in
consideration. Future capital contributions into the venture will be
50% each, although the share of capital will be 60% Crownbutte and 40%
Westmoreland. We will be the managing party.
Ralls,
TX
In July
2008, we agreed to purchase development rights from American Seawind Energy LLC
for a 10 MW wind park near Ralls, TX. The agreement calls for a power
purchase agreement (“PPA”), or qualifying facility (“QF”) off-take arrangement
to be in place before construction. Purchase price was $1,500,000,
with $200,000 due upon signature, $1,000,000 due on the earlier of construction
start or March 2009, and the remaining $300,000 due upon construction
completion. In December 2008, we determined that we would not pursue
this project any further due to difficulties in securing a PPA and project
financing.
Our
Strategy
The
electricity generated by all of our owned and operated wind parks will be sold
under the best available arrangement for “off-taking” (the term for the act of
accepting the flow of electricity offered by the generator, in this case the
wind park owner/operator). In many wind developments in the past,
this has occurred under a power purchase agreement (PPA) with a
utility. In the Western North Dakota/Eastern Montana region, we have
experienced the reality that PPA’s are difficult to secure, and when available,
they have been at relatively unattractive price levels (
e.g.
,
$0.04/kWh). This phenomenon is likely the result of the relative
abundance of cheap coal in the area, and a high number of coal-fired power
plants owned by the local utilities.
Therefore,
we have adopted the strategy of selling power on the local nodes of the Midwest
Independent Systems Operator (“MISO”), using the available real-time spot
market, as well as the day-ahead contract market. In this MISO
footprint area, the relevant nodal prices have been trending upward for the past
few years and have recently averaged over $0.048/kWh (see graph below), which we
believe is an attractive enough price to make project finance models workable
for the raising of construction capital.
67
The
reliance on the merchant market (
i.e.
, the lack of PPAs) can
be a significant barrier to achieving project finance with tax equity investors
(as described below), many of whom seek the security of long-term PPAs with
off-takers. The possibility that the spot price of electricity will
drop is also a risk to our business strategy. Finally, we are
exploring the viability of hedging against the possible drop of local
electricity prices. In the MISO footprint, the availability of solid
hedging instruments (with high correlations to the local power market price
histories) has been the focus of our investigations. A risk remains
that a viable hedging methodology is not possible in the MISO footprint, which
would represent an overall risk to the success of the business model, and is a
possible barrier to achieving project financing.
We have
entered into negotiations with and have received quotes from multiple suppliers
(including GE, ACCIONA, Gamesa and DeWind) for purchase of turbines for our
first planned park construction, with a delivery target of September
2010. We believe that the turbines that we require for our project
development schedule will be available on a timely basis provided that we can
obtain turbine financing. Generally, turbine suppliers require
up-front payments upon execution of a turbine supply agreement and significant
progress payments well in advance of turbine delivery. See the
discussion of “Project Finance” below. We expect this supply will be
sufficient and timely for our anticipated construction schedule.
The
primary challenges we face include our limited operating history, our lack of
any owned operating wind parks and expected dependence on a limited number of
owned operating wind parks for the foreseeable future, increasing costs in all
areas of our business, tighter terms and conditions on debt and tax equity
financing available to us, the amount of capital we need to raise to consummate
our business plan, the availability of turbines, the uncertainty created by
efforts to extend the production tax credit and the vulnerability of our wind
parks to meteorological and atmospheric conditions. Our ability to
complete the projects in our development pipeline and achieve our targeted
capacity is subject to these and a number of other risks and uncertainties as
described in the “Risk Factors” section of this Annual Report.
Since
1999, we have focused on seeking the most attractive wind regimes at sites that
are very close to existing transmission lines with high likelihood of available
electricity transmission capacity. We believe our attention to the
existing transmission infrastructure will contribute to a lower construction
cost due to a lessened need for transmission plant upgrades, as well as improved
time to achieve an interconnection agreement with the local utility and systems
operator. Selecting optimal sites on butte tops (
i.e.
, consistently high winds
with low turbulence) should ensure high net capacity factors. As a
result, we have amassed a pipeline of attractive wind parks, the first of which
are ready for construction financing.
68
Green-field
development of wind park sites is a process that generally takes approximately
24 months and $200,000 to $300,000 of development expense. The
sequence of steps that we follow in this process is generally as
follows:
|
|
1.
|
Identify
the transmission capability
|
|
|
2.
|
Conduct
topographical studies
|
|
|
3.
|
Configure
an initial park array
|
|
|
4.
|
Procure
the necessary land lease options
|
|
|
5.
|
Install
site-specific meteorological
instrumentation
|
|
|
6.
|
Accumulate
sufficient meteorological data
|
|
|
7.
|
Select
turbine type
|
|
|
8.
|
Prepare
a wind report (by a certified consulting
meteorologist)
|
|
|
9.
|
Apply
for local/state/federal permitting and transmission queue
position
|
|
|
10.
|
Secure
interconnect agreement
|
|
|
11.
|
Prepare
site design, including geotechnical studies for the
foundations
|
|
|
12.
|
Execute
turbine supply agreement
|
|
|
13.
|
Retain
construction contractor(s)
|
|
|
14.
|
Prepare
the final site designs (including high voltage systems, access roads,
junction boxes etc.)
|
The
additional steps after completion of the development phase are:
|
|
15.
|
Finalize
project financing
|
|
|
16.
|
Order
long lead-time items
|
|
|
17.
|
Construction
|
|
|
18.
|
Turbine
Commissioning
|
|
|
19.
|
Operation
and Maintenance.
|
69
Our
current pipeline of projects includes 12 projects totaling 638 MW (0 MW
currently in operation) of potential capacity. The table below
provides information on our projects in development, including the stage of
development based on the 14 steps outlined above:
Crownbutte
Projects in Development
|
Park
Size
|
Net
Capacity
|
Development
|
|||||||||||
|
Project
|
State
|
(MW)
|
Factors
|
Steps
Completed
|
|||||||||
|
1
|
Gascoyne
I
|
ND
|
20 | 41.2 | % |
Steps
1- 10
|
|||||||
|
2
|
New
England
|
ND
|
60 | 43.0 | % |
Steps
1-8
|
|||||||
|
3
|
Wibaux
|
MT
|
20 | 40.0 | % |
Steps
1-9
|
|||||||
|
4
|
Elgin
|
ND
|
20 | 38.0 | % |
Steps
1-9
|
|||||||
|
5
|
Berthold
|
ND
|
60 | 37.0 | % |
Steps
1-9
|
|||||||
|
6
|
Carson
|
ND
|
20 | 37.0 | % |
Steps
1-6
|
|||||||
|
7
|
Gascoyne
II
|
ND
|
200 | 43.6 | % |
Steps
1-9
|
|||||||
|
8
|
Tappen
|
ND
|
98 | 40.0 | % |
Steps
1-6
|
|||||||
|
9
|
Monarch
|
MT
|
60 | 39.0 | % |
Steps
1-6
|
|||||||
|
10
|
Mobridge
|
SD
|
40 | 36.0 | % |
Steps
1-5
|
|||||||
|
11
|
Scobey
|
MT
|
20 | 41.0 | % |
Steps
1-6
|
|||||||
|
12
|
Big
Sandy
|
MT
|
20 | 35.0 | % |
Steps
1-4
|
|||||||
We
believe we are ready to make the transition to owner-operator, in addition to
developer, of wind energy generation sites. This transition would
result in the addition of a new stream of revenue from the sales of electricity
generated by owned wind energy assets, as well as the sale of associated
Renewable Energy Certificates (“RECs”). We intend to construct as
many of the projects in our pipeline as possible. The total number we
are able to construct will be a function of our success in securing project
financing.
Since we
will need to cover our corporate overhead and expenses during the period until
cash flows from owned and operated wind projects generate enough income to do
so, it will be necessary to sell the development rights to at least one of the
projects currently in our pipeline. Which project’s development
rights are sold has not yet been determined and is subject to the desires of
potential purchasers more than to us.
In March
and April 2008, Crownbutte ND sold an aggregate of 1,100,000 units of its
securities in a private placement at a purchase price of $0.50 per unit, for an
aggregate cash consideration of $550,000, before deducting offering
costs. Each unit consisted of one share of Crownbutte ND common stock
and a warrant to purchase one share of Crownbutte ND common stock, exercisable
for a period of three years at an exercise price of $0.50 per
share. (Upon the closing of the merger, these units converted into an
aggregate of 1,100,000 shares of our common stock and warrants to purchase
1,100,000 shares of our common stock with the same terms.)
Concurrently
with the closing of the merger on July 2, 2008, we consummated a private
placement of 1,350,000 units of our securities at a purchase price of $0.50 per
unit, for an aggregate cash consideration of $675,000, before deducting offering
costs. Each unit consists of one share of our common stock and a
warrant to purchase one share of our common stock, exercisable for a period of
two years at an exercise price of $2.50 per share. On July 18, 2008,
we sold an additional 850,000 units for an aggregate cash consideration of
$425,000; on August 12, 2008, we sold an additional 678,000 units for an
aggregate cash consideration of $339,000; and on September 8, 2008, we sold an
additional 240,000 units for an aggregate cash consideration of $120,000, all as
part of the same private placement.
70
In
February 2010, we consummated a private placement of 557,141 units of our
securities at a purchase price of $0.35 per unit, for an aggregate cash
consideration of $195,000, before deducting offering costs. Each unit
consists of (i) one share of our common stock, (ii) a warrant to purchase one
share of our common stock, exercisable for a period of four years at an exercise
price of $1.50 per share, and (iii) a warrant to purchase one share of our
common stock, exercisable for a period of four years at an exercise price of
$2.50 per share.
We plan
to raise an additional approximately $1 million through private placements of
equity by the end of 2010, the proceeds of which, together with cash on hand,
will be used for general corporate expenses associated with the hiring of new
staff required to accelerate our development activities, as well as move into
our new owner-operator business model, which requires oversight of construction
of projects, as well as the operations and maintenance of projects after
construction is complete. However, we may be unable to secure this
additional financing on terms acceptable to us, or at all, at times when we need
such financing. Our inability to raise these additional funds on a
timely basis could prevent us from achieving our business objectives and could
have a negative impact on our business, financial condition, results of
operations and the value of our securities. We do not anticipate a
need to raise additional equity financing beyond this $1 million to fund
development, operating and maintenance costs. These fundings do not
include project financing. See “—Project Finance” and “—Liquidity and
Capital Resources” below.
Green-field
Development and Sale of Development Rights
The
current business model for Crownbutte is to develop likely sites from a
green-field or blank-slate status into a state that is “construction-ready” or
“shovel-ready.” This process can take two to four years and from
$200,000-$400,000 of expenses for each project. Development rights to
projects can be sold at any time to entities that take responsibility for
completing any remaining development, raising project finance and completing
construction. The development rights to a park may change hands
several times before construction is actually started.
Generally
speaking, pricing is discussed and negotiated on a “per-megawatt”
basis. Prices for the purchase of development rights for specific
parks can vary widely based on a number of factors, including:
|
|
·
|
engineered
generation capacity
|
|
|
·
|
wind
regime
|
|
|
·
|
topography
|
|
|
·
|
amount
of land under control
|
|
|
·
|
nearest
transmission inter-connect point
|
|
|
·
|
transmission
capacity of nearest transmission
line(s)
|
|
|
·
|
on-site
meteorological data gathering
equipment
|
|
|
·
|
completed
wind resource assessments
|
|
|
·
|
permitting
|
|
|
·
|
interconnection
application deposits
|
We intend
to continue development of projects currently in our
pipeline. We also intend to sell one to two parks per year to
interested parties for the purpose of covering corporate expenses until such
time we are able to generate sufficient revenues and cash flow solely from the
ownership and operation of developed parks. We estimate that on-going
green-field development activities cost approximately $800,000 to $850,000 per
year in total. Although there can be no guarantee, because pricing
varies and the number of transactions is small, we estimate that the sale of 20
to 40 MW of development rights per year should cover our green-field development
costs.
71
Project
Finance
The basic
gating element in constructing wind parks is the raising of project
finance. We estimate (based on most recent quotes from suppliers,
contractors, and vendors) that the cost of constructing a wind park is $1.8 to
$2 million per megawatt of rated generation capacity. For the
Gascoyne I project (20 MW), the first wind park we plan to construct, this means
a necessary project financing amount of $38,000,000.
Failure
to secure the required project financing is a significant risk to our operating
plan. Without project financing, we have no alternatives to
monetization of our development efforts other than the sale of the development
rights to entities that are able to assemble the necessary project finance to
enable construction. Inability to raise project finance would mean
that we would be relegated to being solely a green-field developer and not an
owner-operator. In this scenario, total profits would be
significantly smaller in magnitude than in the case of success with the
owner/operator model.
We plan
on financing our projects one or two at a time with the best available
combination of debt, tax equity financing and equity capital. At the
initial stage of a project’s development, for example, we could use a
combination of equity capital and turbine supply loans to cover development
expenses and turbine costs. Turbine supply loans would be employed to
finance approximately 60-90% of the cost of a project’s
turbines. Once a project moves to the construction phase, we could
use a combination of equity capital and construction loans to finance the
construction of the project. Proceeds from the construction loans are
typically used to fund construction and installation costs as well as to retire
the turbine supply loans. Finally, once a project is complete and
commercial operations begin, we would permanently finance the project through a
combination of term loans and equity financing transactions, the proceeds of
which would be used to retire the construction loans and provide for a return of
a portion of equity capital. Although the percentage of each of these
three forms of permanent financing varies regionally and by project, tax equity
financing (discussed below) typically represents a majority of a project’s
permanent financing.
We
continue to pursue project financing opportunities with a large number of
finders and private equity firms for the Elgin and Wibaux projects, which total
40 MW. There can be no guarantees these efforts will result in the
necessary funding for these projects. In both cases, the projects
themselves would be owned by a special-purpose entity and would be financed on a
limited recourse basis, and could benefit from the production tax credit (“PTC”)
or investment tax credit (“ITC”), or the U.S. Treasury Department renewable
energy grant program in lieu of investment tax credits or production tax
credits, and the Modified Accelerated Cost Recovery System of the Internal
Revenue Code (“MACRS”) tax benefits during the operating life of the
project itself (typically 20 years).
72
Turbine
supply loans
The
majority of the total cost of a wind energy project is attributable to turbine
purchases. Our turbine purchases will be our principal capital
expenditure. During the construction of our first planned park,
Gascoyne I, turbine costs will comprise roughly $28 million of a total estimated
$38 million capital cost.
In recent
years, the combined effect of a limited number of turbine suppliers, the
weakening dollar, rising commodity costs and increasing demand for turbines has
led to escalating turbine prices. To mitigate supply-related
uncertainty, we will seek to secure and finance our anticipated turbine needs in
advance of our targeted installation dates. We are looking at quotes
from GE and from Gamesa (both established suppliers), as well as from DeWind (a
newer entrant into the U.S. wind turbine market) and Acciona. We have
seen some evidence of softening turbine prices and shorter delivery lead times
as the financial market turmoil during the autumn of 2008 have slowed the
installation of new wind capacity. While we currently have no
turbines under contract, we expect that the turbines that we require for our
project development schedule will be available on a timely basis provided that
we can obtain turbine financing.
Generally,
turbine suppliers require up-front payments upon execution of a turbine supply
agreement and significant progress payments well in advance of turbine
delivery. We expect to finance our turbine supply agreements through
a combination of turbine supply loans and equity capital. Equity
capital contributions to each project are anticipated to vary from 10-100%,
depending on the terms available from turbine supply loan lenders.
Development
financing
We have
historically funded the development expenditures of our turn-key projects,
primarily consisting of permitting, community outreach and meteorological
expenses, through income derived from consulting projects, construction
oversight, or outright sale of partially-developed wind parks. In the
future, we expect to fund the development of our owned and operated wind energy
projects with a combination of cash flows from operations (sale of electricity,
sale of RECs, and sale of partially-completed projects), the proceeds of the
completed private placements of equity, and future debt and/or equity
offerings.
Construction
loans
After we
have developed a wind energy project to the point where we are prepared to
commence construction, we typically expect to enter into a limited recourse
construction loan. Proceeds from construction loans are typically
used to retire turbine indebtedness and to pay construction costs, including
costs to construct roads, substations, transmission lines and the balance of
plant. Construction loans are generally secured by the project’s
assets. In certain instances we may enter into a construction loan
for a single project, while in other instances we may be able to finance
multiple projects through a single credit facility. We will also use
equity capital contributions (from other investors and potentially our own as
described above) to fund a portion of each project’s construction
costs.
73
We would
forego the need for construction loans (as well as turbine supply loans) if we
are able to secure 100% debt or 100% equity-based investment for any given
project. A 100% debt financing would be done on a limited recourse
basis and be secured by the project assets and our equity. In a 100%
equity financing, the outside equity investors would contribute all of the
project costs as equity in return for an 80% to 90% share of the
returns. However, while we are exploring these possibilities, these
structures have not in the past been the norm in the wind generation industry
and may not be available. As discussed in the Recent Developments
section and elsewhere in this report, the proposed 100% debt financing with 80%
ownership stake for our Gascoyne I project is unique and we do not anticipate it
as the norm for future projects.
Financing
upon commencement of commercial operations
Once
construction of a wind energy project is completed and commercial operations
commence, we would seek to finance the project on a long-term basis through a
combination of term loans and tax equity financing, as described in more detail
below.
Term loans.
Term
loans provide long-term debt financing and are repaid with project cash
flows. In conjunction with term loans, a project that has a PPA may
maintain a separate credit facility to provide letters of credit required under
the PPA. We expect our project subsidiaries that raise term loan
financing generally to secure these term loans through pledges of our equity
interests in the project companies.
Tax equity
financing.
We generally will seek to secure tax equity
financing to provide the majority of each project’s permanent capital needs for
projects constructed after 2010. In a typical tax equity financing,
we expect to receive a capital investment for a portion of a project’s cost in
exchange for an equity interest in our subsidiary that owns the
project. These equity interests entitle the tax equity investors to
receive a portion of the project’s cash distributions from electricity sales and
related hedging agreements, PTCs and taxable income or loss until such investors
reach an agreed rate of return on their investment, which we typically expect to
occur in ten years. The availability of tax equity financing depends
on federal tax attributes that encourage renewable energy
development. These attributes primarily include (i) renewable
energy PTCs, which are federal income tax credits related to the quantity of
renewable energy produced and sold during a taxable year and
(ii) accelerated depreciation of renewable energy assets as calculated
under MACRS.
The PTC
incentive currently provides a $21 federal tax credit per megawatt hour
(“MWh”) for a renewable energy facility that uses wind, geothermal or
“closed-loop” bioenergy fuel sources in each of the first ten years of its
operation, and applies to facilities that are placed in service before the end
of 2012. These facilities will continue to benefit from the current
PTC incentive until the end of the ten-year period from the date on which the
facilities are placed in service. Our current tax equity financing
model is substantially dependent on the PTC incentive, and to the extent it is
not extended our anticipated growth will be adversely affected. The
growth of our business depends upon the extension of the expiration date of the
PTC, which currently expires on December 31, 2012, and other federal and
state governmental policies and standards that support renewable energy
development.
The Tax
Reform Act of 1986 established MACRS as the method to calculate depreciation for
federal income tax purposes. Under MACRS, wind power assets are
provided a depreciable life of five years, which is substantially shorter than
the 15- to 20-year depreciable lives associated with traditional power
generation facilities. Accelerated depreciation results in tax losses
in the early stages of a wind energy project’s life. Typically, 90%
of a wind energy project’s assets qualify for five-year accelerated depreciation
under MACRS.
74
The
amount of the capital investment made by our tax equity investors will be
determined by discounting the projected future value of the cash distributions
from electricity sales and related hedging agreements, PTCs and taxable income
or loss that the tax equity investors will be entitled to receive until such
investors reach an agreed investment return, which we typically expect to occur
in ten years. The after-tax discount rate used for this calculation
will be an agreed-upon targeted investment return for the tax
investor. As described in more detail in the table below, prior to
achieving the targeted investment return, our tax equity investors would receive
substantially all of the project’s cash distributions from electricity sales and
related hedging agreements, PTCs and taxable income or
loss. Following achievement of the targeted investment return, the
allocation of the project’s cash distributions from electricity sales and
related hedging agreements, PTCs and taxable income or loss would “flip” or
reverse from our tax equity investors to us so that we would receive
substantially all of the project’s cash distributions from electricity sales and
related hedging agreements, PTCs and taxable income or loss from that point
forward. If the project outperforms expectations, the flip will occur sooner,
and if a project underperforms, it will take longer for the flip to
occur.
To date,
the wind industry’s tax equity investors have been large financial institutions
with significant taxable income. However, the unprecedented upheaval
in the financial markets in the U.S. and around the world in recent months has
significantly lowered or eliminated profits achieved by many financial
institutions, making tax equity investing less available in
general. After giving effect to a tax equity financing, we will
retain day-to-day operational and management control of the applicable
project. However, our tax equity financing agreements are expected to
provide the tax equity investors with a number of approval rights, including
approvals of annual budgets, indebtedness, incurrence of liens, sales of assets
outside the ordinary course of business and litigation settlements. Tax equity
investors do not receive a lien on the project’s assets.
Although
the economic terms of each tax equity financing will vary substantially, the
following table provides an illustration of an allocation to tax equity
investors of cash distributions, PTCs and taxable income or loss that may
characterize a tax equity financing. The column titled “Cash
Distributions” reflects the apportionment of cash distributions from electricity
sales and related hedging agreements; the column titled “PTCs” reflects the
allocation of PTCs for U.S. federal income tax purposes; and the column titled
“Taxable Income or Loss” reflects the allocation of taxable income or loss for
U.S. federal income tax purposes.
|
Cash Distributions
|
PTCs
(1)
|
Taxable Income
or Loss
|
||||||||||||||||||||||
|
Project
Owner
|
Tax Equity
Investors
|
Project
Owner
|
Tax Equity
Investors
|
Project
Owner
|
Tax Equity
Investors
|
|||||||||||||||||||
|
Year
1 to Flip Date
(2)
|
30 | % | 70 | % | 1 | % | 99 | % | 1 | % | 99 | % | ||||||||||||
|
Thereafter
|
95 | % | 5 | % | 95 | % | 5 | % | 95 | % | 5 | % | ||||||||||||
|
(1)
|
PTCs lapse after ten years of
commercial operations, and the assets are generally fully depreciated five
years after commercial operations
commence.
|
|
(2)
|
Actual flip dates, as discussed
above, vary and depend on the date the tax equity investors earn the
agreed upon targeted investment
return.
|
75
Hedging
Our
ownership and operation of wind energy projects will expose us to volatility in
market prices of electricity and RECs. In an effort to stabilize our
returns from electricity sales, we intend to carefully review the electricity
sale options for each of our development projects. As part of this
review, we will assess the appropriateness of entering into a fixed price PPA
and/or a financial hedge. If we sell our electricity into a liquid
independent systems operator (“ISO”) market, we may enter into a financial hedge
with institutional investors in order to stabilize our projected revenue
stream.
Under the
terms of our anticipated financial hedges, we would not be obligated to
physically deliver or purchase electricity, but we would receive payments for
certain quantities of electricity based on a fixed price and would be obligated
to pay the market electricity price for the same quantities of
electricity. Thus, if market prices of electricity increase, we are
obligated to make payments under these financial hedges. Our
financial hedges will cover quantities of electricity that we estimate we can
produce with a high degree of certainty. As a result, gains or losses
under the financial hedges should be offset by decreases or increases in our
revenues from spot sales of electricity in liquid ISO
markets. However, the actual amount of electricity we generate from
operations may be materially different from our estimates for a variety of
reasons, including variable wind conditions, catastrophic events such as fires,
earthquakes, storms and changes in weather patterns due to climate
change. To the extent actual amounts produced fall short of the
quantities covered in our financial hedges, we will not be hedged and we will be
exposed to commodity price risk. In the event a project does not
generate the amount of electricity covered by the related hedge, we could incur
significant losses under the financial hedge if electricity prices rise
substantially above the fixed prices provided for in the hedge. If a
project generates more electricity than is covered by the relevant hedge, the
excess production will not be hedged and the revenues we derive will be subject
to market price fluctuations.
We may
seek to sell forward a portion of our RECs in an effort to hedge against future
declines in REC prices. If our projects are unable to generate the
amount of electricity required to earn the RECs sold forward or if we are unable
for any reason to qualify our electricity for RECs in relevant states, we may
incur significant losses.
We may be
required to post cash collateral and issue letters of credit for obligations
under hedging arrangements, which may not be available on acceptable terms and
if available would reduce our capacity to borrow for other purposes. Our
inability to effectively manage market risks and our hedging activities may have
a material adverse effect on our business, financial condition or results of
operations. In addition, our hedging activities may also limit our ability to
realize the full benefit of increases in electricity prices and
RECs.
Material
trends and uncertainties
Please
refer to the “Risk Factors” section for an in-depth discussion of the risks that
face the Company and its investors. We are pursuing our business plan
against the backdrop of a business, financial and competitive environment whose
characteristics represent material factors that affect the quality and amount of
our revenues, costs, financing prospects and liquidity. Among these
factors are:
76
|
●
|
Demand for and price of
electricity.
We seek to develop and eventually construct
wind parks that are aimed at generating and selling electricity on
established spot markets in the Midwest Independent Systems Operator
(MISO) footprint. The possibility that the price of electricity
will fall and stay low for a protracted period is a basic uncertainty
inherent in the merchant model, which seeks to sell electricity on a spot
market. Please refer to the more detailed discussion in the
“Description of Business—Demand for
Electricity.”
|
|
●
|
Costs of alternative methods
of generation.
Sustained declines in the prices of
fossil fuels, and drops in the costs of other alternative energy
technologies (such as solar), may also impair our income
prospects.
|
|
o
|
Price
of natural gas
.
The prices
for natural gas in 2009 were volatile and ended the year at, or below, the
prices during the beginning of the year. Natural gas is a major source of
fuel for electricity generation in the U.S., so any declines in the price
of natural gas will negatively impact electricity prices and therefore our
prospective income.
|
|
o
|
Price of
oil
. The price of oil in 2009 climbed steadily since the
beginning of the year. This may cause some increase in
electricity prices (increasing our prospective income), however this
effect is likely small since oil is not used as a major fuel for
electricity generation in the U.S., but does have some impact on the price
of natural gas, which is a source of fuel for electricity
generation.
|
|
●
|
Regulatory environment facing
independent generators of electricity
. We can offer no
assurances that the current regulatory environment will not become more
stringent in the future, and raise the cost of
compliance. Utilities are competing generators of electricity
who also own transmission infrastructure. Utilities may be able
to influence legislation in their favor at the expense of generators who
do not own transmission infrastructure. In such a case, the
construction costs for our wind parks would rise, and impair the
profitability of our prospective business
model.
|
These
uncertainties are inherent to the wind energy business and are difficult or
impossible to effectively mitigate, particularly for a company like us with
limited resources.
|
●
|
Tax incentives and government
subsidies
. The American Recovery and Reinvestment Act of
February 2009 includes provisions that extend the PTC/ITC tax benefits
available to the wind industry until December 31, 2012. Long
term success for Crownbutte will depend on the continuance of such
subsidies beyond 2012.
|
|
●
|
Condition of capital and
credit markets
.
|
|
o
|
Ability to raise
project finance for construction of wind projects
. Late
2008 and early 2009 has been a time of great difficulty for the financial
markets, and credit has become very difficult to obtain, especially for
developers such as Crownbutte, who have not raised construction financing
before. Inability to raise project finance will mean that we
must rely on sale of development rights for
income.
|
77
|
o
|
Ability to raise
private placement capital for general corporate
expenses
. Poor performance of the equity markets has
impaired our abilities to raise capital via a private placement of common
stock. We plan to raise approximately $1 million through
private placement of equity by the end of 2010, but there can be no
assurance that we will be
successful.
|
|
●
|
Ability to sell the
development rights for individual green-field development
projects
. Our near term income will depend on the sale
of development rights for one or two wind parks per
year. Because such a sale can take weeks or months to
negotiate, we cannot well control the timing of such income. If
such a sale does not occur before funds are depleted by ordinary
expenditures, then we will face significantly adverse liquidity
problems.
|
These
uncertainties are inherent in the wind energy business and are difficult or
impossible to effectively mitigate, particularly for a company like us with
limited resources. Any or all of the above factors may be such that
successful pursuit of our strategy may be seriously impaired and may represent a
potentially significant adverse impact on earnings and
liquidity. The Company will closely monitor changes in any of
these areas to determine if they are material and will seek to adjust its
business operations to adapt to these changes as they are identified, although
there can be no assurance we will be successful in doing so.
Results
of Operations
We are an
exploration stage company and have generated minimal revenues from operations to
date.
Fiscal
Years 2009 and 2008 Compared
|
For years ended December 31,
|
||||||||||||||||
|
2009
|
2008
|
$ Change
|
% Change
|
|||||||||||||
|
Sale
of project development rights
|
$
|
-
|
$
|
200,000
|
$
|
(200,000
|
)
|
-100
|
%
|
|||||||
|
Consulting
revenues
|
-
|
73,020
|
(73,020
|
)
|
-100
|
%
|
||||||||||
|
Total
revenues
|
-
|
273,020
|
(273,020
|
)
|
-100
|
%
|
||||||||||
|
Cost
of revenues
|
||||||||||||||||
|
Project
development rights
|
-
|
34,593
|
(34,593
|
)
|
-100
|
%
|
||||||||||
|
Consulting
|
-
|
3,482
|
(3,482
|
)
|
-100
|
%
|
||||||||||
|
Total
cost of revenues
|
-
|
38,075
|
(38,075
|
)
|
-100
|
%
|
||||||||||
|
Gross
profit
|
-
|
234,945
|
(234,945
|
)
|
-100
|
%
|
||||||||||
|
Operating
expenses:
|
||||||||||||||||
|
General
and administrative (includes stock based compensation of $702,702 and
$2,739,974 for stock and warrants issued for services in
2008)
|
1,828,235
|
4,169,687
|
(2,341,452
|
)
|
-56
|
%
|
||||||||||
|
Depreciation
expense
|
32,459
|
21,039
|
11,420
|
54
|
%
|
|||||||||||
|
Total
operating expenses
|
1,860,694
|
4,190,726
|
(2,330,032
|
)
|
-56
|
%
|
||||||||||
|
Net
operating loss
|
(1,860,694
|
)
|
(3,955,781)
|
2,095,087
|
-53
|
%
|
||||||||||
|
Other
income (expenses):
|
||||||||||||||||
|
Interest
income
|
935
|
11,282
|
(10,347
|
)
|
-92
|
%
|
||||||||||
|
Other
income
|
60,772
|
-
|
60,772
|
100
|
%
|
|||||||||||
|
Interest
expense
|
(4,094
|
)
|
-
|
4,094
|
100
|
%
|
||||||||||
|
Loss
on sale of fixed assets
|
(18,369
|
)
|
-
|
18,369
|
100
|
%
|
||||||||||
|
Bad
debt expense
|
(1,722
|
)
|
-
|
1,722
|
100
|
%
|
||||||||||
|
Total
other income (expenses)
|
37,522
|
11,282
|
26,240
|
233
|
%
|
|||||||||||
|
Net
loss
|
$
|
(1,823,172
|
)
|
$
|
(3,944,499
|
)
|
$
|
2,121,372
|
54
|
%
|
||||||
78
For the
year ended December 31, 2009, revenues declined to $0 from $273,020 in
2008. This reflects the timing and lumpiness of income from sale of
brown-field sites as well as from consulting. No new sales of
development rights or new consulting projects were secured during
2009. As described in the “Risk Factors” section and in the
discussion on Material Trends and Uncertainties, we cannot be assured of success
in our endeavors to sell development rights, to secure consulting contracts, or
to raise the necessary project finance required to construct and operate wind
parks for the sale of electricity.
We
believe that 2009 was a difficult year for the wind industry as a whole due to
the uncertainties surrounding the global economic environment (which made
financing of all types more difficult). In this environment of
uncertainty, there was a decline in the number of potential purchasers of
development rights to new wind parks. We are encouraged by the
passage of the American Recovery and Reinvestment Act of 2009, which extends the
PTC for three years to 2012, offers an alternative ITC option to the PTC,
and, for projects beginning construction before the end of 2010, offers a
one-time grant equal to 30% of the authorized capital costs of the project in
lieu of investment tax credits or production tax credits. These new
incentives have mitigated the adverse effects of continued tightening in the
credit markets and have contributed to an improvement in the overall economic
climate for the wind industry. However, to date, we have been
unsuccessful in securing any additional sales of development rights, and there
can be no assurance we will be able to sell development rights in the
future. We have entered into a non-binding agreement to obtain $37.5
million debt financing for our Gascoyne I project, as discussed elsewhere within
this report. The consummation of this financing is subject to, among
other things, satisfactory completion by the lender of all necessary technical
and legal due diligence and satisfactory negotiation of all required definitive
agreements necessary or desirable to effect the transaction. We
anticipate a construction completion and operational date by the end of 2010 or
early 2011. There can be no assurance, however, that this project
financing effort will be successful.
Cost
of Revenues
During
2009, we had no cost of revenues due to no revenue earned for the
year. This is a decrease of $38,075 compared to
2008.
79
Operating
Expenses
A large
portion of the total 2009 operating expenses is share-based compensation
relating to key employees and awards made in 2008. The Company
recognized $702,702 in share-based compensation in 2009 compared to $2,739,974
in 2008. The decrease in compensation expense of $2,037,272 accounted
for most of the Company’s $2,121,372 improvement in earnings for 2009 versus
2008.
Research
and development expenses related to the Company’s projects, decreased in 2009 to
$147,151 compared to $638,443 for 2008. The significant decrease is
mainly due to the increased activity and investments made in 2008 to purchase
development rights and to bring projects closer to the shovel-ready phase for
2009. Most of 2009’s focus for the Company shifted from development
to seeking financing for late development stage projects. No new
significant investments were made in 2009.
Legal,
accounting, and other professional fees (which includes costs related to finance
costs of raising private placement investment and ongoing filing requirements)
were higher in 2009 versus 2008. Professional fees expenses for 2009
totaled $417,294 compared to $273,865 recorded in 2008. A significant
portion of the additional $143,429 recorded in 2009 includes legal defense fees
related to the Centre Square Capital litigation from 2008.
Other
Non-Operating Income and Expenses
The
Company incurred interest expense totaling $4,094 in 2009 compared to $0 in
2008. The increase in interest expense is due to finance charges on
credit cards payable and late fees incurred in 2009 caused by the Company’s
increased accounts payable and accrued liabilities.
The
Company incurred a loss of $18,369 on sale of fixed assets in 2009 compared to
$0 for 2008. Three vehicles and one trailer were sold during the year
to generate cash for operating expenses.
Other
income of $60,772 was recorded in 2009, most of it ($53,214) due to the write
off of a legal bill owed by the Company. There was no other
income for 2008.
The
Company received $935 interest income for 2009 compared to $11,282 for
2008. The decrease of $10,347 was due to the depletion of cash and
redemption of interest-bearing certificates of deposit early in
2009.
Liquidity
and Capital Resources
The
Company experienced significant liquidity issues in 2009 compared to
2008. Expenses related to the reverse merger, private placements, and
increased investment in project development activities late 2008 continued into
2009, depleting the Company’s cash reserves. Further compounding the
issue, the credit market turmoil of late 2008 continued well into 2009 and to
the present, making the task of obtaining financing even more
difficult. The Company also incurred significant legal and other
expenses due to litigation and the ongoing accounting and public reporting
expenses.
80
In an
effort to cut costs, staff were reduced in 2009 from eight to four, retaining
only key employees until the Company can successfully procure financing for one
or more projects, generate revenue from the sale of project development rights
or consulting, or raise sufficient funds through private
placements.
The
Company has accrued significant liabilities and has a working capital deficit of
$652,292 as of December 31, 2009 compared to positive working capital of
$300,200 on December 31, 2008. In 2009, we used $560,875 cash in
operations compared to $1,158,901 used in operations for 2008. The
decrease in cash used for 2009 is mainly due to large increases in accounts
payable and accrued liabilities for 2009 and no additional investment in
interconnect application deposits compared to 2008.
Future
efforts to generate positive cash flow depend on Crownbutte’s success in selling
development rights to parks in the short term, and constructing wind parks to
generate electricity sales in the long term. If we are successful at
closing the pending Gascoyne I financing, we anticipate receipt of approximately
$1,000,000 developer fee to be paid out of the financing. Receipt of
these funds will allow the Company to eliminate most of our liabilities and
obligations through the date of financing, however, we will still be dependent
upon sales of project development rights, consulting revenues, or other sources
of cash flow until such time our parks are operational and generating sufficient
revenues to meet corporate overhead.
Cash
flows from investing activities for 2009 totaled $169,471 compared to cash used
in investing activities in 2008 of $181,640. The increase in cash
from investing for 2009 related to redemption of certificates of deposit
totaling $152,030 and sales of fixed assets compared to $170,499 fixed assets
purchased in 2008.
Cash
flows from financing activities for 2009 totaled $104,023 compared to $1,519,500
in 2008. Sources of cash for 2009 included officer loan proceeds of
$44,380, stockholder loans of $20,000 and proceeds from exercise of warrants
totaling approximately $40,000. In 2008 the Company received most of
its financing funds from private placement activities. A dividend of
$153,333 was paid to the original stockholders in 2008.
Off-Balance
Sheet Arrangements
We do not
have any off-balance sheet arrangements that have or are reasonably likely to
have a current or future effect on our financial condition, changes in financial
condition, revenues or expenses, results of operations, liquidity, capital
expenditures or capital resources that is material to investors.
Critical
Accounting Policies
Revenue
Recognition
The
Company recognizes revenue in accordance with guidance issued by the Financial
Accounting Standards Board (“FASB”) on revenue recognition, which requires 1)
evidence of an agreement, 2) delivery of the product or services has occurred 3)
at a fixed or determinable price, and 4) assurance of collection within a
reasonable period of time.
81
Further,
some revenues are recognized using the percentage of completion method of
accounting. The Company believes that the use of the percentage of completion
method is appropriate as the Company has the ability to make reasonably
dependable estimates of the extent of progress towards completion, contract
revenues and contract costs. The percentage to completion is measured by
monitoring progress using records of actual time, materials and other costs
incurred to date on specific projects compared to the total estimated project
requirements, which corresponds to the costs related to earned revenues.
Estimates of total project requirements are based on prior experience of
customization, delivery and acceptance of the same or similar technology and are
reviewed and updated regularly by management. Provisions for estimated losses on
uncompleted contracts are made in the period in which such losses are first
determined, in the amount of the estimated loss on the entire
contract.
The
Company currently functions in two business areas: as a wind park developer and
as a consulting and advisory service to power utilities. During 2008 the Company
recognized revenues from consulting and advising services to power utilities
(Consulting revenues). The Company made no sales and had no
consulting revenues for the year ended December 31, 2009.
Consulting
services revenue is recognized under guidance that differs from contract
services revenue. Consulting services revenue is recognized when delivery of the
service has occurred; the customer has already received the service, and
along with other revenue recognition criteria, qualifies the transaction as
a sale. Whereas, contract services revenue is recognized when delivery of the
product or service has yet to be completed yet the transaction still qualifies
as a sale. When recognizing contract services revenue, prior to the project’s
start, the Company estimates the cost at each stage of the project. As time
passes and the stages are completed, the contractor recognizes an estimate of
the revenue that has been earned based on the percentage of the estimated costs
that have already been incurred. Using the percentage of completion method
allows revenues and their associated expenses to be recognized in the same
accounting period according to the matching principle, even if the customer has
yet to receive delivery of the goods and services, or if the goods and services
have not been completed by the Company.
Cost
of Revenues
The
Company includes all direct costs related to its contract and sale of
development rights revenues in cost of revenues. The types of costs
include materials and supplies and subcontractor fees and expenses specific to
the project or contract. Additionally, allocations of payroll, taxes,
and benefits are added to cost of revenues based on time worked on each
project. Any project expenses not directly related to
revenue-generating contracts or sales are expensed to research and development
within general and administrative expenses.
Research
and Development
The
Company expenses research and development as incurred.
Stock-Based
Compensation
The
Company accounts for the grant of stock and warrants awards in accordance with
ASC Topic 718, Compensation – Stock Compensation (ASC 718). ASC 718
requires companies to recognize in the statement of operations the grant-date
fair value of warrants and stock options and other equity based
compensation.
82
The
Company uses the Black-Scholes option valuation model for estimating the fair
value of traded options. This option valuation model requires the
input of highly subjective assumptions including the expected stock price
volatility.
See the
accompanying notes to consolidated audited financial statements for additional
discussion of critical accounting policies (Note 3 – Summary of Significant
Accounting Policies).
New
Accounting Pronouncements
In June
2009, the FASB issued authoritative guidance which eliminates the exemption for
qualifying special-purpose entities from consolidation requirements, contains
new criteria for determining the primary beneficiary of a variable interest
entity, and increases the frequency of required reassessments to determine
whether a company is the primary beneficiary of a variable interest entity. The
guidance is applicable for annual periods beginning after November 15, 2009 and
interim periods therein and thereafter. The Company does not expect the adoption
of this standard to have a material effect on its financial position or results
of operations.
EITF
Issue No. 07-5 (ASC 815), “Determining Whether an Instrument (or embedded
Feature) is Indexed to an Entity’s Own Stock” (EITF 07-5) was issued in June
2008 to clarify how to determine whether certain instruments or features were
indexed to an entity’s own stock under EITF Issue No. 01-6 (ASC 815), “The
Meaning of “Indexed to a Company’s Own Stock” (EITF 01-6) (ASC 815),. EITF
07-5(ASC 815), applies to any freestanding financial instrument (or embedded
feature) that has all of the characteristics of a derivative as defined in FAS
133, for purposes of determining whether that instrument (or embedded feature)
qualifies for the first part of the paragraph 11(a) scope exception. It is also
applicable to any freestanding financial instrument (e.g., gross physically
settled warrants) that is potentially settled in an entity’s own stock,
regardless of whether it has all of the characteristics of a derivative as
defined in FAS 133 (ASC 815), for purposes of determining whether to apply EITF
00-19 (ASC 815). EITF 07-5(ASC 815) does not apply to share-based payment awards
within the scope of FAS 123(R), Share-Based Payment (FAS 123(R) (ASC 718)).
However, an equity-linked financial instrument issued to investors to establish
a market-based measure of the fair value of employee stock options is not within
the scope of FAS 123(R) and therefore is subject to EITF 07-5(ASC
815).
In
January 2009, the FASB issued FSP EITF 99-20-1 (ASC 325), to amend the
impairment guidance in EITF Issue No. 99-20 (ASC 325) in order to achieve
more consistent determination of whether an other-than-temporary impairment
(“OTTI”) has occurred. This FSP amended EITF 99-20 (ASC 325) to more
closely align the OTTI guidance therein to the guidance in Statement
No. 115 (ASC 320, 10-35-31). Retrospective application to a prior interim
or annual period is prohibited. The guidance in this FSP was considered in the
assessment of OTTI for various securities at December 31,
2008.
83
On June
5, 2003, the United States Securities and Exchange Commission (“SEC”) adopted
final rules under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”),
as amended by SEC Release No. 33-9072 on October 13, 2009. Commencing with its
annual report for the year ending December 31, 2010, the Company will be
required to include a report of management on its internal control over
financial reporting. The internal control report must include a statement
of:
|
|
·
|
Management’s
responsibility for establishing and maintaining adequate internal control
over its financial reporting;
|
|
|
·
|
Management’s
assessment of the effectiveness of its internal control over financial
reporting as of year- end; and
|
|
|
·
|
The
framework used by management to evaluate the effectiveness of the
Company’s internal control over financial
reporting.
|
Furthermore,
it is required to file the auditor’s attestation report separately on the
Company’s internal control over financial reporting on whether it believes that
the Company has maintained, in all material respects, effective internal control
over financial reporting.
In August
2009, the FASB issued the FASB Accounting Standards Update No. 2009-04
“Accounting for Redeemable Equity Instruments - Amendment to Section 480-10-S99”
which represents an update to section 480-10-S99, distinguishing liabilities
from equity, per EITF Topic D-98, Classification and Measurement of Redeemable
Securities. The Company does not expect the adoption of this update to have a
material impact on its consolidated financial position, results of operations or
cash flows. In August 2009, the FASB issued the FASB Accounting Standards Update
No. 2009-05 “Fair Value Measurement and Disclosures Topic 820 – Measuring
Liabilities at Fair Value”, which provides amendments to subtopic 820-10, Fair
Value Measurements and Disclosures – Overall, for the fair value measurement of
liabilities. This update provides clarification that in circumstances in which a
quoted price in an active market for the identical liability is not available, a
reporting entity is required to measure fair value using one or more of the
following techniques: 1. A valuation technique that uses: a. The quoted price of
the identical liability when traded as an asset b. Quoted prices for similar
liabilities or similar liabilities when traded as assets. 2. Another valuation
technique that is consistent with the principles of topic 820; two examples
would be an income approach, such as a present value technique, or a market
approach, such as a technique that is based on the amount at the measurement
date that the reporting entity would pay to transfer the identical liability or
would receive to enter into the identical liability. The amendments in this
update also clarify that when estimating the fair value of a liability, a
reporting entity is not required to include a separate input or adjustment to
other inputs relating to the existence of a restriction that prevents the
transfer of the liability. The amendments in this update also clarify that both
a quoted price in an active market for the identical liability when traded as an
asset in an active market when no adjustments to the quoted price of the asset
are required are Level 1 fair value measurements. The Company does not expect
the adoption of this update to have a material impact on its consolidated
financial position, results of operations or cash flows.
In
September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-08
“Earnings Per Share – Amendments to Section 260-10-S99”,which represents
technical corrections to topic 260-10-S99, Earnings per share, based on EITF
Topic D-53, Computation of Earnings Per Share for a Period that includes a
Redemption or an Induced Conversion of a Portion of a Class of Preferred Stock
and EITF Topic D-42, The Effect of the Calculation of Earnings per Share for the
Redemption or Induced Conversion of Preferred Stock. The Company does not expect
the adoption of this update to have a material impact on its consolidated
financial position, results of operations or cash flows.
84
In
September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-09
“Accounting for Investments-Equity Method and Joint Ventures and Accounting for
Equity-Based Payments to Non-Employees”. This update represents a correction to
Section 323-10-S99-4, Accounting by an Investor for Stock-Based Compensation
Granted to Employees of an Equity Method Investee. Additionally, it adds
observer comment Accounting Recognition for Certain Transactions Involving
Equity Instruments Granted to Other Than Employees to the Codification. The
Company does not expect the adoption to have a material impact on its
consolidated financial position, results of operations or cash
flows.
In
September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-12
“Fair Value Measurements and Disclosures Topic 820 – Investment in Certain
Entities That Calculate Net Assets Value Per Share (or Its Equivalent)”, which
provides amendments to Subtopic 820-10, Fair Value Measurements and
Disclosures-Overall, for the fair value measurement of investments in certain
entities that calculate net asset value per share (or its equivalent). The
amendments in this update permit, as a practical expedient, a reporting entity
to measure the fair value of an investment that is within the scope of the
amendments in this update on the basis of the net asset value per share of the
investment (or its equivalent) if the net asset value of the investment (or its
equivalent) is calculated in a manner consistent with the measurement principles
of Topic 946 as of the reporting entity’s measurement date, including
measurement of all or substantially all of the underlying investments of the
investee in accordance with Topic 820. The amendments in this update also
require disclosures by major category of investment about the attributes of
investments within the scope of the amendments in this update, such as the
nature of any restrictions on the investor’s ability to redeem its investments
at the measurement date, any unfunded commitments (for example, a contractual
commitment by the investor to invest a specified amount of additional capital at
a future date to fund investments that will be made by the investee), and the
investment strategies of the investees. The major category of investment is
required to be determined on the basis of the nature and risks of the investment
in a manner consistent with the guidance for major security types in U.S. GAAP
on investments in debt and equity securities in paragraph 320-10-50-1B. The
disclosures are required for all investments within the scope of the amendments
in this update regardless of whether the fair value of the investment is
measured using the practical expedient. The Company does not expect the adoption
to have a material impact on its consolidated financial position, results of
operations or cash flows.
In
October 2009, the FASB issued guidance for amendments to FASB Emerging Issues
Task Force on EITF Issue No. 09-1 “Accounting for Own-Share Lending Arrangements
in Contemplation of a Convertible Debt Issuance or Other Financing” (Subtopic
470-20) “Subtopic”. This accounting standards update establishes the accounting
and reporting guidance for arrangements under which own-share lending
arrangements issued in contemplation of convertible debt issuance. This
Statement is effective for fiscal years, and interim periods within those fiscal
years, beginning on or after December 15, 2009. Earlier adoption is not
permitted. The Company does not expect the adoption to have a material impact on
its consolidated financial position, results of operations or cash
flows.
85
A variety
of proposed or otherwise potential accounting standards are currently under
study by standard setting organizations and various regulatory agencies. Due to
the tentative and preliminary nature of those proposed standards, management has
not determined whether implementation of such proposed standards would be
material to our consolidated financial statements.
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTAL DATA
|
Our
audited consolidated financial statements as of, and for the years ended,
December 31, 2009 and 2008 are included beginning on Page F-1 immediately
following the signature page to this report. See Item 15 for a list
of the financial statements included herein.
|
ITEM
9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
None.
|
|
CONTROLS
AND PROCEDURES
|
Our Chief
Executive Officer and Chief Financial Officer evaluated the effectiveness of our
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) as of December 31, 2009, the end of the period covered by this
report. Based on that evaluation, our Chief Executive Officer and
Chief Financial Officer concluded that our disclosure controls and procedures as
of December 31, 2009 were not effective to ensure that the information required
to be disclosed by us in reports filed under the Securities Exchange Act of 1934
is (i) recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms and (ii) accumulated and communicated to
the Chief Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding disclosure. A controls system cannot
provide absolute assurance that the objectives of the controls system are met,
and no evaluation of controls can provide absolute assurance that all control
issues and instances of fraud, if any, within a company have been
detected.
Our Chief
Executive Officer and Chief Financial Officer are responsible for establishing
and maintaining adequate internal control over financial reporting (as defined
in Rule 13a-15(f) under the Exchange Act). Our internal control over
financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with accounting
principles generally accepted in the United States.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance of achieving
their control objectives. Furthermore, smaller reporting companies
face additional limitations. Smaller reporting companies employ fewer
individuals and find it difficult to properly segregate
duties. Often, one or two individuals control every aspect of the
Company’s operation and are in a position to override any system of internal
control. Additionally, smaller reporting companies tend to utilize
general accounting software packages that lack a rigorous set of software
controls.
86
We have
identified the following material weaknesses in our internal control over
financial reporting:
Lack
of Independent Board of Directors and Audit Committee
Management
is aware that an audit committee composed of the requisite number of independent
members along with a qualified financial expert has not yet been
established. Considering the costs associated with procuring and
providing the infrastructure to support an independent audit committee and the
limited number of transactions, management has concluded that the risks
associated with the lack of an independent audit committee are not sufficient to
justify the creation of such a committee at this time. Management
will periodically reevaluate this situation.
Lack
of Segregation of Duties
Management
is aware that there is a lack of segregation of duties at the Company due to the
small number of employees dealing with general administrative and financial
matters. However, at this time management has decided that
considering the abilities of the employees now involved and the control
procedures in place, the risks associated with such lack of segregation are low
and the potential benefits of adding employees to clearly segregate duties do
not justify the substantial expenses associated with such
increases. Management will periodically reevaluate this
situation.
Officers’
Certifications
Appearing
as Exhibits 31.1 and 31.2 to this Annual Report are “Certifications” of our
Chief Executive Officer and Chief Financial Officer which are required pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002 (the “Section 302
Certifications”). This section of the Annual Report contains
information concerning the evaluation of disclosure controls and procedures
referred to in the Section 302 Certifications. This information
should be read in conjunction with the Section 302 Certifications for a more
complete understanding of the topics presented.
Changes
in Internal Control Over Financial Reporting
There
have been no changes in our internal control over financial reporting that
occurred during the quarter ended December 31, 2009 that have materially
affected or are reasonably likely to materially affect our internal control over
financial reporting.
None.
87
Executive
Officers and Directors
Our
executive officers and directors are as follows:
|
Name
|
Age
|
Position
|
||
|
Timothy
H. Simons
|
63
|
Chief
Executive Officer, President and Director
|
||
|
Manu
Kalia
|
39
|
Chief
Financial Officer
|
||
|
Ross
D. Mushik
|
51
|
Director
|
||
|
Terry
Pilling
|
39
|
Director
and Executive Vice
President
|
Background
of Executive Officers and Directors
Timothy H.
Simons,
Chief Executive
Officer, President and Director
, founded Crownbutte ND in 1999 and has
been involved in the wind power industry since 1996. Following the
merger in July 2008, Mr. Simons became our Chief Executive Officer and President
and a member of the Board of Directors. From 1991 through 2002, he
was a teacher in the public school systems of Bismarck and Mandan, North
Dakota. After founding Crownbutte ND in 1999, he taught part time,
devoting over 40 hours per week to the Company.
In 2002
Mr. Simons was asked to join the newly established Upper Great Plains
Transmission Coalition (the “UGPTC”). The UGPTC was formed by the
Governor of North Dakota in cooperation with Minnesota and South Dakota in order
to address electrical transmission problems, so that the coal, hydro and wind
resources in the area could be better utilized. In addition to
membership in the UGPTC, Mr. Simons is on the Steering Committee and is
co-chairman of the Transmission Bottleneck Committee of the UGPTC.
Manu
Kalia,
Chief
Financial Officer,
has been our Chief Financial Officer since September
15, 2008. Mr. Kalia has 13 years of high tech and financial
management experience. He served as CEO of ProMana Solutions, Inc.
(web-based payroll services) from July 2006 to July 2008, CFO of ARC
International, PLC (semiconductors IP and embedded software) from October 2002
to June 2006, CFO of Tradeworx Inc. (statistical-arbitrage financial analytics/
hedge fund) from March 2001 to September 2002, and CEO of Open Source Creations
Inc. (online collaboration) from August 2000 to February 2001. Prior
to that, Mr. Kalia spent time as an investment banker for Commonwealth
Associates from July 1999 to July 2000, as an analyst for Sanford Bernstein from
April 1998 through June 1999, and as a manager at Lucent Technologies Bell
Laboratories from September 1995 through March 1998. Mr. Kalia holds
a Bachelor in Engineering Sciences (cum laude) from Dartmouth College, and an
MBA from the Amos Tuck School of Business Administration at
Dartmouth.
88
Ross D. Mushik,
Director
, was
appointed to the Board of Directors on June 4, 2009. Mr. Mushik is
the principal owner and operator of Ross Lawn and Snow Services, LLC, a small
business located in Mandan, ND, which has been in operation since August
2007. Prior to being a full-time entrepreneur, Mr. Mushik was
employed with state government in various positions within the fields of
accounting and finance for approximately 22 years. He served as
Administrative Services Manager for the ND Department of Emergency Services, a
position he held from October 2001 to August 2007 and as Account/Budget
Specialist December 1997 to October 2001. From January 1991 to
December 1997, Mr. Mushik was an Account Budget Specialist at the ND Office of
Intergovernmental Assistance. From August 1988 to December 1990, he
worked for American Express Financial Services as a Financial Planner, and in
state government from July 1983 to August 1988 as a Field Tax Inspector and
Legal Auditor for the ND State Tax Department. Mr. Mushik has a
Masters of Business Administration from the American Graduate School of
International Management in Glendale, Arizona and a Bachelor of Arts Degree from
Jamestown College in Jamestown, ND. Mr. Mushik serves as Secretary
and Treasurer for two fraternal organizations, the Masons and the
Shriners.
Terry Pilling,
Director and Executive
Vice President,
has been a member of the Board of Directors since
September 2008 and our Executive Vice President since February
2010. From September 2008 to February 2010, Mr. Pilling served as our
Vice President of Operations and Technology. Mr. Pilling was an
assistant professor of the Physics Department at the North Dakota State
University from August 2004 to August 2008. His professional
experience includes Visiting Researcher, Joint Astronomy Centre and the James
Clerk Maxwell radio telescope on Mauna Kea, Hilo, Hawaii from May 2006 to August
2006; Postdoctoral Research Associate, Institute of Theoretical and Experimental
Physics, Moscow from September 2003 to June 2004 and Postdoctoral Research
Associate, Joint Institute for Nuclear Research, Dubna from September 2003 to
June 2004. Prior to that, Mr. Pilling worked as Science Editor for
the House of Knowledge Publishing Company in London, England from September 2002
to August 2003, as a teaching assistant for the North Dakota State University
from September 1998 to August 2002 and as its physics department Network Systems
Administrator and Webmaster September 1999 to August 2002. Mr.
Pilling obtained his Ph.D. in High Energy Particle Physics and Gravitation from
North Dakota State University in 2002. He achieved an M.Sc. in
Theoretical and Experimental Nuclear Physics from Saskatchewan Accelerator
Laboratory in 1998 and a B.Sc. in Physics and Engineering Physics from the
University of Saskatchewan in 1996. Mr. Pilling has received
professional recognition from the North Dakota State University as an Odney
Award nominee in 2008 and a Gunkelman Award nominee in 2006. He was a
National Science Foundation EPSCoR Research Fellow in 2001 and received the
Physics and Engineering Physics Convocation Award in 1996 from the University of
Saskatchewan.
Code
of Ethics
We have
not formally adopted a code of ethics that governs all of our employees,
including our CEO, CFO, principal accounting officer or persons performing
similar functions.
Board
of Directors; Committees; Audit Committee Financial Expert
The Board
of Directors currently consists of three members. Directors serve
until their successors are duly elected or appointed. Messrs. Simon
and Pilling are not “independent” as defined in the Nasdaq Stock Market Listing
Rules. Mr. Mushik may be considered to be “independent,” but the
Board has made no determination as yet. None of our directors is an
“audit committee financial expert” as defined Item 407 of Regulation
S-K. With a Board of only three directors, we do not have a separate
audit committee or any other committee.
89
Shareholder
Communications
Currently,
we do not have a policy with regard to the consideration of any director
candidates recommended by security holders. To date, no security
holders have made any such recommendations.
Summary
Compensation Table
The
following table sets forth information concerning the total compensation paid or
accrued by us during the last two fiscal years ended December 31, 2009 to (i)
all individuals that served as our principal executive officer or acted in a
similar capacity for us at any time during the fiscal year ended December 31,
2009; (ii) all individuals that served as our principal financial officer or
acted in a similar capacity for us at any time during the fiscal year ended
December 31, 2009; and (iii) all individuals that served as executive officers
of ours at any time during the fiscal year ended December 31, 2009 that received
annual compensation during the fiscal year ended December 31, 2009 in excess of
$100,000.
|
Name and
Principal
Position(s)
(a)
|
Year
(b)
|
|
Salary
($)
(c)
|
|
Bonus
($)
(d)
|
Stock
Awards
($)
(e)
|
|
Option
Awards
($)
(f)
|
|
Non-Equity
Incentive
Plan
Compensation
($)
(g)
|
Change in
Pension Value
and Nonqualified
Deferred
Compensation
Earnings
($)
(h)
|
All Other
Annual
Compensation
($)
(i)
|
Total
($)
(j)
|
||||||||||
|
Timothy
H. Simons
|
2009
|
$
|
105,600
|
-
|
-
|
-
|
-
|
$
|
1,080
|
$
|
106,680
|
||||||||||||
|
President
& CEO
|
2008
|
$
|
105,600
|
-
|
-
|
-
|
-
|
-
|
$
|
3,168
|
$
|
108,768
|
|||||||||||
|
Manu
Kalia
|
2009
|
$
|
100,000
|
-
|
-
|
$
|
702,702
|
-
|
-
|
$
|
-
|
$
|
802,702
|
||||||||||
|
CFO
|
2008
|
$
|
20,833
|
-
|
-
|
$
|
251,000
|
-
|
-
|
$
|
-
|
$
|
271,833
|
||||||||||
|
Terry
Pilling
|
2009
|
$
|
100,000
|
-
|
-
|
$
|
-
|
-
|
-
|
$
|
2,250
|
$
|
102,250
|
||||||||||
|
Executive Vice
President
(1)
|
2008
|
$
|
16,666
|
-
|
-
|
$
|
-
|
-
|
-
|
$
|
-
|
16,666
|
|||||||||||
|
Ryan
Fegley,
|
2009
|
$
|
30,513
|
-
|
-
|
$
|
-
|
-
|
-
|
$
|
915
|
$
|
31,428
|
||||||||||
|
VP of Project
Development
(2)
|
2008
|
$
|
46,167
|
-
|
-
|
$
|
2,488,000
|
-
|
-
|
$
|
1,385
|
$
|
2,535,552
|
||||||||||
(1) From September 17, 2008 to February 15, 2010, Mr. Pilling was Vice President of Operations and Technology.
(2) Mr.
Fegley resigned as a director and Vice President of Project Development as of
May 15, 2009.
Each of
Messrs. Kalia and Pilling is, and prior to his resignation Mr. Fegley was, party
to an employment agreement with the Company governing his
compensation. See “Employment Agreements with Executive Officers”
below. There are no other written or unwritten agreements with other
executive officers, other than Messrs. Kalia and Pilling. Mr. Simons’
compensation is determined annually by the Board of Directors.
90
Chronology
of Stock and Option Awards
In June
2008, Timothy Simons was granted warrants to purchase 1,000,000 shares of
restricted common stock at an exercise price of $0.10 per share, vesting
immediately and with a term of five years. These warrants were
granted to Mr. Simons as part of a negotiated transaction and were not issued as
compensation.
In June
2008, Ryan Fegley was granted warrants to purchase 5,000,000 shares of
restricted common stock at an exercise price of $0.01 per share, vesting
immediately and with a term of three years.
In
September 2008, Manu Kalia entered into an employment agreement with Crownbutte
wherein he was to be granted 1,000,000 shares of restricted common stock,
vesting quarterly in four equal portions beginning January 1,
2009. The employment agreement has since been amended (on January 1,
2009) to change the grant of shares into a grant of warrants to purchase the
same number of shares (1,000,000) at an exercise price of $0.001 per share,
vesting on the same four-quarter schedule. Manu Kalia was also
granted warrants to purchase 1,000,000 shares at an exercise price of $0.001 per
share, vesting 100% on September 15, 2009.
In each
accounting period, the value of each stock or option award that vests shall be
expensed according to the principles of FAS123(R).
In August
2007, the Company established a SIMPLE retirement plan. The Company
matches employee contributions up to 3% of gross wages. The Company’s
contributions to the plan were $6,776 for the year ended December 31, 2008 and
$6,378 for the year ended December 31, 2009.
OUTSTANDING
EQUITY AWARDS AT FISCAL YEAR-END
|
OPTION AWARDS
|
STOCK AWARDS
|
||||||||||||||||||||||||||||||||
|
Name
(a)
|
Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
(b)
|
Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable
(c)
|
Equity
Incentive
Plan Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options (#)
(d)
|
Option
Exercise
Price ($)
(e)
|
Option
Expiration
Date
(f)
|
Number of
Shares or Units
of Stock That
Have Not
Vested (#)
(g)
|
Market Value
of Shares or
Units of Stock
That Have Not
Vested ($)
(h)
|
Equity Incentive
Plan Awards:
Number of
Unearned
Shares, Units or
Other Rights
That Have
Not Vested (#)
(i)
|
Equity Incentive
Plan Awards:
Market or
Payout Value of
Unearned Shares,
Units or Other
Rights That Have
Not Vested (#)
(j)
|
||||||||||||||||||||||||
|
Timothy
H.
Simons
|
1,000,000
|
(1)
|
-
|
-
|
$
|
0.10
|
July
2, 2013
|
-
|
-
|
-
|
-
|
||||||||||||||||||||||
|
Manu
Kalia
|
-
|
1,000,000
|
-
|
$
|
0.001
|
Sept.
15, 2013
|
1,000,000
|
$
|
500,000
|
-
|
-
|
||||||||||||||||||||||
|
(1)
|
Mr.
Simons received these warrants as part of a negotiated transaction and not
as compensation.
|
91
Employment
Agreements with Executive Officers
On
September 15, 2008, the Company entered into an employment agreement with Manu
Kalia to serve as its Chief Financial Officer. Pursuant to the
agreement, Mr. Kalia will receive annual compensation of $100,000, until the
Company raises an additional $3,000,000 in private placement of its stock, at
which time Mr. Kalia will receive annual compensation of
$150,000. The Company granted to Mr. Kalia warrants to purchase
1,000,000 shares of its restricted common stock at, which shares vest quarterly
in four equal installments beginning on January 1, 2009. Mr. Kalia
also received warrants to purchase 1,000,000 shares of the Company’s common
stock at an exercise price of $0.001 per share, which warrants become
exercisable after Mr. Kalia’s has been continuously employed by the Company for
a period of 12 months. In addition, Mr. Kalia is entitled to
participate in the benefits from time to time in effect for the Company’s
employees holding similar positions, along with vacation, sick and holiday pay
in accordance with policies established and in effect from time to
time. The Company may terminate the employment agreement with notice
if (i) the Company discontinues operation of its business or is forced to reduce
its personnel due to lack of work or (ii) Mr. Kalia becomes “permanently
disabled” (as defined in the agreement). If Mr. Kalia breaches any of
the terms of the agreement or if there is just cause for termination, the
Company may terminate Mr. Kalia without notice. Mr. Kalia may
terminate his employment with one month’s notice. On January 1, 2009,
Mr. Kalia’s employment agreement was amended to change the original grant of
1,000,000 shares into warrants to purchase 1,000,000 restricted common shares at
an exercise price of $0.001 per share. The vesting schedule remains
unchanged, vesting quarterly in four equal portions starting on January 1,
2009.
On
September 17, 2008, the Company entered into an employment agreement with Terry
Pilling to serve as its Chief of Operations and Technology. Pursuant
to the agreement, Mr. Pilling will receive annual compensation of
$100,000. He will have the opportunity to acquire stock
options through a Company plan if and when the Company adopts an equity
incentive plan, and the Company will contribute one-half of the value of the
stock as part of his compensation, not to exceed 15% of the his gross annual
salary. Mr. Pilling is entitled to participate in the benefits from
time to time in effect for the Company’s employees holding similar positions,
along with vacation, sick and holiday pay in accordance with policies
established and in effect from time to time. The Company may
terminate the employment agreement with notice if (i) the Company discontinues
operation of its business or is forced to reduce its personnel due to lack of
work or (ii) Mr. Pilling becomes “permanently disabled” (as defined in the
agreement). If Mr. Pilling breaches any of the terms of the agreement
or if there is just cause for termination, the Company may terminate Mr. Pilling
without notice. Mr. Pilling may terminate his employment with one
month’s notice. On February 15, 2010, Mr. Pilling was promoted to
Executive Vice President.
On
November 27, 2007, the Company entered into an employment agreement with Ryan
Fegley to serve as a Project Manager to develop wind
projects. Pursuant to the agreement, Mr. Fegley received annual
compensation of $35,000. Mr. Fegley was also a director of the
Company. Mr. Fegley resigned as director and Vice President of
Project Development as of May 15, 2009. In anticipation of the Merger, in
June 2008, the Company granted Mr. Fegley warrants to purchase 5,000,000 shares
of Crownbutte ND common stock, exercisable for three years, at an exercise price
of $0.01 per share. At the merger, this warrant was exchanged for warrants
to purchase 5,000,000 of Company common stock, at an exercise price of $0.01 per
share.
Director
Compensation
We do not
award stock options to our directors for their services as directors. Our
directors are paid $500 per year and reimbursed for reasonable and necessary
out-of-pocket expenses incurred in connection with their service to us,
including travel expenses.
92
|
ITEM
12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
|
The
following tables set forth certain information regarding the beneficial
ownership of our common stock as of April 14, 2010, by (i) each person who, to
our knowledge, owns more than 5% of the common stock; (ii) each of our directors
and executive officers; and (iii) all of our executive officers and directors as
a group. Unless otherwise indicated in the footnotes to the following
tables, each person named in the table has sole voting and investment power,
except to the extent such power may be shared with a spouse, and that person’s
address is c/o Crownbutte Wind Power, Inc., 111 5th Avenue NE, Mandan,
ND 58554. Shares of common stock subject to options or
warrants currently exercisable or exercisable within 60 days of that date are
deemed outstanding for computing the share ownership and percentage of the
person holding such options and warrants, but are not deemed outstanding for
computing the percentage of any other person.
|
Name
and Address of Beneficial Owner
|
Amount and
Nature of
Beneficial
Ownership
|
Percent of
Class
+
|
||||||
|
Timothy H. Simons
(1)
|
13,000,000
|
39.1
|
%
|
|||||
|
Ross
D. Mushik
|
*
|
*
|
||||||
|
Manu Kalia
(2)
|
2,082,164
|
6.1
|
%
|
|||||
|
Terry
Pilling
|
*
|
*
|
||||||
|
Directors and
executive officers as a group
(1) –
(2)
|
15,082,164
|
42.8
|
%
|
|||||
|
Dan
Gefroh
|
5,000,000
|
15.7
|
%
|
|||||
* Less than one percent
+
Based on
32,257,472 shares of common stock issued and outstanding as of April 14,
2010.
|
(1)
|
Includes
1,000,000 shares of common stock issuable upon exercise of warrants
currently exercisable or exercisable within 60
days.
|
|
(2)
|
Includes
warrants to purchase 2,000,000 shares of restricted stock that are
currently exercisable or exercisable within 60
days.
|
Other
than as disclosed below and in this Annual Report, there have been no
transactions, or currently proposed transactions, in which we were or are to be
a participant and the amount involved exceeds the lesser of $120,000 or 1% of
the average of our total assets at year end for the last two completed fiscal
years and in which any of our directors, executive officers or beneficial
holders of more than 5% of our outstanding common stock, or any of their
respective immediate family members, has had or will have any direct or material
indirect interest.
93
In June
2008, Timothy Simons agreed to surrender 3,000,000 shares of Crownbutte ND
common stock, in exchange for a warrant to purchase 1,000,000 shares of
Crownbutte ND common stock, exercisable for five years, at an exercise price of
$0.10 per share. At the merger, this warrant was exchanged for a
warrant to purchase 1,000,000 of our common stock as a result of the merger, at
an exercise price of $0.10 per share. Also upon the closing of the
merger, Mr. Simons received 12,000,000 shares of our common stock in exchange
for 12,000,000 shares of Crownbutte ND common stock. Between May 21
and September 29, 2009, the Company borrowed a total of $44,380 from Mr.
Simons. These loans are non-interest bearing and payable on
demand.
Ryan
Fegley, a director and Vice President of Project Development of the Company
until May 15, 2009, was party to an employment agreement with the Company and
received compensation thereunder. See the “Executive Compensation”
section. In June 2008, in consideration of his services, Crownbutte
ND granted to Mr. Fegley a warrant to purchase 5,000,000 shares of Crownbutte ND
common stock, exercisable for three years, at an exercise price of $0.01 per
share. At the merger, this warrant was exchanged for a warrant to
purchase 5,000,000 of our common stock, at an exercise price of $0.01 per
share.
On
September 15, 2008, Manu Kalia has entered into an employment agreement with the
Company and receives compensation thereunder. See the “Executive
Compensation” section. At the closing of the merger on July 2, 2008,
we issued 5,400,000 shares of our common stock (on a pre-reverse stock split
basis) to Mr. Kalia pursuant to a Memorandum of Understanding between the
Company and Mr. Kalia.
On
September 17, 2008, Terry Pilling has entered into an employment agreement with
the Company and receives compensation thereunder. Mr. Pilling is
compensated $100,000 annually as Executive Vice President. See the
“Executive Compensation” section.
Ross
Mushik, a director appointed to the Board in June 2009, owns and operates Ross
Lawn and Snow Services, LLC and conducts business with the Company providing
snow removal services. Amounts billed to the Company for snow removal
average less than $1,000 annually.
Audit
Fees
.
The
aggregate fees billed to us by our principal accountant for services rendered
during the fiscal years ended December 31, 2009 and 2008 are set forth in the
table below:
|
Fee Category
|
Fiscal year ended December 31,
2009
|
Fiscal year ended December 31,
2008
|
||||||
|
Audit
fees (1)
|
$ | 44,500 | $ | 44,000 | ||||
|
Audit-related
fees (2)
|
$ | 30,000 | $ | 0 | ||||
|
Tax
fees (3)
|
$ | 0 | $ | 0 | ||||
|
All
other fees (4)
|
$ | 0 | $ | 0 | ||||
|
Total
fees
|
$ | 0 | $ | 0 | ||||
94
|
(1)
|
“Audit
fees” consists of fees billed for professional services rendered for the
audit of consolidated financial statements, for reviews of our interim
consolidated financial statements included in our quarterly reports on
Forms 10-Q and for services that are normally provided in connection with
statutory or regulatory filings or
engagements.
|
|
(2)
|
“Audit-related
fees” consists of fees billed for assurance and related services that are
reasonably related to the performance of the audit or review of our
consolidated financial statements, but are not reported under “Audit
fees,”
consisting
of fees associated with the Company’s Registration Statement on Form
S-1.
|
|
(3)
|
“Tax
fees” consists of fees billed for professional services relating to tax
compliance, tax planning, and tax
advice.
|
|
(4)
|
“All
other fees” consists of fees billed for all other
services.
|
Audit Committee’s
Pre-Approval Practice
Our Board
currently has no separate Audit Committee. Accordingly, the entire
Board of Directors functions as our audit committee. Our Board is
directly responsible for the appointment, compensation, retention and oversight
of the work of any registered public accounting firm engaged by us for the
purpose of preparing or issuing an audit report or performing other audit,
review or attest services for us, and each such registered public accounting
firm must report directly to the Board. It is our Board’s policy to
approve in advance all audit, review and attest services and all non-audit
services (including, in each case, the engagement fees therefor and terms
thereof) to be performed by our independent auditors, in accordance with
applicable laws, rules and regulations. During fiscal 2009 and 2008,
all such services were pre-approved by the Board in accordance with this
policy.
Our Board
selected Sherb & Co., LLP as our independent registered public accounting
firm for purposes of auditing our financial statements for the year ended
December 31, 2009. In accordance with Board’s practice, Sherb &
Co., LLP was pre-approved by the Board to perform these audit services for us
prior to its engagement.
Financial
Statement Schedules
The
consolidated financial statements of Crownbutte Wind Power, Inc. are listed on
the Index to Financial Statements on this annual report on Form 10-K beginning
on page F-1.
All
financial statement schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes
thereto.
95
Exhibits
The
following Exhibits are being filed with this Annual Report on Form
10-K:
In
reviewing the agreements included or incorporated by reference as exhibits to
this Annual Report on Form 10-K, please remember that they are included to
provide you with information regarding their terms and are not intended to
provide any other factual or disclosure information about us or the other
parties to the agreements. The agreements may contain representations
and warranties by each of the parties to the applicable
agreement. These representations and warranties have been made solely
for the benefit of the parties to the applicable agreement and:
|
|
·
|
should
not in all instances be treated as categorical statements of fact, but
rather as a way of allocating the risk to one of the parties if those
statements prove to be inaccurate;
|
|
|
·
|
have
been qualified by disclosures that were made to the other party in
connection with the negotiation of the applicable agreement, which
disclosures are not necessarily reflected in the
agreement;
|
|
|
·
|
may
apply standards of materiality in a way that is different from what may be
viewed as material to you or other investors;
and
|
|
|
·
|
were
made only as of the date of the applicable agreement or such other date or
dates as may be specified in the agreement and are subject to more recent
developments.
|
Accordingly,
these representations and warranties may not describe the actual state of
affairs as of the date they were made or at any other
time. Additional information about us may be found elsewhere in this
Annual Report on Form 10-K and our other public filings, which are available
without charge through the SEC’s website at
http://www.sec.gov
.
|
Exhibit
No.
|
Description
|
|||
|
2.1
|
(1)
|
Agreement
and Plan of Merger and Reorganization, dated as of July 2, 2008, by and
among Crownbutte Wind Power, Inc. (f/k/a ProMana Solutions, Inc.), a
Nevada corporation (the “Registrant” or the “Company”), Crownbutte
Acquisition Sub Inc., a North Dakota corporation, and Crownbutte Wind
Power, Inc., a North Dakota corporation
|
||
|
2.2
|
(1)
|
Articles
of Merger of Crownbutte Acquisition Sub Inc. with and into Crownbutte Wind
Power, Inc., a North Dakota corporation, filed as of July 2,
2008
|
||
|
3.1
|
(1)
|
Restated
Articles of Incorporation of the Registrant, filed as of July 2,
2008
|
||
|
3.2
|
(1)
|
Amended
and Restated Bylaws of the Registrant, adopted as of June
2008
|
||
|
4.1
|
(1)
|
Form
of the certificate representing the Registrant’s common stock, par value
$0.001 per share
|
||
|
4.2
|
(1)
|
Form
of Warrant of the Registrant issued to former holders of warrants of
Crownbutte Wind Power, Inc., a North Dakota corporation, issued in
connection with a private placement offering by Crownbutte Wind Power,
Inc., a North Dakota corporation, completed in April
2008
|
96
|
Exhibit
No.
|
Description
|
|||
|
4.3
|
(1)
|
Form
of Investor Warrant of the Registrant, issued in connection with a private
placement offering by the Registrant completed in September
2008
|
||
|
4.4
|
(1)
|
Form
of Lock-Up Agreement between the Registrant and Timothy H. Simons and Dan
Gefroh
|
||
|
10.1
|
(1)
|
Split-Off
Agreement, dated as of July 2, 2008, by and among the Registrant, Pro Mana
Technologies, Inc., Crownbutte Wind Power, Inc., a North Dakota
corporation, Robert A. Basso and Lawrence J. Kass
|
||
|
|
||||
|
10.2
|
(1)
|
General
Release Agreement, dated as of July 2, 2008, by and among the Registrant,
Pro Mana Technologies, Inc., Crownbutte Wind Power, Inc., a North Dakota
corporation, Robert A. Basso and Lawrence J. Kass
|
||
|
|
||||
|
10.3
|
(1)
|
Escrow
Agreement, dated as of July 2, 2008, by and among the Registrant, Timothy
H. Simons and Gottbetter & Partners, LLP
|
||
|
10.4
|
(1)
|
Form
of Subscription Agreement by and between Crownbutte Wind Power LLC and
certain investors
|
||
|
10.5
|
(1)
|
Form
of Subscription Agreement by and between the Registrant and certain
investors
|
||
|
10.6
|
(1)
|
Form
of Registration Rights Agreement by and between the Registrant and the
selling stockholders
|
||
|
10.7
|
(1)
|
Escrow
Agreement, dated as of July 2, 2008, by and among the Registrant,
Strasbourger Pearson Tulcin Wolff, Inc. and Gottbetter & Partners,
LLP
|
||
|
10.8
|
(1)
|
Placement
Agency Agreement, dated as of November 15, 2007, by and between Crownbutte
Wind Power LLC and Strasbourger Pearson Tulcin Wolff,
Inc.
|
||
|
10.9
|
(1)
|
Memorandum
of Understanding, dated as of July 15, 2006, by and between the Registrant
and Manu Kalia
|
||
|
10.10
|
(1)
|
Employment
Contract, dated as of September 15, 2008, by and between the Registrant
and Manu Kalia
|
||
|
10.11
|
(1)
|
Employment
Contract, dated as of November 27, 2007, by and between the Registrant and
Ryan Fegley
|
||
|
10.12
|
(1)
|
Asset
Purchase and Development Agreement, effective December 27, 2006, between
Crownbutte Wind Power LLC and Gascoyne Wind LLC
|
||
|
10.13
|
(2)
|
Asset
Purchase Agreement, effective September 30, 2008, between Crownbutte Wind
Power LLC and Gascoyne Wind LLC
|
||
|
10.14
|
(1)
|
General
Consulting Services Agreement, dated July 31, 2007, between Crownbutte
Wind Power LLC and Montana-Dakota Utilities Co.
|
||
|
10.15
|
(1)
|
Wind
Development Agreement, dated January 14, 2008, between Crownbutte Wind
Power LLC and EverGreen Energy
|
97
|
Exhibit
No.
|
Description
|
|||
|
10.16
|
(1)
|
Gascoyne
Wind Park Joint Venture Agreement, dated May 27, 2008, between Crownbutte
Wind Power LLC and Westmoreland Power, Inc.
|
||
|
10.17
|
(1)
|
Asset
Purchase Agreement, dated September 25, 2008, between Crownbutte Wind
Power, Inc., a North Dakota corporation, and American Seawind Energy
LLC
|
||
|
10.18
|
(1)
|
Form
of Lease Option Agreement & Wind Energy Lease between the Registrant
and a landowner
|
||
|
10.19
|
(2)
|
Employment
Contract, dated as of September 17, 2008, by and between the Registrant
and Terry Pilling
|
||
|
10.20
|
*
|
Promissory
Note, dated as of March 29, 2010, in the principal amount of $100,000,
issued by the Registrant to Catherine C. Coleman
|
||
|
10.21
|
*
|
Promissory
Note, dated as of March 29, 2010, in the principal amount of $100,000,
issued by the Registrant to David L. Cohen
|
||
|
21
|
(1)
|
Subsidiaries
of the Registrant
|
||
|
31.1
|
*
|
Certification
of Principal Executive Officer, pursuant to SEC Rules 13a-14(a) and
15d-14(a), adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002
|
||
|
31.2
|
*
|
Certification
of Principal Financial Officer, pursuant to SEC Rules 13a-14(a) and
15d-14(a), adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002
|
||
|
32.1
|
*
|
Certification
of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350,
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002†
|
||
|
32.2
|
|
*
|
|
Certification
of Acting Chief Financial Officer, pursuant to 18 U.S.C.
Section 1350, adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002†
|
|
(1)
|
Incorporated
by reference to the like numbered Exhibit to the Registrant’s Amendment
No. 1 to Registration Statement on Form S-1 (File No. 333-156467), filed
with the SEC on April 24, 2009.
|
|
(2)
|
Incorporated
by reference to the like numbered Exhibit to the Registrant’s Amendment
No. 2 to Registration Statement on Form S-1 (File No. 333-156467), filed
with the SEC on June 19, 2009.
|
* Filed
herewith.
† This
certification is being furnished and shall not be deemed “filed” with the SEC
for purposes of Section 18 of the Exchange Act, or otherwise subject to the
liability of that section, and shall not be deemed to be incorporated by
reference into any filing under the Securities Act or the Exchange Act, except
if and to the extent that the Registrant specifically incorporates it by
reference.
98
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, as amended, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
|
CROWNBUTTE
WIND POWER, INC.
|
||
|
Dated: April
15, 2010
|
By:
|
/s/ Timothy H. Simons
|
|
Timothy
H. Simons, Chief Executive Officer
|
||
|
By:
|
/s/ Manu Kalia
|
|
|
Manu
Kalia, Chief Financial
Officer
|
||
In
accordance with the Exchange Act, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the
dates indicated.
|
SIGNATURE
|
TITLE
|
DATE
|
||
|
/s/ Timothy H. Simons
|
Director
and Chief Executive
|
April
15, 2010
|
||
|
Timothy
H. Simons
|
Officer
(principal executive officer)
|
|||
|
/s/ Manu Kalia
|
Chief
Financial Officer (principal
|
April
15, 2010
|
||
|
Manu
Kalia
|
financial
officer and principal accounting officer)
|
|||
|
/s/ Ross D. Mushik
|
Director
|
April
15, 2010
|
||
|
Ross
D. Mushik
|
||||
|
|
|
|||
|
/s/ Terry Pilling
|
Director
|
April
15, 2010
|
||
|
Terry
Pilling
|
|
|
99
INDEX
TO FINANCIAL STATEMENTS
|
Page
|
|||
|
Reports
of Independent Registered Public Accounting Firm
|
F-2 | ||
|
Consolidated
Balance Sheets as of December 31, 2009 and 2008
|
F-3 | ||
|
Consolidated
Statements of Operations for the years ended December 31, 2009 and
2008
|
F-4 | ||
|
Consolidated
Statement of Changes in Stockholders’ Equity (Deficit) for the year ended
December 31, 2009
|
F-5 | ||
|
Consolidated
Statements of Cash Flows for the years ended December 31, 2009 and
2008
|
F-6 | ||
|
Notes
to Consolidated Financial Statements
|
F-7 |
F-1
REPORTS
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Stockholders and Board of Directors
Crownbutte
Wind Power, Inc.
We have
audited the accompanying consolidated balance sheets of Crownbutte Wind Power,
Inc. as of December 31, 2009 and 2008 and the related consolidated statements of
operations, stockholders’ equity and cash flows for the years then
ended. These consolidated financial statements are the responsibility
of the Company’s management. Our responsibility is to express an
opinion on these financial statements 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
the financial statements are free of material misstatement. The
Company is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Accordingly we express no
such opinion. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of Crownbutte Wind Power, Inc. as of
December 31, 2009 and 2008 and the results of their operations and their cash
flows for the years then ended, in conformity with accounting principles
generally accepted in the United States of America.
The
accompanying consolidated financial statements have been prepared assuming that
the Company will continue as a going concern. The Company has
incurred significant losses as more fully described in Note 2. These
issues raise substantial doubt about the Company’s ability to continue as a
going concern. Management’s plans in regard to these matters are also
described in Note 2. The consolidated financial statements do not
include any adjustments that might result from the outcome of this
uncertainty.
|
/s/ Sherb & Co., LLP
|
|
|
Certified
Public Accountants
|
|
|
New
York, New York
|
|
|
April
15, 2010
|
|
F-2
CROWNBUTTE
WIND POWER, INC.
For
the years ended December 31, 2009 and 2008
|
December 31, 2009
|
December 31, 2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
Assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 17,322 | $ | 304,703 | ||||
|
Certificates
of deposit
|
- | 152,029 | ||||||
|
Other
current assets
|
3,949 | 23,109 | ||||||
|
Total
current assets
|
21,271 | 479,841 | ||||||
|
Other
assets:
|
||||||||
|
Interconnect
application deposits
|
91,638 | 112,346 | ||||||
|
Property
and equipment, net
|
166,088 | 234,357 | ||||||
|
Total
other assets
|
257,726 | 346,703 | ||||||
| $ | 278,997 | $ | 826,544 | |||||
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY (DEFICIT)
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable
|
$ | 371,297 | $ | 128,683 | ||||
|
Accrued
expenses
|
239,886 | 50,958 | ||||||
|
Stockholder
loan payable
|
20,000 | - | ||||||
|
Due
to officer
|
42,380 | - | ||||||
|
Total
current liabilities
|
673,563 | 179,641 | ||||||
|
Total
liabilities
|
673,563 | 179,641 | ||||||
|
Stockholders’
equity (deficit):
|
||||||||
|
Preferred
stock, $0.001 par value, 25,000,000 shares authorized none issued and
outstanding
|
- | - | ||||||
|
Common
stock, $0.001 par value, 300,000,000 shares authorized 31,300,331 and
26,200,331 issued and outstanding
|
31,300 | 26,200 | ||||||
|
Additional
paid-in capital
|
5,113,209 | 4,336,606 | ||||||
|
Retained
earnings deficit
|
(5,539,075 | ) | (3,715,903 | ) | ||||
|
Total
stockholders’ equity (deficit)
|
(394,566 | ) | 646,903 | |||||
|
Total
liabilities and stockholders’ equity (deficit)
|
$ | 278,997 | $ | 826,544 | ||||
See
accompanying notes to audited consolidated financial
statements.
F-3
CROWNBUTTE
WIND POWER, INC.
For
the years ended December 31, 2009 and 2008
|
For the years ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Sale
of project development rights
|
$ | - | $ | 200,000 | ||||
|
Consulting
revenues
|
- | 73,020 | ||||||
|
Total
revenues
|
$ | - | $ | 273,020 | ||||
|
Cost
of revenues:
|
||||||||
|
Project
development rights
|
- | 34,593 | ||||||
|
Consulting
revenues
|
- | 3,482 | ||||||
|
Total
cost of revenues
|
- | 38,075 | ||||||
|
Gross
profit
|
- | 234,945 | ||||||
|
Operating
expenses:
|
||||||||
|
General
and administrative (includes stock based compensation of $702,702 and
$2,739,974 in 2009 and 2008)
|
1,828,235 | 4,169,687 | ||||||
|
Depreciation
expense
|
32,459 | 21,039 | ||||||
|
Total
operating expenses
|
1,860,694 | 4,190,726 | ||||||
|
Net
operating loss
|
(1,860,694 | ) | (3,955,781 | ) | ||||
|
Other
income (expenses):
|
||||||||
|
Interest
income
|
935 | 11,282 | ||||||
|
Other
income
|
60,772 | - | ||||||
|
Interest
expense
|
(4,094 | ) | - | |||||
|
Bad
debt expense
|
(1,722 | ) | - | |||||
|
Loss
on sale of fixed assets
|
(18,369 | ) | - | |||||
|
Total
other income (expenses)
|
37,522 | 11,282 | ||||||
|
Net
loss
|
$ | (1,823,172 | ) | $ | (3,944,499 | ) | ||
|
Basic
and diluted - net loss per common share
|
$ | (0.07 | ) | $ | (0.20 | ) | ||
|
Basic
and diluted - weighted average common shares outstanding
|
26,595,947 | 20,019,294 | ||||||
See
accompanying notes to audited consolidated financial
statements.
F-4
CROWNBUTTE
WIND POWER, INC.
Consolidated
Statement of Changes in Stockholders’ Equity (Deficit)
For
the year ended December 31, 2009
|
Common Stock
|
Additional
|
Retained
|
Total
Stockholders’
|
|||||||||||||||||
|
($.001 par value)
|
Paid-In
|
Earnings
|
Equity
|
|||||||||||||||||
|
Shares
|
Amount
|
Capital
|
(Deficit)
|
(Deficit)
|
||||||||||||||||
|
Balance,
December 31, 2007
|
17,000,000 | $ | 17,000 | $ | (17,000 | ) | $ | 228,596 | $ | 228,596 | ||||||||||
|
Shares
effectively issued to former ProMana shareholders as part of the July 2,
2008 recapitalization
|
1,482,331 | 1,482 | (1,482 | ) | - | - | ||||||||||||||
|
Common
stock and warrants issued for cash
|
4,218,000 | 4,218 | 1,618,615 | - | 1,622,833- | |||||||||||||||
|
Conversion
of warrants to common stock
|
3,500,000 | 3,500 | (3,500 | ) | - | - | ||||||||||||||
|
Stock-based
compensation
|
- | - | 2,739,974 | - | 2,739,974 | |||||||||||||||
|
Net
loss
|
- | - | - | (3,944,499 | ) | (3,944,499 | ) | |||||||||||||
|
Balance,
December 31, 2008
|
26,200,331 | $ | 26,200 | $ | 4,336,607 | $ | (3,715,903 | ) | $ | 646,904 | ||||||||||
|
Issuance
of common stock for services
|
100,000 | 100 | 28,900 | - | 29,000 | |||||||||||||||
|
Exercise
of 5,000,000 warrants
|
5,000,000 | 5,000 | 45,000 | - | 50,000 | |||||||||||||||
|
Stock-based
compensation
|
- | - | 702,702 | - | 702,702 | |||||||||||||||
|
Net
loss
|
- | - | - | (1,823,172 | ) | (1,823,172 | ) | |||||||||||||
|
Balance,
December 31, 2009
|
31,300,331 | $ | 31,300 | $ | 5,113,209 | $ | (5,539,075 | ) | $ | (394,566 | ) | |||||||||
See
accompanying notes to audited consolidated financial
statements.
F-5
CROWNBUTTE
WIND POWER, INC.
For
the years ended December 31, 2009 and 2008
|
For the years ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Cash
flows from operating activities:
|
||||||||
|
Net
loss
|
$ | (1,823,172 | ) | $ | (3,944,499 | ) | ||
|
Adjustments
to reconcile net loss to net cash provided by operating
activities:
|
||||||||
|
Depreciation
|
32,459 | 21,039 | ||||||
|
Bad
debt
|
1,722 | - | ||||||
|
Stock
issued for services
|
29,000 | - | ||||||
|
Warrants
exercised for services
|
8,357 | - | ||||||
|
Stock-based
compensation
|
702,702 | 2,739,974 | ||||||
|
Loss
on sale of fixed assets
|
18,369 | - | ||||||
|
Changes
in operating assets and liabilities:
|
||||||||
|
Decrease
(increase) in:
|
||||||||
|
Other
assets
|
38,147 | (125,102 | ) | |||||
|
Increase
in:
|
||||||||
|
Accounts
payable
|
245,467 | 122,246 | ||||||
|
Accrued
expenses
|
186,074 | 27,441 | ||||||
|
Total
adjustments
|
1,262,297 | 2,785,598 | ||||||
|
Net
cash used in operating activities
|
(560,875 | ) | (1,158,901 | ) | ||||
|
Cash
flows from investing activities:
|
||||||||
|
Certificates
of deposit redeemed
|
152,030 | 140,889 | ||||||
|
Investment
in certificates of deposit
|
- | (152,030 | ) | |||||
|
Purchase
of fixed assets
|
(5,259 | ) | (170,499 | ) | ||||
|
Proceeds
from sale of fixed assets
|
22,700 | - | ||||||
|
Net
cash provided by (used in) investing activities
|
169,471 | (181,640 | ) | |||||
|
Cash
flows from financing activities:
|
||||||||
|
Net
proceeds of private placement
|
- | 1,622,833 | ||||||
|
Proceeds
from exercise of warrants
|
41,643 | - | ||||||
|
Deferred
financing costs
|
- | 50,000 | ||||||
|
Payment
of dividends
|
- | (153,333 | ) | |||||
|
Proceeds
from stockholder loan
|
20,000 | - | ||||||
|
Proceeds
from officer loan
|
44,380 | - | ||||||
|
Payments
on officer loan
|
(2,000 | ) | - | |||||
|
Net
cash provided by financing activities
|
104,023 | 1,519,500 | ||||||
|
Net
increase (decrease) in cash and cash equivalents
|
(287,381 | ) | 178,959 | |||||
|
Cash
and cash equivalents, beginning of period
|
304,703 | 125,744 | ||||||
|
Cash
and cash equivalents, end of period
|
$ | 17,322 | $ | 304,703 | ||||
|
Supplemental disclosures of cash flow
information:
|
||||||||
|
Cash
paid during the year for:
|
||||||||
|
Interest
paid
|
$ | 4,094 | $ | - | ||||
|
Taxes
paid
|
$ | 119 | $ | - | ||||
See
accompanying notes to audited consolidated financial
statements.
F-6
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
Crownbutte
Wind Power LLC (“Crownbutte ND”) was founded on May 11, 1999 with the strategy
of addressing the requirements of regional utility companies to satisfy
increasing renewable energy demands. Crownbutte ND was formed as a limited
liability company (LLC) in the State of North Dakota and elected to be taxed as
an S corporation effective January 1, 2001. On March 11, 2008, Crownbutte ND no
longer met the requirements to be treated as an S corporation. As a
result, effective March 11, 2008, Crownbutte ND has been taxed like a C
corporation. On May 19, 2008, Crownbutte ND filed with the Secretary
of State of North Dakota to convert from an LLC to a C corporation becoming
“Crownbutte Wind Power, Inc.” On July 2, 2008, Crownbutte ND became a
wholly owned subsidiary of Crownbutte Wind Power, Inc., a Nevada corporation,
formerly ProMana Solutions, Inc. as described below.
In
cooperation with a local utility, Crownbutte developed and constructed the first
utility-scale wind facility in either of the Dakotas in 2001, consisting of two
turbines near Chamberlain, South Dakota.
The
Company currently functions as a wind park developer as well as a consulting and
advisory service to power utilities.
ProMana
Solutions, Inc. (or “ProMana”)
ProMana
was incorporated in the State of Nevada on March 9, 2004, under the name ProMana
Solutions, Inc. ProMana’s business was to provide web-based, fully integrated
solutions for managing payroll, benefits, human resource management and business
processing outsourcing to small and medium sized businesses. Following the
merger described below, ProMana is no longer in that web services business. On
July 2, 2008, ProMana amended its Articles of Incorporation to change its name
to Crownbutte Wind Power, Inc.
Merger
On July
2, 2008, pursuant to a Merger Agreement entered into on the same date,
Crownbutte Acquisition Sub Inc., a North Dakota corporation formed on June 6,
2008, and a wholly owned subsidiary (“Acquisition Sub”), merged with and into
Crownbutte ND, with Crownbutte ND being the surviving corporation (the
“Merger”). As a result of the Merger, Crownbutte ND became a wholly-owned
subsidiary of the Company.
Pursuant
to the Merger, ProMana ceased operating as a provider of web-based, fully
integrated solutions for managing payroll, benefits, human resource management
and business processing outsourcing, and acquired the business of Crownbutte ND
to develop wind parks from green field to operation and has continued Crownbutte
ND’s business operations as a publicly-traded company. See “Split-Off
Agreement” below.
At the
closing of the Merger, each share of Crownbutte ND’s common stock issued and
outstanding immediately prior to the closing of the Merger was converted into
one share of the Company’s common stock. As a result, an aggregate of 18,100,000
shares of common stock were issued to the holders of Crownbutte ND’s common
stock, 17,000,000 of which were issued to the original members of Crownbutte
Wind Power LLC and 1,100,000 to investors in Crownbutte ND who purchased shares
in a private placement prior to the merger. In addition, warrants to purchase an
aggregate of 10,600,000 shares of Crownbutte ND’s outstanding at the time of the
Merger became warrants to purchase an equivalent number of shares of the
Company’s common stock.
Split-Off
Agreement
Upon the
closing of the Merger, under the terms of a Split-Off Agreement, ProMana
transferred all of its pre-Merger operating assets and liabilities to its
wholly-owned subsidiary, ProMana Technologies, Inc., a New Jersey
corporation (“ProMana NJ”). Simultaneously, pursuant to the Split-Off
Agreement, ProMana transferred all of the outstanding shares of capital stock of
ProMana NJ to two stockholders prior to the Merger (the “Split-Off”), in
consideration of and in exchange for (i) the surrender and cancellation of an
aggregate of 144,702 shares of the common stock and warrants to purchase 19,062
shares of common stock held by those stockholders and (ii) certain
representations, covenants and indemnities.
F-7
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
Stock
Split
The Board
of Directors authorized a one-for-65.723 reverse split of the Company’s common
stock (the “Stock Split”), which was effective on July 31, 2008, for holders of
record on July 14, 2008. After giving effect to the Stock Split,
there were outstanding 19,582,249 shares of common stock. All share
and per share numbers in this Report relating to the Common Stock prior to the
Stock Split have been adjusted to give effect to the Stock Split retroactively
unless otherwise stated.
For
accounting purposes, the Merger was treated as a recapitalization of the
Company. Crownbutte ND formerly Crownbutte Wind Power LLC is considered the
acquirer for accounting purposes, and the Company’s historical financial
statements before the Merger have been replaced with the historical financial
statements of Crownbutte ND before the Merger in all subsequent filings with the
Securities and Exchange Commission (the “SEC”).
As used
herein, unless the context otherwise requires, the “Company” and “Crownbutte”
refer to Crownbutte ND for periods prior to the merger and to Crownbutte Wind
Power, Inc., a Nevada corporation, formerly ProMana Solutions, Inc., and its
wholly-owned subsidiary, Crownbutte ND, for periods after the
Merger.
The
accompanying audited consolidated financial statements include the results of
operations of the Company and its subsidiary for the years ended December 31,
2009 and 2008. All material intercompany accounts and transactions
between the Company and its subsidiary have been eliminated in
consolidation.
Certain
reclassifications have been made to prior year amounts to conform to the current
year presentation.
Going
Concern
These
consolidated financial statements have been prepared by management in accordance
with accounting principles generally accepted in the United States on a “going
concern” basis, which presumes the Company will be able to realize its assets
and discharge its liabilities in the normal course of business for the
foreseeable future.
The
Company has incurred operating losses and negative cash flows from its operating
activities for the year ended December 31, 2009, as well as an accumulated
deficit of approximately $5,539,075 as of December 31, 2009 and a working
capital deficit of $652,292.
As of
December 31, 2009, the Company has only $17,322 in cash. The
Company’s ability to pay its obligations as they become due is in danger as it
is in need of immediate financing. The Company’s continued existence
is dependent upon its ability to resolve its liquidity problems, principally by
obtaining equity and or debt financing. The Company’s current
operations are not an adequate source of cash to fund future
operations. In the event that it is unable to obtain debt or equity
financing, it may have to cease or curtail operations.
The
Company’s management continues to focus on procurement of financing for its
Gascoyne I project and is actively engaged in discussion with parties who may be
interested in purchasing development rights of some of the Company’s other
greenfield projects.
The
Company’s ability to continue as a going concern is dependent upon either the
sale of one or more greenfield projects, obtaining additional financing to
develop the properties and the ultimate realization of profits through future
production or sale of properties, and the success of the Company’s business
plan. The outcome of these matters cannot be predicted at this
time. These consolidated financial statements do not include any
adjustments to the amounts and classifications of assets and liabilities that
might be necessary should the Company be unable to continue its
business.
F-8
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
Revenue
Recognition
The
Company recognizes revenue in accordance with guidance issued by the Financial
Accounting Standards Board (“FASB”) on revenue recognition, which requires 1)
evidence of an agreement, 2) delivery of the product or services has occurred 3)
at a fixed or determinable price, and 4) assurance of collection within a
reasonable period of time.
Further,
some revenues are recognized using the percentage of completion method of
accounting. The Company believes that the use of the percentage of completion
method is appropriate as the Company has the ability to make reasonably
dependable estimates of the extent of progress towards completion, contract
revenues and contract costs. The percentage to completion is measured by
monitoring progress using records of actual time, materials and other costs
incurred to date on specific projects compared to the total estimated project
requirements, which corresponds to the costs related to earned revenues.
Estimates of total project requirements are based on prior experience of
customization, delivery and acceptance of the same or similar technology and are
reviewed and updated regularly by management. Provisions for estimated losses on
uncompleted contracts are made in the period in which such losses are first
determined, in the amount of the estimated loss on the entire
contract.
The
Company currently functions in two business areas: as a wind park developer and
as a consulting and advisory service to power utilities. During 2008 the Company
recognized revenues from consulting and advising services to power utilities
(Consulting revenues). The Company made no sales and had no
consulting revenues for the year ended December 31, 2009.
Consulting
services revenue is recognized under guidance that differs from contract
services revenue. Consulting services revenue is recognized when delivery of the
service has occurred; the customer has already received the service, and
along with other revenue recognition criteria, qualifies the transaction as
a sale. Whereas, contract services revenue is recognized when delivery of the
product or service has yet to be completed yet the transaction still qualifies
as a sale. When recognizing contract services revenue, prior to the project’s
start, the Company estimates the cost at each stage of the project. As time
passes and the stages are completed, the contractor recognizes an estimate of
the revenue that has been earned based on the percentage of the estimated costs
that have already been incurred. Using the percentage of completion method
allows revenues and their associated expenses to be recognized in the same
accounting period according to the matching principle, even if the customer has
yet to receive delivery of the goods and services, or if the goods and services
have not been completed by the Company.
Cost
of Revenues
The
Company includes all direct costs related to its contract and sale of
development rights revenues in cost of revenues. The types of costs
include materials and supplies and subcontractor fees and expenses specific to
the project or contract. Additionally, allocations of payroll, taxes,
and benefits are added to cost of revenues based on time worked on each
project. Any project expenses not directly related to
revenue-generating contracts or sales are expensed to research and development
within general and administrative expenses.
Estimates
The
preparation of financial statements in conformity with U.S. generally accepted
accounting principles requires management to make estimates and assumptions that
affect certain reported amounts and disclosures. Accordingly, actual results
could differ from those estimates.
Cash
and Cash Equivalents and Certificates of Deposit
For
purpose of reporting cash flows, the Company considers all accounts with
maturities of three months or less to be cash equivalents. Certificates of
deposit with a maturity of more than three months when purchased are classified
as current assets.
F-9
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
At
December 31, 2008, the Company had certificates of deposit in the amounts of
$100,000 and $52,030 which collected interest of 2.68% and 3.21% and matured on
February 26, 2009 and May 13, 2009, respectively.
Property,
Equipment and Leasehold Improvements
Property,
equipment and leasehold improvements are stated at cost. The Company records
straight-line depreciation based on the estimated useful life of the individual
units of property and equipment. Estimated useful lives are five to ten years
for the property and equipment. Leasehold improvements are amortized
using the straight-line method over the shorter of the estimated useful lives of
the assets or the terms of the leases.
Research
and Development
The
Company expenses research and development as incurred.
Income
Taxes
The
Company was organized as a limited liability company for the year ended December
31, 2007 and the Company’s members elected to be taxed as an S corporation. An S
corporation is not a taxpaying entity for federal and state income tax purposes;
thus, no income tax expenses have been recorded in the financial statements. It
is the responsibility of the members to report their proportionate share of the
Company’s income or loss on the members’ individual income tax
returns.
Since
March 11, 2008, the Company is being taxed as a C corporation. A
short year S corporation tax return and a short year C corporation tax return
was filed. Income tax liability for the years ended December 31, 2009
and 2008 is $0.
Income
taxes are accounted for in accordance with the provisions of FASB ASC 740,
Accounting for Income Taxes. Deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and liabilities and
their respective tax bases. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered or settled. The
effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date. Valuation
allowances are established, when necessary, to reduce deferred tax assets to the
amounts expected to be realized.
Customer
Concentration
Two of
the Company’s customers accounted for 100% of its revenues for the year ended
December 31, 2008. The Company had no revenues for the year ended
December 31, 2009.
Concentration
of Credit Risk
The
Company maintains its cash deposits at various financial institutions. Bank
balances periodically exceed the Federal Deposit Insurance Corporation limits at
one bank.
Fair
Value of Financial Instruments
Effective
January 1, 2008, the Company adopted guidance issued by the Financial Accounting
Standards Board (“FASB”) on “Fair Value Measurements” for assets and liabilities
measured at fair value on a recurring basis. This guidance establishes a common
definition for fair value to be applied to existing generally accepted
accounting principles that require the use of fair value measurements
establishes a framework for measuring fair value and expands disclosure about
such fair value measurements. The adoption of this guidance did not have an
impact on the Company’s financial position or operating results, but did expand
certain disclosures.
F-10
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
The
Financial Accounting Standards Board (“FASB”) defines fair value as the price
that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date.
Additionally, the “FASB” requires the use of valuation techniques that maximize
the use of observable inputs and minimize the use of unobservable inputs. These
inputs are prioritized below:
|
Level 1:
|
Observable inputs such as quoted
market prices in active markets for identical assets or
liabilities
|
|
Level 2:
|
Observable market-based inputs or
unobservable inputs that are corroborated by market
data
|
|
Level 3:
|
Unobservable inputs for which
there is little or no market data, which require the use of the reporting
entity’s own assumptions.
|
The
Company did not have any Level 2 or Level 3 assets or liabilities as
of December 31, 2009 and December 31, 2008. The Company discloses the
estimated fair values for all financial instruments for which it is practicable
to estimate fair value. As of December 31, 2009 and December 31, 2008, the fair
value short-term financial instruments including cash, certificates of deposit,
other current assets, accounts payable, accrued expenses and due to officer,
approximates book value due to their short-term duration.
Cash and
cash equivalents include money market securities and commercial paper that are
considered to be highly liquid and easily tradable. These securities are valued
using inputs observable in active markets for identical securities and are
therefore classified as Level 1 within the fair value
hierarchy.
In
addition, the Financial Accounting Standards Board (“FASB”) issued, “The Fair
Value Option for Financial Assets and Financial Liabilities,” effective for
January 1, 2008. This guidance expands opportunities to use fair value
measurements in financial reporting and permits entities to choose to measure
many financial instruments and certain other items at fair value. The Company
did not elect the fair value option for any of its qualifying financial
instruments.
Stock-Based
Compensation
The
Company accounts for the grant of stock and warrants awards in accordance with
ASC Topic 718, Compensation – Stock Compensation (ASC 718). ASC 718
requires companies to recognize in the statement of operations the grant-date
fair value of warrants and stock options and other equity based
compensation.
The
Company uses the Black-Scholes option valuation model for estimating the fair
value of traded options. This option valuation model requires the
input of highly subjective assumptions including the expected stock price
volatility.
For the
years ended December 31, 2009 and 2008, the Company recorded stock-based
compensation of $702,702 and $2,739,974, respectively.
Basic
and Diluted Earnings per Share
Basic
earnings per share are calculated by dividing income available to stockholders
by the weighted average number of common shares outstanding during each
period. Diluted earnings per share are computed using the weighted
average number of common and dilutive common share equivalents outstanding
during the period. Dilutive common share equivalents consist of
shares issuable upon the exercise of stock options and warrants (calculated
using the modified-treasury stock method). The outstanding warrants
amounted to 7,235,752 and 10,235,752 at December 31, 2009 and 2008,
respectively. For the years ended December 31, 2009 and 2008, these
potentially dilutive securities were not included in the calculation of loss per
share because the Company incurred a loss during such periods and thus their
effect would have been anti-dilutive.
New
Accounting Pronouncements
In June
2009, the FASB issued authoritative guidance which eliminates the exemption for
qualifying special-purpose entities from consolidation requirements, contains
new criteria for determining the primary beneficiary of a variable interest
entity, and increases the frequency of required reassessments to determine
whether a company is the primary beneficiary of a variable interest entity. The
guidance is applicable for annual periods beginning after November 15, 2009 and
interim periods therein and thereafter. The Company does not expect the adoption
of this standard to have a material effect on its financial position or results
of operations.
F-11
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
EITF
Issue No. 07-5 (ASC 815), “Determining Whether an Instrument (or embedded
Feature) is Indexed to an Entity’s Own Stock” (EITF 07-5) was issued in June
2008 to clarify how to determine whether certain instruments or features were
indexed to an entity’s own stock under EITF Issue No. 01-6 (ASC 815), “The
Meaning of “Indexed to a Company’s Own Stock” (EITF 01-6) (ASC 815),. EITF
07-5(ASC 815), applies to any freestanding financial instrument (or embedded
feature) that has all of the characteristics of a derivative as defined in FAS
133, for purposes of determining whether that instrument (or embedded feature)
qualifies for the first part of the paragraph 11(a) scope exception. It is also
applicable to any freestanding financial instrument (e.g., gross physically
settled warrants) that is potentially settled in an entity’s own stock,
regardless of whether it has all of the characteristics of a derivative as
defined in FAS 133 (ASC 815), for purposes of determining whether to apply EITF
00-19 (ASC 815). EITF 07-5(ASC 815) does not apply to share-based payment awards
within the scope of FAS 123(R), Share-Based Payment (FAS 123(R) (ASC 718)).
However, an equity-linked financial instrument issued to investors to establish
a market-based measure of the fair value of employee stock options is not within
the scope of FAS 123(R) and therefore is subject to EITF 07-5(ASC
815).
In
January 2009, the FASB issued FSP EITF 99-20-1 (ASC 325), to amend the
impairment guidance in EITF Issue No. 99-20 (ASC 325) in order to achieve
more consistent determination of whether an other-than-temporary impairment
(“OTTI”) has occurred. This FSP amended EITF 99-20 (ASC 325) to more
closely align the OTTI guidance therein to the guidance in Statement
No. 115 (ASC 320, 10-35-31). Retrospective application to a prior interim
or annual period is prohibited. The guidance in this FSP was considered in the
assessment of OTTI for various securities at December 31,
2008.
On June
5, 2003, the United States Securities and Exchange Commission (“SEC”) adopted
final rules under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”),
as amended by SEC Release No. 33-9072 on October 13, 2009. Commencing with its
annual report for the year ending December 31, 2010, the Company will be
required to include a report of management on its internal control over
financial reporting. The internal control report must include a statement
of:
|
|
·
|
Management’s
responsibility for establishing and maintaining adequate internal control
over its financial reporting;
|
|
|
·
|
Management’s
assessment of the effectiveness of its internal control over financial
reporting as of year- end; and
|
|
|
·
|
The
framework used by management to evaluate the effectiveness of the
Company’s internal control over financial
reporting.
|
Furthermore,
it is required to file the auditor’s attestation report separately on the
Company’s internal control over financial reporting on whether it believes that
the Company has maintained, in all material respects, effective internal control
over financial reporting.
In August
2009, the FASB issued the FASB Accounting Standards Update No. 2009-04
“Accounting for Redeemable Equity Instruments - Amendment to Section 480-10-S99”
which represents an update to section 480-10-S99, distinguishing liabilities
from equity, per EITF Topic D-98, Classification and Measurement of Redeemable
Securities. The Company does not expect the adoption of this update to have a
material impact on its consolidated financial position, results of operations or
cash flows. In August 2009, the FASB issued the FASB Accounting Standards Update
No. 2009-05 “Fair Value Measurement and Disclosures Topic 820 – Measuring
Liabilities at Fair Value”, which provides amendments to subtopic 820-10, Fair
Value Measurements and Disclosures – Overall, for the fair value measurement of
liabilities. This update provides clarification that in circumstances in which a
quoted price in an active market for the identical liability is not available, a
reporting entity is required to measure fair value using one or more of the
following techniques: 1. A valuation technique that uses: a. The quoted price of
the identical liability when traded as an asset b. Quoted prices for similar
liabilities or similar liabilities when traded as assets. 2. Another valuation
technique that is consistent with the principles of topic 820; two examples
would be an income approach, such as a present value technique, or a market
approach, such as a technique that is based on the amount at the measurement
date that the reporting entity would pay to transfer the identical liability or
would receive to enter into the identical liability. The amendments in this
update also clarify that when estimating the fair value of a liability, a
reporting entity is not required to include a separate input or adjustment to
other inputs relating to the existence of a restriction that prevents the
transfer of the liability. The amendments in this update also clarify that both
a quoted price in an active market for the identical liability when traded as an
asset in an active market when no adjustments to the quoted price of the asset
are required are Level 1 fair value measurements. The Company does not expect
the adoption of this update to have a material impact on its consolidated
financial position, results of operations or cash flows.
F-12
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
In
September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-08
“Earnings Per Share – Amendments to Section 260-10-S99”,which represents
technical corrections to topic 260-10-S99, Earnings per share, based on EITF
Topic D-53, Computation of Earnings Per Share for a Period that includes a
Redemption or an Induced Conversion of a Portion of a Class of Preferred Stock
and EITF Topic D-42, The Effect of the Calculation of Earnings per Share for the
Redemption or Induced Conversion of Preferred Stock. The Company does not expect
the adoption of this update to have a material impact on its consolidated
financial position, results of operations or cash flows.
In
September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-09
“Accounting for Investments-Equity Method and Joint Ventures and Accounting for
Equity-Based Payments to Non-Employees”. This update represents a correction to
Section 323-10-S99-4, Accounting by an Investor for Stock-Based Compensation
Granted to Employees of an Equity Method Investee. Additionally, it adds
observer comment Accounting Recognition for Certain Transactions Involving
Equity Instruments Granted to Other Than Employees to the Codification. The
Company does not expect the adoption to have a material impact on its
consolidated financial position, results of operations or cash
flows.
In
September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-12
“Fair Value Measurements and Disclosures Topic 820 – Investment in Certain
Entities That Calculate Net Assets Value Per Share (or Its Equivalent)”, which
provides amendments to Subtopic 820-10, Fair Value Measurements and
Disclosures-Overall, for the fair value measurement of investments in certain
entities that calculate net asset value per share (or its equivalent). The
amendments in this update permit, as a practical expedient, a reporting entity
to measure the fair value of an investment that is within the scope of the
amendments in this update on the basis of the net asset value per share of the
investment (or its equivalent) if the net asset value of the investment (or its
equivalent) is calculated in a manner consistent with the measurement principles
of Topic 946 as of the reporting entity’s measurement date, including
measurement of all or substantially all of the underlying investments of the
investee in accordance with Topic 820. The amendments in this update also
require disclosures by major category of investment about the attributes of
investments within the scope of the amendments in this update, such as the
nature of any restrictions on the investor’s ability to redeem its investments
at the measurement date, any unfunded commitments (for example, a contractual
commitment by the investor to invest a specified amount of additional capital at
a future date to fund investments that will be made by the investee), and the
investment strategies of the investees. The major category of investment is
required to be determined on the basis of the nature and risks of the investment
in a manner consistent with the guidance for major security types in U.S. GAAP
on investments in debt and equity securities in paragraph 320-10-50-1B. The
disclosures are required for all investments within the scope of the amendments
in this update regardless of whether the fair value of the investment is
measured using the practical expedient. The Company does not expect the adoption
to have a material impact on its consolidated financial position, results of
operations or cash flows.
In
October 2009, the FASB issued guidance for amendments to FASB Emerging Issues
Task Force on EITF Issue No. 09-1 “Accounting for Own-Share Lending Arrangements
in Contemplation of a Convertible Debt Issuance or Other Financing” (Subtopic
470-20) “Subtopic”. This accounting standards update establishes the accounting
and reporting guidance for arrangements under which own-share lending
arrangements issued in contemplation of convertible debt issuance. This
Statement is effective for fiscal years, and interim periods within those fiscal
years, beginning on or after December 15, 2009. Earlier adoption is not
permitted. The Company does not expect the adoption to have a material impact on
its consolidated financial position, results of operations or cash
flows.
F-13
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
A variety
of proposed or otherwise potential accounting standards are currently under
study by standard setting organizations and various regulatory agencies. Due to
the tentative and preliminary nature of those proposed standards, management has
not determined whether implementation of such proposed standards would be
material to our consolidated financial statements.
Property
and equipment and related accumulated depreciation consists of the
following:
|
December 31, 2009
|
December 31, 2008
|
|||||||
|
Equipment
and Vehicles
|
$ | 179,370 | $ | 229,495 | ||||
|
Software
|
39,289 | 39,289 | ||||||
|
Leasehold
Improvements
|
938 | - | ||||||
|
Total
Cost
|
219,597 | 268,784 | ||||||
|
Accumulated
Depreciation
|
(53,509 | ) | (34,427 | ) | ||||
|
Net
Property and Equipment
|
$ | 166,088 | $ | 234,357 | ||||
Equipment
and vehicles are depreciated with an estimated useful life of 5 to 10 years and
software has an estimated useful life of 5 years. Depreciation
expense was $32,459 and $21,039 for the years ended December 31, 2009 and 2008,
respectively.
Accrued
expenses consist of the following:
|
December 31, 2009
|
December 31, 2008
|
|||||||
|
Accrued
Payroll
|
$ | 216,254 | $ | 45,984 | ||||
|
Credit
Cards Payable
|
23,262 | - | ||||||
|
Accrued
Vacation
|
324 | - | ||||||
|
Accrued
Interest
|
46 | - | ||||||
|
Payroll
Taxes Payable
|
- | 2,663 | ||||||
|
Sales
Tax Payable
|
- | 2,311 | ||||||
| $ | 239,886 | $ | 50,958 | |||||
Under the
terms of the merger the Company issued 17,000,000 shares of common stock and
1,000,000 warrants to the two original members of Crownbutte ND (formerly
“Crownbutte Wind Power LLC”) and 1,482,331 shares of common stock to the
pre-merger ProMana shareholders.
To
appropriately reflect this recapitalization, the Company has retroactively
restated the equity of the Company prior to the merger date to include the
17,000,000 shares of common stock and 1,000,000 warrants issued to the two
original members of Crownbutte ND (formerly “Crownbutte Wind Power LLC”) in the
merger.
During
the period from March 11, 2008 through September 8, 2008, the Company completed
its private placement to accredited investors for $2,109,000 (net proceeds of
$1,622,833) in units of its securities consisting of 4,218,000 shares of common
stock at a purchase price of $0.50 per share and common stock purchase warrants
to
purchase
4,218,000 shares of common stock.
F-14
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
During
the years ended December 31, 2009 and 2008, the Company issued 5,000,000 and
3,500,000 shares of common stock, respectively, for the exercise of 5,000,000
and 3,500,000 warrants.
During
the year ended December 31, 2009, the Company issued 100,000 shares of common
stock for legal services. These shares were valued at $0.29 per
share, the fair market value at the date of issuance. Accordingly,
the Company recorded legal expense of $29,000.
Stock
Purchase Warrants
During
the year ended December 31, 2008, the Company issued 15,718,000 warrants at
exercise prices ranging from $0.001 and $2.50 per common share as
follows:
In
connection with the merger the Company issued 1,000,000 warrants to one of the
original members of Crownbutte, ND (formerly Crownbutte Wind Power LLC) to
purchase up to 1,000,000 shares of common stock of the Company at an exercise
price of $.10 per share. The warrants have a term of 5 years after
the issuance date of July 2, 2008.
In
connection with private placements a total of 4,218,000 warrants were issued to
purchase up to 4,218,000 shares of common stock of the Company with 1,100,000
warrants at an exercise price of $0.50 per share and 3,118,000 warrants at an
exercise price of $2.50 per share. The 1,100,000 warrants have a term
of 3 years after the issuing date and the 3,118,000 warrants have a term of 2
years after the issuing date. The warrants will be callable by the
Company at any time if the fair market value of the common stock for the twenty
(20) consecutive trading days ending three days prior to the date of the call
notice is at least $3.50. Additionally, the Company issued 3,500,000
to the placement agent at an exercise price of $0.001 per
share. These warrants were exercised during the year ended December
31, 2008.
During
the year ended December 31, 2008, the Company granted 7,000,000 warrants to
purchase 7,000,000 shares of the common stock of the Company. The
warrants included 2,000,000 awarded to the Chief Financial Officer at an
exercise price of $0.001 per share which vest over the next twelve months and
5,000,000 awarded to the Vice President of Project Development at an exercise
price of $0.01 per share which vest immediately. The warrants were
issued at an exercise price significantly less than the offering price of
$0.50. During the year ended December 31, 2009, the 5,000,000
warrants originally awarded to the Vice President of Project Development were
exercised.
The
Company valued these warrants utilizing the Black-Scholes options pricing model
and the following assumption terms: 3 to 5 years; interest
rate: 4%; volatility: 100%. For the year ended
December 31, 2008, the Company recorded compensation expense of approximately
$2,700,000 related to the warrants. This amount represents 100% of
the value of the 5,000,000 warrants which vested immediately and 25% of the
2,000,000 warrants vested by December 31, 2008.
The
2,000,000 warrants granted to the CFO were valued at approximately
$1,000,000. This amount was expensed over the vesting
period. For the year ended December 31, 2009 the Company expensed
approximately $700,000 related to these warrants which became fully vested by
September 15, 2009.
F-15
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
A
reconciliation of warrant activity is as follows:
|
Number of
Shares Issuable
|
Weighted
Average
Exercise Price
|
Weighted
Average Grant
Date
Fair Value
|
||||||||||
|
Balance
at January 1, 2008
|
17,752 | * | $ | 0.65723 | $ | 0.35 | ||||||
|
Granted
|
15,718,000 | 0.68 | 0.35 | |||||||||
|
Exercised
|
(3,500,000 | ) | 0.001 | 0.50 | ||||||||
|
Expired
|
- | - | - | |||||||||
|
Balance
at December 31, 2008
|
12,235,752 | $ | 0.87 | $ | 0.35 | |||||||
|
Balance
at January 1, 2009
|
12,235,752 | $ | 0.87 | $ | 0.35 | |||||||
|
Granted
|
- | - | - | |||||||||
|
Exercised
|
(5,000,000 | ) | 0.01 | 0.49 | ||||||||
|
Expired
|
- | - | - | |||||||||
|
Balance
at December 31, 2009
|
7,235,752 | $ | 1.17 | $ | 0.25 | |||||||
Warrants
outstanding and exercisable at December 31, 2009 have a weighted average
exercise price of $1.17 and an intrinsic value of $738,000. At
December 31, 2008, the warrants exercisable had a weighted average exercise
price of $0.78 and an aggregate intrinsic value of $2,850,000. The
weighted average exercise price of warrants outstanding at December 31, 2008 was
$0.87 with an aggregate intrinsic value of $3,848,000.
The
following tables summarize warrants outstanding and exercisable as of December
31, 2009 and 2008:
|
Exercise Price
|
Number of
shares
underlying
Warrants
|
Weighted-
average
remaining
contractual
life
(in Years)
|
Number of
shares
exercisable
|
Weighted-
average
remaining
contractual
Life of
Warrants
Exercisable
(in Years)
|
|||||||||||||
|
$
0.001
|
2,000,000 | 3.71 | 2,000,000 | 3.71 | |||||||||||||
|
$
0.10
|
1,000,000 | 3.50 | 1,000,000 | 3.50 | |||||||||||||
|
$
0.50
|
1,100,000 | 1.25 | 1,100,000 | 1.25 | |||||||||||||
|
$
0.65723
|
17,752 | * | 17,752 | * | |||||||||||||
|
$
2.50
|
3,118,000 | .46 | 3,118,000 | .46 | |||||||||||||
|
Balance
at December 31, 2009
|
7,235,752 | 1.78 | 7,235,752 | 1.78 | |||||||||||||
F-16
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
|
Exercise Price
|
Number of
shares
underlying
Warrants
|
Weighted-
average
remaining
contractual life
(in Years)
|
Number of
shares
exercisable
|
Weighted-
average
remaining
contractual
Life of Warrants
Exercisable
(in Years)
|
|||||||||||||
|
$
0.001
|
2,000,000 | 4.71 | - | - | |||||||||||||
|
$
0.01
|
5,000,000 | 2.50 | 5,000,000 | 2.50 | |||||||||||||
|
$
0.10
|
1,000,000 | 4.50 | 1,000,000 | 4.50 | |||||||||||||
|
$
0.50
|
1,100,000 | 2.25 | 1,100,000 | 2.25 | |||||||||||||
|
$
0.65723
|
17,752 | * | 17,752 | * | |||||||||||||
|
$
2.50
|
3,118,000 | 1.46 | 3,118,000 | 1.46 | |||||||||||||
|
Balance
at December 31, 2008
|
12,235,752 | 2.66 | 10,235,752 | 2.26 | |||||||||||||
*These
warrants were issued by ProMana prior to the merger. The Company is
unable to identify the remaining contractual life of these
warrants.
The total
intrinsic value of warrants exercised for the years ended December 31, 2009 and
2008 was $1,350,000 and $1,746,500, respectively.
The
Company has a net operating loss carry forward for tax purposes totaling
approximately $964,000 at December 31, 2009. The net operating loss
carries forward for income taxes, which may be available to reduce future years’
taxable income. These carry forwards will expire, if not utilized,
through 2029 and are subject to the Internal Revenue Code Section 382, which
places a limitation on the amount of taxable income that can be offset by net
operating losses after a change in ownership. Management believes
that the realization of the benefits from these losses appears uncertain due to
the Company’s continuing losses for income tax purposes. Accordingly,
the Company has provided a 100% valuation allowance on the deferred tax asset
benefit to reduce the asset to zero. Management will review this
valuation allowance periodically and make adjustments as warranted.
The table
below summarizes the differences between the Company’s effective tax rate and
the statutory federal rate as follows for the year ended December 31, 2009 and
the period ended December 31, 2008:
|
Rate Reconciliation:
|
December 31, 2009
|
December 31, 2008
|
||||||
|
Expected
Federal income tax benefit (at 34%)
|
$ | (637,971 | ) | $ | (1,341,300 | ) | ||
|
State
tax benefit (net of Federal effect)
|
(75,055 | ) | (157,800 | ) | ||||
|
Loss
incurred during S corp period
|
- | 239,020 | ||||||
|
Other
|
380 | 760 | ||||||
|
Change
in valuation allowance
|
712,646 | 1,259,320 | ||||||
|
Net
income tax benefit
|
$ | - | $ | - | ||||
Deferred
tax assets and liabilities are provided for significant income and expense items
recognized in different years for tax and financial reporting
purposes. Temporary differences, which give rise to a net deferred
tax asset is as follows:
F-17
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
|
Schedule of deferred tax assets
|
December 31, 2009
|
December 31, 2008
|
||||||
|
Net
operating loss
|
$ | 366,466 | $ | 211,660 | ||||
|
Temporary
differences: Depreciation
|
8,740 | 6,460 | ||||||
|
Warrant
expense
|
267,140 | 1,041,200 | ||||||
|
Accrued
expenses not paid within 2 ½ months
|
70,300 | - | ||||||
|
Valuation
allowance
|
(712,646 | ) | (1,259,320 | ) | ||||
|
Net
deferred tax asset
|
$ | - | $ | - | ||||
The
Company borrowed funds from Timothy Simons, one of the Company’s stockholders
and its CEO. The terms of the loans are non-interest bearing and
payable upon demand. Amounts owed totaled $42,380 as of December 31,
2009 and $0 for the year ended December 31, 2008.
The
Company borrowed funds from StarInvest Group, Inc., one of the Company’s
stockholders. Terms of the loan are $20,000 at 6% annual interest,
due within one year. The date of the loan is December 18,
2009. As of December 31, 2009, the Company owed $20,000.
The
Company leased office space from Timothy Simons, one of the Company’s
stockholders and its CEO. The lease was a month-to-month lease for
$458 per month. The lease terminated on March 31,
2008. Total rent expense paid for the year ended December 31, 2008
was $1,374.
On May 1,
2008, the Company entered into a lease for office and shop space at $1,500 per
month. The lease is for twelve months and has no renewal
options. Upon expiration of the initial lease term, the lease is
month-to-month. The Company is responsible for paying all utilities
and janitorial.
In August
2007, the Company established a SIMPLE retirement plan. The Company matches
employee contributions up to 3% of gross wages. The Company’s contributions to
the plan were $5,141 and $7,469 for the years ended December 31, 2009 and 2008,
respectively.
The
Company conducted all of its operations for the years ended December 31, 2009
and 2008 under contracts with two companies, a utility and a coal
company. Revenues earned and recognized for the years ended December
31, 2009 and 2008 were $0 and $273,020 for sale of project development rights
($200,000) and consulting revenue ($73,020), respectively.
The
Company expenses all project development costs until management deems a project
probable of being technically, commercially, and financially
viable. The Company capitalizes project development costs generally
once management deems a project probable of being technically, commercially, and
financially viable. This generally occurs in tandem with management’s
determination that a project should be classified as an advanced project, such
as when favorable results of a system impact study are received, interconnect
agreements obtained, and project financing is in place.
F-18
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
On May
27, 2008, the Company entered into a joint venture agreement with Westmoreland
Power, Inc., a coal company, under the name of Gascoyne II Wind Project to
develop, construct, manage, and operate a 200 MW wind power project in southwest
North Dakota. The Company received $200,000 from Westmoreland as
compensation in order to participate in the joint venture. The
Company recognized sale of development rights revenues for this amount for the
year ended December 31, 2008. Crownbutte is the managing
party. For the years ended December 31, 2009 and 2008, the Company
expensed development costs of $11,130 and $5,126, respectively, for this
project.
On June
20, 2008, the Company entered into an agreement with a wind development company
to purchase the rights to develop a wind park near New England, ND for
$100,000. Assets purchased by the Company consist of one met tower,
3.5 years meteorological data, and a land lease cooperation
agreement. For the years ended December 31, 2009 and 2008, the
Company expensed development costs of $13,901 and $89,427, respectively, for
this project.
On
September 18, 2008, the Company entered into an agreement with a wind
development company to purchase the rights to develop a 10 MW wind park near
Ralls, TX for $1,500,000. The agreement calls for a non-refundable
down payment of $200,000, another payment of $1,000,000 by March 10, 2009, and a
final payment of $300,000 upon beginning construction of the wind park, but no
later than September 18, 2009. Assets purchased by the Company
consist of meteorological data, land lease option agreements, permits, licenses,
assignable interconnect agreement, right-of-ways to substations and power lines,
and FFA determination. Should the Company default on any payments,
the seller would be entitled to take back the assets purchased by the
Company. As of December 31, 2008 the Company expensed development
costs totaling $210,270 for this project.
As of
December 31, 2008, the Company abandoned the Ralls, TX project forfeiting the
development rights and related assets. All assets were expensed as
research and development costs and were included in the $210,270 expensed as of
December 31, 2008. No additional costs were incurred in
2009.
In 2007,
the Company sold project development rights for a 20 MW wind park near Gascoyne,
ND to a wind energy company. The Company recognized $75,000 revenue
in 2006 for preliminary development work completed and earned in 2006. For the
year ended December 31, 2007, additional revenue of $250,000 for sale of project
development rights was earned and recognized for final development work
completed prior to transfer of ownership.
In 2008,
the Company decided to repurchase the project. On September 30, 2008 the
Company entered into an agreement with the wind development company to
repurchase the development rights for the 20 MW Gascoyne, ND wind park for
$325,000. For the years ended December 31, 2009 and 2008, the
Company expensed development costs totaling $93,667 and $333,476, respectively,
for this project as it has not yet deemed the project probable of being
technically, commercially, and financially viable.
For the
years ended December 31, 2009 and 2008 the Company expensed an additional
$38,178 and $282,799, respectively, in development costs for smaller projects
not listed above.
The
Company has deemed all of the projects described above as research and
development costs which have been expensed accordingly.
Interconnect
Application Deposits
The
Company pays in advance for electrical interconnect studies. As the
studies are performed, the portions of the advances that are used are expensed.
These costs are incurred as part of the process to obtain an interconnect
agreement. Interconnect deposits are classified as non-current assets as studies
generally exceed one year in length. If a study is complete, any
unused deposits are refunded to the Company. At December 31, 2009 and
December 31, 2008, the Company had $91,638 and $112,346, respectively, of unused
deposits on its balance sheet.
F-19
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
On
September 15, 2008, the Company entered into an employment contract with a new
CFO. The contract calls for a starting annual salary of
$100,000. Once an additional $3,000,000 is raised from the private
placement, the annual salary will increase to $150,000. There is no
specified termination date of employment in the contract.
Legal
proceedings
On August
19, 2008, Centre Square Capital, LLC filed a claim in the amount of $3,000,000
plus attorneys fees, interest, and arbitration costs in a demand for
arbitration, claiming that the Company has not compensated it for introducing
the Company to the firm that raised the private placement capital in March, 2008
and thereafter. On March 16, 2009 a judge dismissed Centre
Square Capital LLC’s claim and awarded the Company reimbursement of all attorney
fees and costs related to the claim. A reimbursement of approximately
$129,227 is payable to the Company.
The
Company accounts for awards of attorney fees and costs resulting from judgments
in its favor on a case-by-case basis. Factors affecting the
accounting treatment include timing of expenses incurred and date of award,
likelihood of collection, and additional costs incurred in the collection
process. Judgments awarded that management deems collectible are
recorded as a receivable. Award amounts for expenses incurred in the
same accounting period are recorded as reductions in the corresponding expense
line item. Reimbursements of prior period expenses are recorded as
other income. Collection of the Centre Square Capital judgment is
uncertain and accordingly, no receivable has been recorded. For the
year ended December 31, 2009 the Company collected $0 of this
award.
On
November 3, 2009, the Company was served with a lawsuit filed against us in the
Philadelphia County Court of Common Pleas under Case ID: 091100318. Stradley,
Ronon, Stevens & Young, LLP (the plaintiffs) filed a claim against the
Company for nonpayment of legal fees and are seeking to recover $93,526 plus
interest, attorneys’ fees and costs. This claim arose as a result of legal
services provided in the Centre Square Capital, LLC arbitration claim filed
August 19, 2008. The Company has included the $93,526 in accounts payable
as of December 31, 2009.
On
December 14, 2009, the Company received a Notice of Intent to Take Default
Judgment from Stradley, Ronon, Stevens & Young, LLP for the unpaid balance
of $93,526. The Company has been working with the plaintiff to make
payments on the debt. In exchange, the plaintiffs have agreed to
postpone execution of the judgment.
In
accordance with ASC 855, “Subsequent Events,” the Company evaluated subsequent
events after the balance sheet date of December 31, 2009 through April 15, 2010,
which is the date the financial statements were issued.
On
February 15, 2010, the Company executed a non-binding term sheet with iStreet
Global, a private equity firm, to provide $37.5 million debt financing for the
Gascoyne I project. The Company will retain 20% ownership and
profit-sharing in the project. Terms of the financing are $14 million to be
repaid over five years at prime plus 4%, 7% floor capped at 10% and $23.5
million repaid over five years at prime plus 6%, 9% floor capped at
12%. Both loans are interest only for the first twelve
months. The lender intends to refinance the $23.5 million loan into a
15 year termed facility either through external funding or internally if no
external sources are available. The deal is contingent upon final
approval of iStreet Global after completion of due diligence. The
Company anticipates a closing date of in the second quarter of
2010.
On
February 22, 2010, the Company Board of Directors executed a Unanimous Written
Consent approving a private placement transaction to offer investors a minimum
of $150,000 (428,571 shares) and a maximum of $700,000 (2,000,000 shares) of the
Company’s common stock at $0.35 per share. Each share sold will
include one warrant to purchase one share of the Company’s common stock
exercisable for a period of four years at an exercise price of $1.50 per share,
and one warrant to purchase one share of common stock, exercisable for four
years, at an exercise price of $2.50 per share. The Company issued
499,999 shares and 999,998 warrants for proceeds of $175,000.
F-20
CROWNBUTTE
WIND POWER, INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
For the
years ended December 31, 2009 and 2008
On
February 24, 2010, the $20,000 short-term note payable to StarInvest Group, Inc.
was converted to common stock as part of the private placement. A
total of 57,142 shares and 114,284 warrants were issued as a result of the
conversion of the promissory note. After this transaction, the
Company has issued an aggregate of 557,141 shares of common stock and 1,114,282
warrants in the private placement.
On March
29, 2010, the Company issued a total of 400,000 shares of common stock in
exchange for short-term loans from two of the Company’s
stockholders. Terms of the loans are $100,000 payable in 60 days for
150,000 shares of common stock in lieu of interest, and $100,000 payable in 60
days for 250,000 shares of common stock in lieu of
interest. Principal payments on both loans are due June 7,
2010.
F-21
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. Submission Of Matters To A Vote Of Security HoldersPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 8. Financial Statements and Supplemental DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9a(t) Controls and ProceduresItem 9a(t)Item 9B. Other InformationPart IIIItem 10. Directors, Executive Officers, and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions,Item 14. Principal Accountant Fees and ServicesPart IVItem 15. Exhibits and Financial Statement SchedulesNote 1 Organization, Description Of Business and MergerNote 2 Basis Of Presentation, Consolidation and Going ConcernNote 3 Summary Of Significant Accounting PoliciesNote 4 Property, Equipment and Leasehold ImprovementsNote 5 Accrued ExpensesNote 6 Stockholders Equity (deficit)Note 7 Income TaxesNote 8 Related Party TransactionsNote 9 Office and Shop LeaseNote 10 Retirement PlanNote 11 Concentration Of RiskNote 12 Project Development Costs and Interconnect Application DepositsNote 13 Commitments and ContingenciesNote 14 Subsequent Events