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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION B OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2004
OR
|_| TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
Commission File No.0-10238
U.S. ENERGY SYSTEMS, INC.
(Exact name of Registrant as specified its charter)
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Delaware 52-1216347
(State of Incorporation) (I.R.S. Employer Identification Number)
One North Lexington Avenue
White Plains, NY 10601 (914) 993-6443
(Address of principal executive offices) (Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None.
Securities Registered pursuant to Section 12(g) of the Act:
Title of Each Class
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Common Stock, par value $.01 per share
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for a shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes |X| No |_|
Indicate by check mark if disclosure of delinquent filers in response to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statement 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 an accelerated filer (as
defined in Rule 12b-2 of the Act): Yes |X| No |_|
The aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the last sales price of the Common
Stock as of June 30, 2004, which was $1.08 per share, was approximately
$12,842,000 based upon 11,890,711 shares outstanding as of that date.
As of March 14, 2005, the number of outstanding shares of the registrant's
Common Stock was 11,970,061.
Documents Incorporated by Reference: Items 10, 11, 12, 13 and 14 hereof
are incorporated by reference from the Registrant's Proxy Statement to be filed
with the SEC by May 2, 2005.
This Form 10-K contains certain "forward-looking statements" which represent our
expectations or beliefs, including, but not limited to, statements concerning
industry performance and our operations, performance, financial condition,
growth and strategies. For this purpose, any statements contained in this Form
10-K that are not statements of historical fact may be deemed to be
forward-looking statements. Without limiting the generality of the foregoing,
words such as "may," "will," "expect," "believe," "anticipate," "intend,"
"could," "estimate" or "continue" or the negative or other variations thereof or
comparable terminology are intended to identify forward-looking statements.
These statements by their nature involve substantial risks and uncertainties,
certain of which are beyond our control, and actual results may differ
materially depending on a variety of important factors which are noted herein,
including but not limited to the potential impact of competition, changes in
local or regional economic conditions, dependence on management and key
personnel, changes in the capital markets, regulatory issues, operational and
resource issues. This 10-K also contains a discussion of certain factors that
may impact our activities. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations." All denominations expressed
herein are U.S. dollars unless stated otherwise and all dollar amounts are
reported in thousands ("000"), with the exception of share data.
PART I
ITEM 1. DESCRIPTION OF BUSINESS
THE COMPANY
OVERVIEW AND RECENT DEVELOPMENTS
U.S. Energy Systems, Inc. (the "Company" or "We"), based in White Plains, NY, is
a provider of thermal and electrical energy and energy outsourcing. Our energy
services involve the management, development, operation and ownership of
small-to-medium-sized energy facilities typically located in close proximity to
our customers. Our customers include large retail energy consumers, such as
industrial and commercial concerns, and local wholesale energy suppliers, such
as utilities and marketers. The energy generation facilities in our portfolio
use proven technology, such as combined heat-and-power ("CHP") and reciprocating
engines, and clean renewable fuels, such as biogas and biomass fuels.
As of December 31, 2004 the Company, through its 54.26% subsidiary, U.S. Energy
Biogas ("USEB"), owned 23 green energy in the United States with a total of 52MW
of electric generation capacity. In addition, the Company owned a 50% interest
in a partnership that owns and operates a CHP plant that produces 1.2MWs of
electricity and 7MWs of heat and a 50% interest in a dormant cogeneration
facility.
A principal focus of the Company in 2004 was to recapitalize its balance sheet
and raise capital; this should provide us with additional financial flexibility.
Countryside Power Income Fund
During 2004, the Company sponsored the initial public offering ("IPO") of a
Canadian Equity Income Fund, the Countryside Power Income Fund (the "Countryside
Fund") an unincorporated, open-ended limited purpose mutual fund trust formed
under the laws of Ontario, Canada. In April 2004, the Countryside Fund issued
and sold trust units totaling approximately Cdn $149,000 in the IPO and arranged
a credit facility of Cdn $35,000 from a syndicate of Canadian banks ("Credit
Facility"). The Countryside Fund IPO and related credit facility closed on April
8, 2004. The Countryside Fund is listed on the Toronto Stock Exchange under the
stock ticker symbol COU.UN. On closing, the Countryside Fund, using a portion of
proceeds of the IPO and a Cdn $30,000 drawn down from the Credit Facility,
acquired USE Canada Holdings Corp. ("USE Canada Holdings"), the parent of USE
Canada Energy Corp. ("USE Canada") from the Company for approximately $15,200.
USE Canada owned district energy systems located in Charlottetown, Prince Edward
Island and London, Ontario. With the remainder of the IPO proceeds, the
Countryside Fund acquired the existing long-term project debt of USEB, and made
additional debt and royalty investments in USEB. Such debt acquisitions and
additional investments totaled in excess of $86,000. The Countryside Fund and
USEB amended the terms of the acquired debt to reflect, among other things,
additional loan advances.
2
The Countryside Fund transaction provided approximately $12,000 of additional
working capital, growth capital and reserves to USEB and more than $20,000 in
additional cash proceeds to the Company.
Concurrent with their acquisition of the existing loans, the Countryside Fund
acquired a convertible royalty interest in USEB for $6,000. Pursuant to this
royalty interest, the Countryside Fund will have the right to receive, on a
quarterly basis, the sum of 7% of net distributable cash flow (as defined in the
royalty agreement) and 1.8% of USEB's gross revenues (as defined in the royalty
agreement). The total royalty payment to be made to the Countryside Fund is
capped at an amount not to exceed 49% of total distributions made to the
Countryside Fund and the shareholders of USEB combined. All distributions must
be approved by the Board of Directors of USEB. The Countryside Fund has the
option, under the terms of the royalty agreement, to convert its interest into
non-voting common shares of USEB equal to 49% of the outstanding equity. The
Countryside Fund can convert at the earlier of the date on which the loan from
the Countryside Fund is paid in full or April 8, 2024. The amount of the royalty
is accrued on a quarterly basis and paid upon the approval of distributions by
the Board of Directors of USEB.
Additionally, in conjunction with the Countryside Fund IPO, the Company entered
into a development agreement with a subsidiary of the Countryside Fund and
Cinergy Solutions, Inc. ("Cinergy Solutions"), a subsidiary of Cinergy Corp.
(NYSE:CIN) an integrated electric and gas utility company respecting potential
development initiatives. USEB also entered into an improvement agreement with a
subsidiary of the Countryside Fund respecting potential investment by the
Countryside Fund in certain USEB development projects which are not covered by
the development agreement.
Illinois Electrical Generation Partners II
On April 8, 2004, AJG Financial Services, Inc.("AJG") made a cash down payment
of $2,000 and delivered a $14,000 note payable to a subsidiary of USEB to
satisfy AJG's obligation to pay for ownership interests in the Illinois based
generating project entities that AJG had previously acquired in 1999. The note
matures in April 2024, requires scheduled payments of principal and interest,
and bears interest at a rate of 15% per annum. The note is secured by the
ownership interests. Payments on the note are limited to amounts distributed
from the project entities with any excesses to the scheduled payments being
applied as an additional principal payment and any deficits to the scheduled
payments being deferred. The transaction resulted in a pre-tax gain for USEB of
$16,000 which was recognized in June 2004. See Note G of our consolidated
financial statements.
Acquisition of USEB Subordinated Debt
On September 30, 2004, USEB purchased the subordinated note owed by USEB to AJG.
The outstanding principal amount of $5,729 plus outstanding accrued interest was
purchased for $3,000. Funds for the acquisition were provided by equity
contributions to USEB from the USEB shareholders; $1,629 contributed by the
Company and $1,371 contributed by Cinergy. The purchase resulted in a gain of
$2,729 which was recognized in September 2004. The gain represents the principal
amount outstanding on the note at the time of acquisition less the acquisition
price.
THE MARKET
The market for energy outsourcing has continued to grow and emerge during the
last several years. Deregulation of the electricity markets has allowed energy
consumers to select new providers. Increasing competitive pressures have caused
large energy consumers to seek ways to reduce costs, including the significant
costs of energy. Energy outsourcing has emerged as a viable option for energy
consumers to reduce costs and improve reliability.
Employing energy generation facilities in close proximity to the customer often
provides those customers with superior economic and operational benefits that
include lower operating and capital costs, improved reliability and enhanced
management focus. At the same time, outsourcing allows the provider to employ
the use of CHP and local renewable energy sources, which improve operational
efficiency and the environment while enhancing customer value.
3
COMPETITION
The energy generation industry is characterized by intense competition, and we
encounter competition from utilities, industrial companies and other energy
producers in our business.
We compete for development and acquisition opportunities with various companies,
many of which have greater access to resources and capital, as well as with our
potential customers' current in-house alternatives.
DESCRIPTION OF OPERATIONS AND FACILITIES
The Company's principal operations include the following:
U.S. Energy Biogas Corp.
The Company owns 54.26% and Cinergy Energy Solutions owns 45.74% of USEB. USEB
owns and operates 23 biogas projects ("Biogas Projects"). The Biogas Projects
currently have approximately 52MW of electric generation capacity. Nineteen of
the 23 Biogas Projects have contracts with local electric utilities for the sale
of electrical output. The contracts have a weighted average remaining life of
approximately 12 years, based upon the revenue generated from the project
operations. The Brookhaven project leases electric generation equipment to a
third party, which in turn has a contract to sell the output to an electric
utility. The remaining three Biogas Projects sell landfill gas for use as boiler
fuel under long-term contracts. All of the generation projects are qualifying
facilities ("QF") under the Public Utility Regulatory Act of 1978 ("PURPA").
The following is a summary of the Biogas Projects and their key characteristics.
Gas Rights
Project PPA/Retail Agreement Site Lease Landfill
Project ST Output MW Rate Expiry Customer Expiry Expiry Status(1)
Countryside IL Electricity 8.0 2011 Commonwealth Edison 2051 2051 Open
Dolton IL Electricity 5.0 2008 Commonwealth Edison 2016(2) 2016(2)(3) Open
Dixon Lee IL Electricity 4.0 2009 Commonwealth Edison 2017(2) 2017(2) Open
Morris IL Electricity 4.0 2011 Commonwealth Edison 2018(4) 2018(4) Open
Roxanna IL Electricity 4.0 2009 Illinois Power N/A 2018(2) Open
Upper Rock IL Electricity 4.0 2010 MidAmerican Energy 2017(2) 2029 Open
SPSA I VA Electricity 3.3 2014 Virginia Power 2011(5) 2011(5) Open
122nd Street IL Electricity 3.0 2008 Commonwealth Edison 2016(2) 2016(2) Closed
Brickyard IL Electricity 3.0 2009 Illinois Power 2017(2) 2017(2) Open
Hamms NJ Electricity 1.2 2010 GPU/First Energy 2006(6) 2006(6) Closed
2016(2) Open
Manchester NH Electricity 1.2 Ongoing(7) New Hampshire Public Service 2004(8) 2004(8) Closed
Oceanside NY Electricity 1.2 2006 Long Island Power 2004(6) 2004(6) Closed
Streator IL Electricity 1.0 2009 Commonwealth Edison 2017(2) 2017(2) Open
Willow Ranch IL Electricity 1.0 2007 Commonwealth Edison 2016(2) 2016(2) Closed
Amity PA Electricity 1.0 2007 Penn Power & Light 2006(6) 2006(6) Closed
Barre MA Electricity 1.0 2006 Dominion Energy 2015 2015 Closed
Burlington VT Electricity 0.7 2006 Burlington Electric Dept. 2006(2) 2006(2) Closed
Onondaga NY Electricity 0.6 2007 Niagara Mohawk 1999(6) 1999(6) Closed
Smithtown NY Electricity 0.8 2010 Long Island Power 2000(6) 2000(6) Closed
Cape May NJ Boiler Fuel N/A 2009(9) State of New Jersey 2011 2011 Open
SPSA II VA Boiler Fuel N/A 2011 CIBA Specialty Chemical 2011 N/A(10) Open
Tucson AZ Boiler Fuel N/A 2011 Tucson Electric Power 2017 N/A(10) Open
Brookhaven NY Electricity 4.0 2007 Wehran Energy Corp. N/A(11) N/A(11) Closed
4
(1) An open landfill is one that continues to accept waste. A closed
landfill is one that does not accept additional waste. Closed
landfills continue to generate landfill gas for a period of up to 25
years after closure, depending upon the total amount of waste in the
landfill.
(2) Subject to two five-year extension terms at USEB's option.
(3) A portion of the site is owned and a portion is leased.
(4) Subject to three five-year extension terms at USEB's option.
(5) May be extended for one or more five year terms by mutual agreement.
(6) The agreement automatically renews so long as landfill gas is
produced by the landfill in commercially reasonable quantities.
Commercially reasonable quantities is defined as an amount
sufficient to allow for USEB to pay all costs of the project plus
receive a reasonable profit.
(7) Continues until terminated by USEB.
(8) Agreement may be extended for up to 10 years upon mutual consent.
(9) Facilities operations agreement under which USEB operates the gas
collection system and transmission pipeline to the off-taker and in
consideration receives a fee.
(10) These Transcos have no facilities located at the site. A
transmission pipeline runs from the Gasco directly to the end users.
(11) The Brookhaven project is structured as an equipment lease under
which a subsidiary of USEB owns the power generating equipment and
receives a fee to operate such equipment.
USEB also receives payments under four notes pertaining to USEB's sale of its
limited partnership interests in several Gasco entities. Payments of principal
and interest on three contingent installment notes are made quarterly based upon
the amount of landfill gas sold and the value of the Section 29 tax credits
generated by the sale. Payments of principal and interest on the fixed
installment note are made quarterly based upon a mortgage style amortization.
These payments are scheduled to end in 2007. See Note G of our consolidated
financial statements.
Thirteen of the 23 Biogas Projects are located at landfill sites that continue
to accept waste, and, as such, biogas production is expected to increase until
shortly after the landfill sites close. As a result, we expect that increases in
biogas production will more than offset declines at those Biogas Projects
located at closed landfill sites, resulting in a net expansion of the Biogas
Projects' current electricity generation capacity.
5
Commercial Structure of the Biogas Projects
The Biogas Projects may incorporate up to three separate legal entities as
illustrated in the following diagram and described below:
Typical Biogas Project Commercial Structure
[GRAPHIC OMITTED]
Genco
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Generation
of electricity
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Biogas Electricity
Gasco
- -------------- ---------------------
Collection Utility or Industrial
of biogas Purchasers
- -------------- ---------------------
Biogas Biogas
Transco
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Transportation
of biogas
--------------
Gasco
Gascos are the legal entities that typically own the biogas extraction rights
and collection systems and collect and sell the biogas to an electric generating
facility ("Genco") and/or a gas transmission facility ("Transco"), as the case
may be, under long-term, fixed-rate contracts. Gascos are typically structured
as limited partnerships whereby the beneficiaries of the Section 29 tax credits
own a 99% limited partnership interest in the Gasco and USEB, directly or
through certain of its subsidiaries, owns a 1% general partnership interest or
less in the Gasco. The limited partnership interests are held by investment
grade third parties. In the cases of the Roxanna and Brookhaven projects, USEB
does not own an interest in the relevant Gascos.
The price for the landfill gas sold by the Gascos to the Gencos and/or Transcos
is established in the respective gas purchase agreements. For 2004, the average
price paid for landfill gas was $0.46/mmbtu. The Gencos typically incur various
expenses and provide operating and maintenance services for the Gascos. The
Gascos reimburse the Gencos for these items per the terms of the landfill gas
purchase agreement. The total revenues received by the Gascos for the sale of
biogas is approximately equal to the total reimbursement to the Gencos.
USEB is negotiating to obtain the right to purchase the limited partnership
interests in the Gascos from their current owners upon expiration of the Section
29 tax credits on December 31, 2007. In the event USEB does not acquire the
limited partnership interests, the existing project agreements generally provide
that: (i) the Gencos shall retain the right to purchase gas from the Gascos
under long-term gas purchase contracts at prices equal to or lower than the
prices currently in effect; and (ii) the Gencos shall continue to perform
operation and maintenance services for the Gascos under long-term agreements and
the compensation received by the Gencos should not be affected by the expiration
of the tax credits.
6
Genco
Gencos are the legal entities that typically own the power generating equipment,
purchase the biogas from a Gasco and sell the electricity it generates to an
electric utility or industrial user under long-term contracts. The Biogas
Projects include 19 Gencos that are wholly-owned subsidiaries of USEB, except
for the Illinois-based projects, which are owned 50% by USEB and 50% by AJG.
Gencos typically lease a portion of a landfill site from an independent third
party landfill owner. One Genco owns the land used as the site for the
generating plant.
Transco
Transcos are the legal entities that typically own the gas transportation
equipment and purchase biogas from a Gasco to transport and sell to a third
party as boiler fuel under long-term contracts. The Biogas Projects include
three Transcos which are all wholly-owned subsidiaries of USEB.
Pricing Structure
Illinois QSWEF Pricing Structure Under the Illinois Retail Rate Program
USEB has 10 operating projects in Illinois which are receiving a subsidy for
each kilowatt hour of electricity sold to the local utility under the Illinois
Retail Rate Program. In accordance with the Illinois Retail Rate Program, the
utility has contracted, for a ten year period, with each project to purchase
electricity for an amount that exceeds the utility's Avoided Cost (what it would
otherwise pay for the generation of electricity). The excess paid above avoided
cost is the subsidy. The utility then receives a tax credit from the the State
of Illinois ("Illinois") equal to the amount of that excess. Each project is
obligated to begin to repay the subsidy to Illinois after the project that
received the subsidy has recouped its capital investment and retired all debt
associated with the financing and construction of the project but, in any case,
no later than 10 years from the date the project commenced commercial operation.
All subsidy liabilities must be fully repaid to Illinois (without interest) by
the end of the actual useful life of the project but no later then 20 years from
the date of the commencement of project's commercial operations.
This subsidy is accounted for GAAP purposes in a manner similar to an original
issue discount whereby the amount to be repaid in the future is discounted to
its net present value and the discount is amortized (as interest expense) over
the 10-year period until repayment begins. The amount of power generation
revenue recognized each period is equal to the Avoided Cost rate plus the
difference between the subsidy received by the project and the net present value
of the subsidy. This unamortized discount and the liability are shown net on the
consolidated balance sheet as Illinois Subsidy Liability.
The following is a breakdown of a typical Illinois-based Biogas Project's rate
components for illustrative purposes:
Avoided Cost 3.1 cents/kwh
Add: Rate Subsidy (Excess above Avoided Costs) 3.9 cents/kwh
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Gross Contract Rate (Retail Rate) 7.0 cents/kwh
Less: Illinois Subsidy Reserve Account Deposit 1.9 cents/kwh
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Net Effective Rate 5.1 cents/kwh
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USEB is required pursuant to its financing arrangement with the Countryside Fund
to deposit funds into the Illinois Subsidy Reserve Accounts (the "Illinois
Accounts") for repayment of the Illinois subsidy liability. The Illinois
Accounts are classified as restricted cash. The amount deposited into the
Illinois Accounts is based upon the amount of subsidy received and contemplates
an annual return sufficient to fund the current period subsidy liability
repayment as it becomes due. Regular deposits combined with actual and expected
returns on those deposits may not be sufficient to fully repay the respective
liabilities as they become due. Should the amounts in the Illinois Accounts be
insufficient to fully repay the obligations, any shortfall would have to be
funded from the project's operations or assets during the repayment period.
7
The funds held in the Illinois Accounts are currently invested in equities and
fixed income securities. These investments are being managed by a third-party
professional money manager with the investment allocations being approved by the
management of the Company and USEB. The amount held in the Illinois Accounts as
of December 31, 2004 was $23,438. The amount of the incentive liability owed to
the State as of December 31, 2004 was $49,028. It is anticipated that repayments
of the subsidy will begin in 2008 and continue through 2021.
Under the terms of the Illinois Retail Rate Program, estimated rates are paid
for production sold to the utility with that rate being trued up annually, on
the anniversary of the commercial operations date, to the actual rates paid for
electricity by the local municipality. After the actual rate is determined,
sales for the preceding calendar year, retroactive to the last anniversary date,
are adjusted based upon the actual rate. If the actual rate is greater than the
estimated rate, additional sales proceeds are paid to the project. If the actual
rate is less than the estimated rate, then prior sales proceeds received, equal
to the excess amounts paid, must be refunded to the utility. This actual rate
then becomes the estimated rate for the subsequent year.
During 2004, USEB experienced an uncharacteristic rate reduction at three
Illinois projects, the off-taker of which is Commonwealth Edison. Retail rates
for these projects decreased by amounts ranging from 26% to 40% per kwh
resulting in a decrease in GAAP revenues of $867 for 2004.
USEB is seeking an explanation from Commonwealth Edison for the reasons behind
these rate changes. USEB has a total of 10 projects in Illinois, representing
64% of its revenues. USEB cannot predict whether any other major decreases in
revenues from the Illinois projects are likely. Commonwealth Edison accounted
for approximately 42% of the Company's consolidated revenues in fiscal year 2004
and 34% in fiscal year 2003.
From time to time during the past few years and in 2004 and 2005, the Governor
and/or Lieutenant Governor of Illinois and members of the Illinois legislature
have proposed changes to or the elimination of the Illinois Retail Rate Program
and have introduced legislation to that effect. While legislation has not been
adopted, the adoption of legislation or the implementation of rules that would
reduce or eliminate the benefits received by USEB under this program would have
a material adverse effect on the Company.
Although the Rate Incentive Program for each of the Illinois-based Biogas
Projects terminates 10 years after the commencement of commercial operation, the
local electric utility is obligated to continue to purchase the electrical
output from such Biogas Projects at the utility's Avoided Cost for so long as
the Biogas Project qualifies as a QF and satisfies Illinois laws. This
obligation arises under requirements of the Public Utility Regulatory Policies
Act of 1978 ("PURPA"), and Part 430, Purchase and Sale of Electrical Energy from
Cogeneration and Small Power Production Facilities of the Illinois
Administrative Code. In addition, we anticipate that at the expiration of such
10-year period, each Biogas Project will seek to sell its generated electricity
in the market for electricity generated from renewable sources that exists in
those states that have implemented renewable portfolio standards or that have
restructured their laws to create competitive electricity markets ("Green Power
Market") at green power rates, which we currently project to exceed Avoided
Cost.
See Note E to the consolidated financial statements.
Green Power Market and Pricing
After expiration of the 10-year period over which the Illinois-based Biogas
Projects participate in the Illinois Retail Rate Program, and after expiration
of the power purchase agreements ("PPAs") for the non-Illinois-based Biogas
Projects, we anticipate that USEB will sell the power generated by the Biogas
Projects into the Green Power Market, if economically attractive. The Green
Power Market, as we define it, includes the sale of Renewable Energy Credits
("RECs") which can be sold separately from the energy.
The use of power derived from alternative sources has been mandated in several
states in the United States, in addition to being discussed at a federal level.
Such states, including Illinois, have incorporated, or are in the process of
incorporating or considering the incorporation of, renewable portfolio
standards. These standards require that a certain percentage of power generated
be derived from a renewable fuel source. The mandate for such standards stems
from the objective of reducing the use of fossil fuels, reducing the reliance on
foreign energy sources and increasing the production of clean energy.
8
In those jurisdictions where renewable portfolio standards exist, Green Power
Markets may develop. Management believes the rates for green power will increase
to a level that will result in green power generation reaching the level set by
renewable portfolio standards. Such levels typically involve a price premium on
electricity generated reflecting the total cost (including capital) of producing
such power. In addition, without state-mandated renewable portfolio standards,
it has been demonstrated that there is a segment of the general public that has
a preference for electricity generated from green power, and is willing to pay a
premium for such power.
During the twelve month period ended December 31, 2004, USEB entered into
short-term contracts for three projects for the sale of the RECs produced by the
generation of electricity from landfill gas. One REC is produced when the
project sells one megawatt of qualified renewable energy to the utility grid.
The contracts do not require USEB to deliver any specified quantities of RECs.
Gross proceeds from the sale of the RECs during 2004 for these projects were an
aggregate of $403. A portion of gross proceeds from the sale of the RECs for one
project is paid to the local utility per an agreement with the utility. Amounts
paid to the utility per the agreement are recorded as operating expenses. The
REC revenue is in addition to the energy value which is sold under a separate
contract.
We believe that the Biogas Projects' production of power will remain competitive
with energy generated from other renewable sources after the Illinois Retail
Rate Program and current PPAs expire. A number of factors are expected to
contribute to the Biogas Projects' competitive position, including their: (i)
comparatively low variable fuel cost, (ii) proximity to customers thereby
reducing transmission costs, and (iii) high availability factors.
GHG Emission Credit Market
USEB has, in the past, sold green house gas ("GHG") emission credits generated
by the destruction of methane contained in landfill gas. USEB will continue to
pursue these transactions, if available in the market.
Section 29 Tax Credits
In 2001, an indirect subsidiary of Cinergy purchased USEB's ownership interests
in the Countryside, Morris and Brown County Gascos. Consideration for the
purchase was in the form of: (i) an up-front down payment; (ii) a fixed note
with specified principal and interest payments; and (iii) a contingent note
whose payments are based upon an amount of MMBtus sold by the Gascos to the
Gencos. USEB has agreed to indemnify the indirect subsidiary of Cinergy for
certain losses suffered in the event that certain tax-related representations
and warranties made by USEB are inaccurate. Payments on the contingent note are
calculated utilizing the number of mmbtus sold multiplied by a specified rate.
The total payment is allocated first to accrued but unpaid interest with any
remaining payment being applied as a principal payment. A portion of the
principal payment is recorded as revenues for financial statement purposes. USEB
will continue to receive revenues from this sale through December 2007.
In 1999, AJG purchased the ownership interests in other Biogas Projects' Gascos.
Consideration from AJG to USEB was in the form of: (i) an up-front down payment;
and (ii) a contingent note whose payment is based upon the amount of millions of
British thermal units ("MMBtus") sold by the Gascos to the Gencos. AJG
subsequently sold certain of such ownership interests to a subsidiary of
American International Group. USEB has agreed to indemnify AJG for certain
losses suffered in the event that certain tax-related representations and
warranties made by USEB are inaccurate. Payments on the contingent note are
calculated utilizing the number of mmbtus sold multiplied by a specified rate.
The total payment is allocated first to accrued but unpaid interest with any
remaining payment being applied as a principal payment. Principal payments made
under the AJG note do not generate any revenues for financial statement
purposes. USEB will continue to receive revenues from this sale through December
2007.
The ability of a project to receive Section 29 tax credits depends on the
placed-in-service date of the facility. Section 29 tax credits for the Gascos at
15 Biogas Projects are currently available annually until December 31, 2007,
based on an in-service date on or before June 30, 1998. These projects include
Brickyard, Cape May, Countryside, Dixon Lee, Dolton, Hamms, Manchester, Morris,
122nd Street, SPSA (I and II), Streator, Upper Rock, Tucson and Willow Ranch.
Biogas Projects with in-service dates prior to 1993 qualified for tax credits
only through 2002. These projects include Amity, Burlington, Oceanside and
Onondaga. USEB also owns two developmental sites where the Gascos generate tax
credits, and receives revenues from four other Gascos where the sites themselves
are owned and operated by third parties. USEB has two generating facilities,
Brookhaven and Roxanna, whose Gascos were not owned by USEB and therefore
generate no revenue for USEB from Section 29 tax credits.
9
Operations
Approximately 68% of the engine generating capacity of the Biogas Projects is
operated and maintained by third-party operators under fixed price per unit of
production contracts. As the third-party operators are responsible for the
relevant projects' day-to-day operations, USEB has been able to reduce its
staffing levels and insurance premiums.
USEB has operating agreements expiring in 2013 with GE/Jenbacher for the
operation and maintenance of the Brickyard, Dixon Lee, Dolton, 122nd Street,
Roxanna, Streator, Upper Rock and Willow Ranch. Under the terms of these
agreements, GE/Jenbacher is responsible for all expenses related to the
operation of the equipment including scheduled major and minor overhauls, the
supply of fluids and other spare parts and the replacement of failed components,
including failed engine blocks. Compensation for the services is at a flat-fixed
rate per kwh produced, adjusted based upon the Consumer Price Index and the
Producers Price Index.
USEB has operating and maintenance agreements with RUN Energy for the operation
and maintenance of the Countryside and Morris projects. Under the terms of these
agreements, RUN Energy is responsible for all expenses related to the operation
of the equipment for these projects including scheduled major and minor
overhauls, the supply of fluids and other spare parts and the replacement of
failed components other than failed engine blocks. The financial risk for failed
engine blocks remains with Biogas. These agreements are renewed on a month to
month basis.
The operation and maintenance functions for the remaining Biogas Projects,
including Amity, Barre, Brookhaven, Burlington, Cape May, Hamms, Manchester,
Oceanside, Onondaga, SPSA I and II, and Tucson are performed by USEB staff. USEB
has 23 employees on staff including all management personnel. USEB personnel
associated with these projects are long-term employees and most of the employees
have been involved with these projects since their inception.
USE Canada Energy Corp. ("USE Canada")
On April 8, 2004, we sold our equity interest in USE Canada Holdings, the parent
of USE Canada, to Countryside Fund. The sale resulted in an after tax gain of
$4,561.
Effective December 31, 2003 USE Canada became a discontinued operation due to
its anticipated sale to the Countryside Fund.
U.S. Energy Geothermal, LLC
Through June 30, 2003, we owned a 95% membership interest in Geothermal, LLC
which owns two geothermal power plants in Steamboat Hills, Nevada: Steamboat 1
and 1A.
SEFL
During 2004, we wrote off our entire investment $7,100, after giving effect to
the repayment to us of $1,100 of loan to SEFL in Scandinavian Energy Finance
Limited, against the $7,100 remaining reserve therefor. We also terminated the
management agreement pursuant to which the Company was entitled to an annual fee
of approximately $660. See Note B to the consolidated financial statements.
OTHER OPERATIONS AND INTERESTS
Plymouth Envirosystems, Inc.: Our wholly owned subsidiary, Plymouth
Envirosystems, Inc., owns a 50% interest in Plymouth Cogeneration Limited
Partnership ("Plymouth Facility") which owns and operates a CHP plant producing
1.2 MW of electricity and 7 MW of heat at Plymouth State College, in Plymouth,
New Hampshire. The Plymouth Facility provides, under a long-term contract, 100%
of the electrical and heating requirements for the campus, which is a part of
the University of New Hampshire system.
10
The day-to-day operations of the Plymouth Facility are managed by one of our
partners, which is an affiliate of Equitable Resources, Inc. Management
decisions are made by a committee composed of representatives of the three
partners in this project.
EMPLOYEES
At December 31, 2004, we employed 35 employees in our various subsidiaries and
locations. Not included are personnel at certain power plants provided under
contract with the plant operators.
GOVERNMENT REGULATION
None of the Company's energy projects in the United States are currently subject
to federal or state utility rate regulation. Under current Federal law, the
Company is not and will not be subject to regulation as a holding company under
the Public Utility Holding Company Act ("PUCHA") of 1935, as long as each power
plant in which it has an interest is a qualifying facility (a "QF"), as such
term is defined under PURPA, or meets the criteria for another exemption. A QF
is a distinct type of energy producer that falls into one or both of two primary
classes. The first class of QFs includes energy producers that generate power
using specific energy sources such as wind, solar, geothermal, hydro, biomass or
waste fuels. The second class of QFs includes cogeneration facilities. For so
long as a facility otherwise eligible for QF status is not more than 50% owned
by a person primarily engaged in the generation or sale of electric power (other
than electric power solely from cogeneration facilities or small power
production facilities), such facility will be exempt from regulation under
PUHCA. Similarly, an entity directly or indirectly owning a QF is not subject to
PUHCA by virtue of such ownership. The Federal Energy Regulatory Commission's
("FERC's") implementing regulations explain that a cogeneration or small power
production facility shall be considered to be owned by a person primarily
engaged in the generation or sale of electric power if more than 50% of the
equity interest in the facility is held by an electric utility or utilities, or
by an electric utility holding company, or companies, or any combination
thereof. Each of our United States energy projects is a QF. The Biogas projects
will be considered QF's if they meet PURPA's ownership requirements and other
standards. In those states where the sale of electricity directly to an
individual or a commercial customer is regulated as retail, none of our energy
projects is currently subject to state utility law regulation.
Separate from federal and state utility rate regulation, the construction and
operation of power generation facilities require numerous permits, approvals and
certificates from appropriate federal, state and local governmental agencies, as
well as compliance with environmental protection legislation and other
regulations. We believe that we are in substantial compliance with all
applicable rules and regulations and that the projects in which we are involved
have the requisite approvals for existing operations and are operated in
accordance with applicable laws.
ITEM 2. DESCRIPTION OF PROPERTY
Property owned by Biogas projects includes all buildings and improvements,
electricity generating equipment, switchgears, controls and associated ancillary
equipment. Biogas has no ownership interest in the landfills, nor does it have
any contractual responsibility for the operation of the landfills. Biogas
projects (Gencos, Transcos and Gascos) occupy land on the landfills pursuant to
leases. One Biogas Project owns the land used as the site for the generation
plant. Substantially all of Biogas project assets are collateral for the USEB
loan from the Countryside Fund. Biogas rents office space in Avon, Connecticut
and Bohemia, New York.
Plymouth Cogeneration, a Delaware partnership, of which we own 50%, owns the
Plymouth Facility. Plymouth Cogeneration owns plant and equipment associated
with the cogeneration project including the engines, generators, boilers,
switchgear, controls and piping.
11
The Lehi Facility is owned by LIPA, a Utah limited liability company, of which
we own 50%. The property is in Lehi, Utah, and includes land, buildings and
permits. The Company has no asset value recorded on its books for this
investment.
Our headquarters are located in a commercial office building in White Plains,
New York.
All our properties are in satisfactory condition and we believe that they are
adequately covered by insurance.
ITEM 3. LEGAL PROCEEDINGS
Foreclosure of Countryside Site Lease
In 2004, a foreclosure proceeding entitled CIB Bank v. Miss Mimi Corporation,
Countryside Genco, LLC et al was commenced in the circuit court for the 19th
Judicial District, Lake County, Illinois. Countryside Genco, LLC is a USEB
project entity and leases, pursuant to a long-term site lease agreement, a
portion of the land which the lender is seeking to foreclose. Countryside has a
consent and recognition agreement with the lender that provides that if the
lender forecloses on the underlying land and Countryside is not in default of
the site lease agreement, the lender will not cause the lease to be terminated
and Countryside will be recognized by the lender as a tenant. Countryside is not
in default of the site lease agreement.
We are engaged from time to time in legal proceedings, none of which are
expected to materially affect our business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, AND RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASE OF EQUITY SECURITIES
PRICE RANGE OF COMMON STOCK
Our Common Stock trades on the NASDAQ Small Cap Market under the symbol USEY.
The table below sets forth, for the periods indicated, the high and low sales
prices for the Common Stock as reported by the NASDAQ Small Cap Market.
Sales Price
-------------------
High Low
-------- -------
Year ended December 31, 2003:
First Quarter........................ $ 1.28 $ .51
Second Quarter....................... 1.52 .60
Third Quarter........................ 2.30 1.01
Fourth Quarter....................... 1.41 .90
Year ended December 31, 2004
First Quarter........................ $ 1.70 $ 1.01
Second Quarter....................... 1.85 1.03
Third Quarter........................ 1.20 0.70
Fourth Quarter....................... 1.04 0.65
HOLDERS
As of December 31, 2004 there were 328 holders of record of our Common Stock. We
estimate that there are over 500 beneficial holders of our common stock.
12
DIVIDENDS
We have not paid cash dividends on our common stock and currently do not
anticipate paying cash dividends on our common stock in the foreseeable future.
Our ability to pay cash dividends on our common stock may be limited by our
outstanding shares of Series B, Series C and Series D Preferred Stock.
Generally, these shares of preferred stock provide that no dividends may be paid
on our common stock unless dividends have been set aside for the outstanding
preferred stock.
EQUITY COMPENSATION PLAN INFORMATION AS OF DECEMBER 31, 2004
Weighted-average exercise Number of securities
Number of securities to price of outstanding remaining available for
be issued upon exercise options warrants and future issuance under
of outstanding options, rights under compensation equity compensation
Plan Category warrants and rights(1) plans(1) plans (2)
------------- ---------------------- -------- ---------
Equity compensation plans approved
by security holders 5,863,925 $ 3.81/share 3, 154,434
Equity compensation plans not
approved by security holders 275,000 $ 4.23/share 0
-------------------------------------------------------------------------------
Total 6,138,925 (1) $ 3.83/share 3,154,434
(1) Does not include 706,641 restricted stock units as of December 31,
2004. Restricted stock units are not used in the calculation of the
weighted average exercise price.
(2) Represents the number of securities available for issuance after
giving effect to the restricted stock units outstanding at December
31, 2004.
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in thousands, except share data)
=========================================================================================================
Year ended
Jan. 31,
2004 2003 2002 2001 2000
=========================================================================================================
Total assets $ 172,529 $ 172,041 $ 219,008 $ 187,610 $ 14,354
Long-Term Debt 80,521 70,084 114,277 57,005 384
Total Stockholder's Equity 40,932 39,085 38,754 45,865 10,491
Revenues 20,108 24,999 28,620 22,760 4,195
Income (Loss) from Operations (4,029) 5,035 (5,710) 4,772 (609)
Income (Loss) Applicable to Common Stock (184) 1,009 (16,979) 3,378 (743)
Basic Earnings per Common Share $ (.02) $ 0.08 $ (1.39) $ 0.35 $ (1.05)
Diluted Earnings per Common Share $ -- $ 0.11 $ -- $ 0.27 $ --
In reviewing this table the following should be taken into consideration:
1) USE Canada was acquired in June 2001, became a discontinued
operation on December 31, 2003 and was sold to the Countryside Fund
on April 8, 2004. See Note B to the consolidated financial
statements.
2) USEB was acquired in May 2001. See Note B to the consolidated
financial statements.
3) SEFL was included in our consolidated operating results from March
2002 through September 2003, at which time our ownership interests
were reduced to less than 50% and was accounted for by the equity
method through 2003. In 2004, the entire net investment ($7,089) was
written off. See Note B to the consolidated financial stateements.
13
4) US Energy Geothermal LLC was sold in June 2003. See Note B to the
consolidated financial statements.
5) USEB acquired its subordinated debt owed to AJG Financial Services
on September 30, 2004 which resulted in a $2,729 gain in 2004. See
Note K to the consolidated financial statements.
6) AJG Financial Services, Inc. satisfied its obligation to pay for the
remaining 50% ownership in certain Illinois gencos which resulted in
a $16,000 pre-tax gain in 2004. See Note G to the consolidated
financial statements.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS
OF OPERATIONS
In March 2005, a special committee of independent directors was organized to
evaluate a potential combination with a private company in a related line of
business. No assurance can be given that such transaction will be completed.
During 2004, our $4,029 loss from operations was principally the result of the
$7,089 write off of the Company's investment in SEFL Net income of $644 reflects
$4,561 in an after tax gain resulting from the sale of USE Canada and $5,384
generated from the payment for ownership interest in Illinois based generating
project entities previously sold to AJG.
RESULTS OF OPERATIONS
Comparison of 2004, 2003 and 2002
A summary of the components of operating income follows:
(Dollars in thousands)
================================================================================
2004 2003 2002
================================================================================
Revenues $ 20,108 $ 24,999 $ 28,620
Operating Expenses 9,646 10,964 14,842
General and Administritive
Expenses 3,241 5,918 9,958
Depreciation and Amortization 4,279 3,874 5,906
Investment Write off 7,089 -- 3,684
(Gain) From Joint Ventures (118) (792) (60)
================================================================================
Income/(Loss) from Operations $ (4,029) $ 5,035 $ (5,710)
================================================================================
In comparing fiscal information it should be noted that:
1) The Company sold its investment in USE Geothermal on June 30, 2003
and was deemed a discontinued operation in 2003.
2) The Company's investment in SEFL was reduced to 32% in the 4th
quarter of 2003. The Company's interest was sold in 2004. See Note B
to the consolidated financial statements.
3) Effective December 31, 2003, USE Canada was deemed to be a
discontinued operation in connection with its anticipated sale to
the Countryside Fund. The sale was completed on April 8, 2004. See
Note B to the consolidated financial statements.
4) USEB acquired its subordinated debt owed to AJG Financial Services
on September 30, 2004 which resulted in a $2,759 pre-tax gain in
2004.
14
5) AJG Financial Services, Inc. satisfied its obligation to pay for the
remaining 50% ownership in certain Illinois gencos which resulted in
a $16,000 pre-tax gain in the second quarter of 2004.
6) The USEB Readville cogeneration project was closed effective October
1, 2003 due to the termination of the contract with the energy user.
Investments in joint ventures are accounted for under the equity method of
accounting, and accordingly, revenues and expenses of these investments are not
included in our consolidated statements of operations.
REVENUES
The Company's 2004 revenues were $20,108 compared with $24,999 for 2003 and
$28,620 for 2002. The decrease of $4,891, or 20%, from 2004 to 2003 was
primarily due to: (a) the closing of a USEB project in 2003 due to a contract
termination ($2,933), (b) a decrease in USEB revenue due to changes in net rates
received for energy sales ($1,238) offset partially by $949 in increased volume
of energy sales, (c) the elimination of other revenues related to USEB
operations that were offset by operating expenses ($1,009) and (d) the
elimination of SEFL management fees ($550).
The $3,621 decrease in revenues in 2003 from to 2002 was due primarily to the
deconsolidation of SEFL in the financial statements for 2003. In 2002, revenues
from SEFL were $3,453.
EXPENSES
Operating Expenses: The Company's 2004 operating expenses were $9,646 compared
with $10,964 in 2003 and $14,842 in 2002. The $1,318, or 12%, decrease in 2004
was the result of the elimination of USEB operating expenses that were offset by
a decrease in USEB revenues as indicated above ($1,000), a decrease in USEB
project operating expenses due to the termination of a project contract, ($174)
and a general reduction in USEB operating expenses, ($144). Operating expenses
as a percentage of revenues increased from 44% in 2003 to 48% in 2004 primarily
due to the inclusion, in 2003, of a $1,900 fee associated with the termination
of a contract for a USEB project.
The $3,878, or 26%, decrease in operating expenses in 2003 when compared to 2002
was primarily due to the deconsolidation of SEFL and recording of USE Canada and
Geothermal as discontinued operations. Operating expenses as a percentage of
revenues decreased from 52% in 2002 to 44% in 2003 due to the reduction in the
number of USEB full time employees resulting from the outsourcing of project
operating and maintenance expenses and the implementation of cost reduction
strategies.
General and Administrative Expenses: General and administrative expenses for
2004 were $3,241, a decrease of $2,677, or 45%, compared with the 2003. Expenses
for 2003 decreased by $4,040, or 41% when compared with 2002. General and
administrative expenses as a percentage of total revenues were 16%, 24% and 35%
for 2004, 2003 and 2002 respectively. The following table summarizes general and
administrative expenses for 2004, 2003 and 2002.
===========================================================================================
2004 2003 2002
- -------------------------------------------------------------------------------------------
General and Administrative Expenses
Salaries, Other Compensation and Consulting $ 5,659 $ 3,336 $ 4,964
Legal and Professional 712 722 660
Insurance 470 623 789
Corporate Expenses 412 572 371
Other 827 665 3,174
Countryside Fund Expense Reimbursement (4,839) -- --
===========================================================================================
Total $ 3,241 $ 5,918 $ 9,958
===========================================================================================
15
For 2004, general and administrative expenses included the reimbursement from
the Countryside Fund of $4,839 for expenses incurred by the Company related to
the Countryside Fund transaction. This reimbursement was utilized in part to
offset the increase in additional compensation awarded to employees generally
pursuant to existing employment arrangements and bonus plans.
The $4,040, or 41%, decrease in general and administrative expense in 2003 when
compared with 2002 was due primarily to the inclusion in 2002 of previously
deferred compensation of $1,500, the payment of severence and consulting fees
related to the consolidation of the accounting and administrative functions of
the Company of $1,100, an increase in the reserve for uncollectible accounts
receivable of $1,000, the expensing of $760 in development costs previously
capitalized and the inclusion of $450 applicable to US Enviro Systems, which was
sold in 2002, offset in part by the 2003 reserve for SEFL management fees of
$992.
Depreciation and Amortization: Depreciation and amortization expenses were
$4,279 in 2004 compared with $3,874 for 2003, an increase of $405 or 10%. The
increase was due to an increase in the amoritzation of debt issuance costs
associated with the the Countryside Fund transaction. Amortization costs for
subsequent years will be approximately $200 higher than those reported in 2004
due to the fact that the amount recorded in 2004 does not reflect full year's
amortization of debt issuance costs associated with the Countryside Fund
transaction which closed on April 8, 2004.
The $2,032, or 34%, decrease in depreciation and amortization expenses in 2003
was primarily due to the sale of U.S. Enviro Systems in 2002.
Interest and Dividend Income: Interest and dividend income for 2004 was $2,828,
an increase of $1,693, or 149%, compared with $1,135 for 2003. The increase in
interest income is primarily from the interest earned on the $14,000 purchase
note (bearing a 15% interest rate) delivered by AJG Financial Services in
payment of the balance of the purchase price owed in connection with the
acquisition of ownership interests in certain of the Illinois based generating
project entities that it acquired from USEB. See Note G to the consolidatd
financial statements
The $597, or 34%, decrease in interest income in 2003 when compared to 2002 was
due to a reduction in the amount of interest related to the installment sale of
partnership interests. See Note G to the consolidated financial statements. The
decrease is the result of the reduction in payments on the notes due to the
expiration of the production of section 29 tax credits for a number of the USEB
projects. Interest income for the installment sales was $447 in 2003 compared
with $754 in 2002. The balance of the reduction was reflective of lower market
rates resulting in lower interest earnings on investments.
Interest Expense: Interest expense for 2004 was $9,443, an increase of $2,665,
or 39%, when compared to the $6,779 in interest expense reported for 2003. This
increase is the result of the increase in total amount of non-related party debt
outstanding as of December 31, 2004 to $80,521 from the December 31, 2003 amount
of $58,755 and the increase in the interest rate on the debt to 11% from an
average interest rate of 8.7% as of December 31, 2003. The changes in the total
outstanding debt and the interest rate resulted from the Countryside Fund
transaction that closed on April 8, 2004. Interest expense for years subsequent
to 2004 will be higher than in 2004 due to the fact that the amount recorded in
2004 does not reflect the full year of increased interest rates and increased
debt outstanding resulting from the Countryside Fund transaction. See Note K to
the consolidated financial statements.
The $987, or 13%, decrease in interest expense in 2003 when compared with 2002
was primarily the result of lower interest rates on variable rate debt and the
continued amortization of principal on the outstanding debt.
16
Unrealized Gain/(Loss): The unrealized gain for 2004 is comprised of $1,246 of
mark to market gains in open trading positions from the investment of the
Illinois Accounts and $785 in gains associated with foreign currancy exchange
rates less taxes of $771.
Income Tax: Provision for income taxes resulted in a tax benefit for 2004, 2003
and 2002 of $10,003, $1,227 and $5,671, respectively. The Company has a Net
Operating Loss ("NOL") carry forward of approximately $38,000, some of which is
subject to limitation under Section 382 of the IRS code.
Transaction Costs: In 2004, we incurred transaction costs of $13,858 associated
with the Countryside Fund. These costs include $10,428 in debt prepayment fees
paid to John Hancock and ABB Energy Capital due to the prepayment of the debt
prior to its maturity, $1,802 related to the write off of unamortized debt
issuance cost associated with John Hancok and ABB Energy Capital debt and $1,628
for internal Company expenses associated with the transaction.
Other Income/(Loss): In 2004 we had Other Income/(Loss) of $3,214. This income
was comprised of a $2,729 pre tax gain associated with the acquisition of the
AJG subordinated debt plus $485 in earnings on the investment of reserve funds.
CONTRACTUAL OBLIGATIONS
The following table summarizes our significant contractual obligations at
December 31, 2004 and the effect such obligations are to have on our liquidity
and cash flow in future periods.
(Dollars in thousands)
======================================================================================================================
Total Less than 1-3 years 4-5 years More than
1 year 5 years
======================================================================================================================
Debt Obligations $80,521 $1,373 $5,150 $4,503 $69,495
Operating Leases 776 291 478 7 --
Purchase Obligations (1) 1,224 288 864 72 --
Other Long Term Liabilities (2) 49,028 0 0 1,000 48,028
======================================================================================================================
Total $131,549 $1,952 $6,492 $5,582 $117,523
======================================================================================================================
Footnotes:
(1) The Company is a party to contractual obligations including gas
purchase agreements and operation and maintenance agreements which
do not specifically provide for a minimum purchase obligation and
accordingly are not included above. In 2004, we paid an aggregate of
$1,753 pursuant to such arrangements.
(2) Other Long Term Liabilities reflected on registrants balance sheet
according to GAAP. On the balance sheet, this is titled Illinois
Subsidy Liability. The $26,346 reported on the balance sheet is
equal to $49,028 owed to Illinios under the Retail Rate Program less
$22,682 related to the GAAP treatment of the subsidy.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2004, cash and marketable securities totaled $45,591, of which
$15,982 was unrestricted, as compared with $3,725 of unrestricted cash at
December 31, 2003. The financing arrangements between the Countryside Fund and
the USEB projects require these subsidiaries to maintain various restricted cash
accounts, which, at December 31, 2004, amounted to $29,609. Included in the cash
and marketable securities is $21,428 that is managed by a money manager under
investment allocation parameters established by the Company and USEB. The
investment accounts managed by the money manager, as of December 31, 2004
included $13,352 invested in equity funds, $6,945 invested in debt funds and
$1,131 being held in cash or cash equivalents. The cost basis of the
investments, which have been invested with the money manager since July 2004, is
$20,182.
During the year ended December 31, 2004 net cash flows provided by operating,
financing activities and investing activities resulted in an increase in cash
and marketable securities of $24,677.
17
During the year 2004, cash flow utilized by operating activities was $(2,417)
which is a decrease of $11,858 from the $9,441 of cash provided by operating
activities for 2003. The decrease is the result of the loss of operating cash
flow from the sale of USE Canada and the termination of the SEFL investment plus
additional interest paid by USEB as the result of the the Countryside Fund
transaction.
Cash flows from investing activities was $14,100 for 2004, an increase of
$16,497 from the amounts reported for 2003. The increase was due to the sale of
USE Canada.
Cash flow from financing activities was $14,994 for 2004, an increase of $14,228
when compared to the amount from 2003. The increase is primarily the result of
refinancing of the USEB debt with the Countryside Fund and the sale of the USEB
roayalty interest to the Countryside fund.
USEB's financing arrangements with the Countryside Fund limit the ability of
USEB and its subsidiaries to distribute funds to the Company or to make
improvements or expand certain projects unless specified conditions are
satisfied.
We continue to evaluate current and forecasted cash flow as a basis to determine
financing operating requirements and capital expenditures. We believe that we
have sufficient cash flow from operations and working capital including
unrestricted cash on hand to satisfy all obligations under outstanding
indebtedness, to finance anticipated capital expenditures and to fund working
capital requirements during the next twelve months.
SIGNIFICANT ACCOUNTING ESTIMATES
The Company utilized estimates in the calculation of the valuation of the
Goodwill Asset. See Note A(5) to the consoidated financial statements. Actual
future operating results that deviate from the estimates would have an effect on
the future valuation of the Goodwill Asset.
CERTAIN RISK FACTORS THAT MAY IMPACT US
Set forth below and elsewhere in this report and other documents we file with
the SEC are risks and uncertainties that could cause actual results to differ
materially from the results contemplated by the forward looking statements
contained in this report.
RISKS RELATED TO THE COMPANY
Our subsidiaries have substantial indebtedness and in connection with their
existing indebtedness we have agreed to significant restrictions upon their
operations, including their ability to use their cash.
We have substantial debt that has been incurred to finance the acquisition and
development of energy facilities. As of December 31, 2004, our total
consolidated long term debt was $80,521. The terms of this debt require USEB to
deposit $250 per calender quarter into the debt service reserve fund provided
that cash available, as defined in the loan agreement, is at certain levels.
USEB was only required to make $84 of additional deposits into the debt service
reserve during 2004. Until an amount is deposited into the reserve equal to $250
per quarter since the April 8, 2004 closing, USEB is precluded from making
dividend or royalty payments or from expending funds to expand its production
capacity. Whether USEB will be able to meet our debt service obligations and
fund the debt service reserve obligations will depend primarily upon the
performance of its energy projects.
We have rate risk within the Illinois Retail Rate Program.
During 2004, USEB experienced major rate reductions at three of the Illinois
projects operating under the Illinois Retail Rate Program. The off-taker at such
projects is Commonwealth Edison. Retail rates for these projects, which are
adjusted annually in arrears, decreased by amounts ranging from 26% to 40% per
kwh. Projects participating in this program accounted for 59% and 47% of our
revenues in 2004 and 2003, respectively. USEB cannot predict whether any other
rate changes are likely. Any additional rate decreases will have a negative
effect on our operating results and cash flow.
18
We depend on our electricity and landfill gas customers.
Our energy facilities rely on one or more energy sales agreements with one or
more customers for a substantial portion of their revenues. Any material failure
by any customer to fulfill its obligations under an energy sales agreement could
have a negative effect on the cash flow available to us and on our results of
operations. Commonwealth Edison accounted for 42% and 34% of our revenues in
2004 and 2003, respectively.Our business of owning, operating power plants, and
district energy systems involve considerable risk.
The operation of energy generation facilities involves many risks, including the
breakdown or failure of power generation, heating and cooling, equipment,
transmission lines, pipes or other equipment or processes and performance below
expected levels of output or efficiency. Although the facilities in which we are
or will be involved contain some redundancies and back-up mechanisms, no
assurances can be made that those redundancies or back-up mechanisms would allow
the affected facility to perform under applicable power purchase and energy sale
agreements. USEB has entered into operation and maintenance agreements with
GE/Jenbacher and RUN Energy for eight and two of its projects, respectively. As
a result, USEB is and will be dependent on these third party operators for the
successful operation of these projects. To the extent that these parties do not
fulfill their obligations under these agreements, USEB's operations at these
projects could be adversely affected. Renewable energy projects such as
geothermal, biogas and biomass projects are dependent upon energy and fuel
supplies, which may experience significant changes. Our energy projects,
particularly our district energy systems, experience changes in revenue and
expenses due to seasonality.
We may lose our status as a qualifying facility.
If any of our projects were to lose its status as a QF, then it could become
subject to rate (and other) regulation as a public utility under the federal and
state law. This would result in substantial regulatory burdens, and possibly
insurmountable impediments, to affected entities with regard to conducting
business in the manner currently conducted and contemplated. In addition, loss
of QF status could trigger defaults under covenants to maintain QF status in
various purchase and loan agreements and result in termination, penalties or
acceleration of indebtedness under such agreements, plus interest. A facility
may lose its QF status on a retroactive or a prospective basis.
While certain legislation to repeal and amend certain sections of PURPA, which
had been pending before the United States Senate and the United States House of
Representatives, would have protected each existing contract of QFs from a
repeal of the obligation of electric utilities to purchase from QFs under their
existing PPAs, there is no guarantee that any future legislation, as passed into
law, would contain provisions to grandfather such PPAs. Loss of QF status for
any Biogas Project could lead to, among other things, a requirement that the
Biogas Project refund payments previously made under the PPAs, with interest.
Under the FPA, FERC has exclusive rate-making jurisdiction over wholesale sales
of electric energy and the transmission of electric energy in interstate
commerce. These rates may be determined on either a cost-of-service basis or, if
the applicable standards are met, using a market-based approach. If any Biogas
Project were to lose its QF status, the rates set forth in the applicable PPA
would have to be filed with FERC and would be subject to initial and potentially
subsequent reviews by FERC under the FPA, which could result in reductions to
such rates.
Loss of QF status by any Illinois-based Biogas Project would cause it also to
lose its QSWEF status. See "Business Regulation".
A significant source of US Biogas revenues are generated from special tax
credits provided for the sale of landfill gas to third parties and these credits
will expire.
19
USEB benefits from Section 29 of the Internal Revenue Code. Section 29 provides
that owners of biogas facilities that collect and sell biogas as a fuel are
permitted to reduce their annual federal income tax liability with a tax credit
based upon the volume of the biogas sold to unrelated third parties.
Historically USEB has sold interests in the Gascos producing these tax credits
to financial investors and such sales have provided USEB with additional
revenue. Part of the purchase price is contingent on gas production. If gas
production were to fall, USEB's revenues may decline. USEB has agreed to
indemnify the financial investors that have purchased interests in the Gascos
for certain losses suffered by such investors in the event that the Section 29
tax credits are denied in certain circumstances.
The tax credit is available for biogas produced at projects that had existing
gas collection facilities that were placed in service before July 1, 1998. The
tax credits are available for qualifying projects until December 31, 2007,
except that projects which were in operation prior to 1993 qualified for the tax
credits only through 2002. Therefore the universe of projects eligible for tax
credits is limited. From time to time, legislation has been proposed to renew
Section 29 tax credits, but it is uncertain whether this legislation will be
enacted, what its final form will be, and in particular whether such legislation
would extend Section 29 tax credits for existing projects or make them available
only for new projects. The unavailability of these tax credits for future biogas
projects may make such future projects less attractive for investment. The
expiration of these tax credits for existing projects may make some biogas
projects financially unviable and reduce USEB's revenues.
Neither USEB, any of the Gascos, nor any Gasco partner has received a ruling
from the IRS confirming that the biogas facilities of the Gascos meet the
requirements of Section 29, that the sales of interests in the Gascos by USEB
were structured in a way that would entitle the buyers to Section 29 credits, or
that sales of methane from the Gascos to the Gencos or Transcos generate Section
29 credits. While a ruling is not required, as is the case with any Section 29
transaction in which a ruling is not obtained, the IRS may challenge the
availability of Section 29 credits to any of the Gascos or to its partners.
We may be unable to acquire or renew the numerous permits and approvals required
to operate power facilities .
The construction and operation of energy projects require numerous permits and
approvals from governmental agencies, as well as compliance with environmental
laws and other regulations. While we believe that we are in substantial
compliance with all applicable regulations and that each of our projects has the
requisite approvals, our projects require compliance with a varied and complex
body of laws and regulations that both public officials and private individuals
may seek to enforce. There can be no assurance that new laws or amendments to
existing laws which would have a materially adverse affect will not be adopted,
nor can there be any assurance that we will be able to obtain all necessary
permits and approvals for proposed projects or that completed facilities will
comply with all applicable permit conditions, statutes and regulations. In
addition, regulatory compliance for the construction of new facilities is a
costly and time consuming process which may necessitate substantial expenditures
to obtain permits, and may create a significant risk of expensive delays or loss
of value if a project is unable to function as planned due to changing
requirements or local opposition.
We have legislative risk pertaining to the continuation of the Illinois Retail
Rate Program
Ten of the Illinois project owned by our USEB subsidiary operate under the
Illinois Retail Rate program. Under the program, the Illinois Commerce
Commission mandates that the local utility purchase power from our projects at
above market rates. The utility is reimbursed by Illinois for any payments made
to our projects above market rates or avoided costs. From time to time during
the past few years and in each of 2004 and 2005, the Governor and/or Lieutenant
Governor of Illinois and members of the Illinois legislature have proposed
changes to or the elimination of the Illinois Retail Rate Program and have
introduced legislation to such effect. While legislation has not been adopted,
the adoption of legislation or the implementation of rules that would reduce or
eliminate the benefits received by the Company under this program would have a
material adverse effect on the Company, as the revenues from such projects
constitued 59% of our revenues in 2004.
We may face substantial impediments to completing future acquisitions and
development projects.
Our growth strategy depends on our ability to identify and acquire appropriate
companies or energy projects, our ability to develop new energy projects, our
ability to integrate the acquired and developed operations effectively and our
ability to increase our market share. We cannot assure you that we will be able
to identify viable acquisition candidates or development projects, that any
identified candidates or development projects will be acquired or developed,
that acquired companies or power facilities and developed projects will be
effectively integrated to realize expected efficiencies and economies of scale,
or that any acquisitions or development projects will prove to be profitable or
be without unforeseen liabilities. In the event that acquisition candidates or
development projects are not identifiable or acquisitions or development
projects are prohibitively costly, we may be forced to alter our future growth
strategy. As we continue to pursue our acquisition and development strategy in
the future, our stock price, financial condition and results of operations may
fluctuate significantly from period to period.
20
We have limited available capital, and we may need additional financing in the
future.
We believe that our current and anticipated cash flow from operations and assets
sales from the financing sources and transactions described herein will be
sufficient to meet our anticipated cash requirements for the next twelve months;
however, there can be no assurance in this regard. As of December 31, 2004 we
had $15,982 in unrestricted cash available. If we are unable to generate cash
flows from operations to fund our working capital needs, we would be required to
obtain additional equity or debt financing to continue to operate our business.
In addition, we anticipate that each project we acquire or develop will require
us to raise additional financing, some of which may be in the form of additional
equity.
There can be no assurance that this capital will be available to us, or if
available, that it will be on terms acceptable to us. If issuing equity
securities raises additional funds, significant dilution to existing
stockholders may result. If additional financing for projects is not available
on acceptable terms, we may have to cancel, decline or defer new projects. Any
inability by us to obtain additional financing to meet cash or capital
requirements, if required, may have a material adverse effect on our operations.
Environmental Health and Safety Risks
Our projects are regulated by numerous and significant laws, including statutes,
regulations, by-laws, guidelines, policies, directives and other requirements
governing or relating to, among other things: air emissions, discharges into
water, the storage, handling, use, transportation and distribution of dangerous
goods and hazardous and residual materials, such as chemicals; the prevention of
releases of contaminants, pollutants or hazardous materials into the
environment; the presence, remediation and monitoring of contaminants,
pollutants or hazardous materials in soil and water, including surface or
groundwater, both on and off site; land use and zoning matters; and workers
health and safety matters. As such, the operation of the projects and systems
carry an inherent risk of environmental, health and safety liabilities
(including potential civil actions, compliance or remediation orders, fines and
other penalties), and may result in the projects and systems being involved from
time to time in administrative and judicial proceedings relating to such
matters, which could have a material adverse effect on the Company's business,
financial condition and results of operations.
Our projects have obtained environmental permits that are required for their
operation. Although we believe that the operations of the facilities are
currently in material compliance with applicable environmental laws, including
permits required for the operation of the projects and systems and although
there are environmental monitoring and reporting systems in place with respect
to all the projects and systems, there is no guarantee that more stringent laws
will not be imposed, that there will not be more stringent enforcement of
applicable laws or that such systems may not fail, which may result in material
expenditures. Failure by the projects and systems to comply with any
environmental, health or safety requirements, or increases in the cost of such
compliance, including as a result of unanticipated liabilities (whether as a
result of newly discovered issues or known issues that have not been quantified)
or expenditures for investigation, assessment, remediation or monitoring, could
result in additional expense, capital expenditures, restrictions and delays in
the projects' and systems' activities, the extent of which cannot be predicted
and which may be material.
Resource Availability and Constancy
The Biogas Projects rely on the extraction of biogas from public and
privately-owned landfill sites. The decomposition of waste causes the release of
methane gas, carbon dioxide, and other gaseous material into the ground and
atmosphere. Landfills typically can emit biogas for more than 30 years.
Landfills generally produce biogas in increasing volumes during their initial
years of operation and for several years after they are closed. Then the biogas
volume gradually declines over ensuing years. Therefore each project is likely
to produce less revenue after the first years following the landfill closing,
and may over time become unprofitable as the volume of biogas continues to
decline. Thus in many cases it is not profitable to maintain projects more than
a certain number of years following the closing of the related landfill. The
quantity of available biogas is determined by numerous factors including,
without limitation, filling pattern of the landfill, the composition of the
waste, compaction, moisture content, time and climatic conditions. These factors
are beyond the control of USEB. Further, they constitute future events that
cannot be predicted with certainty. In the event that the amount of biogas
produced by a landfill is less than expected, the methane component of the gas
is less than expected or the duration of biogas emission is shorter than
expected, the sale of biogas by USEB, the production of electricity by USEB
and/or the amount of revenue received by USEB from the sale of Section 29 tax
credits may be adversely affected in a material manner.
21
Generally with respect to each Biogas Project: (i) the Gasco's right to extract
biogas from the landfill is subject to a long-term gas rights agreement with the
landfill owner; (ii) the Genco or Transco's right to purchase biogas from the
Gasco is subject to a long-term gas purchase agreement with the Gasco; and (iii)
the Genco or Transco's right to occupy the landfill is subject to a long-term
lease with the landfill owner. In certain cases, based on the occurrence of
certain events, including an event of default by the Gasco, Genco or Transco the
contract counterparty may terminate the applicable agreement or lease prior to
the expiry of its term. While USEB believes that the Biogas Projects, Gascos,
Gencos and Transco's are in material compliance with all of their respective
agreements or leases, if one of the foregoing agreements or leases was
terminated prematurely, for any reason, the relevant Biogas Project would be
affected in a material adverse manner.
QSWEF Status
All of USEB's Illinois-based Biogas Projects qualify as QSWEFs and therefore
benefit from the Rate Incentive Program. The Rate Incentive Program permits such
QSWEFs to sell electricity that they generate to public utilities in whose
service areas the QSWEFs are located at a rate that during the period of the
Rate Incentive Program (a) is equal to the average amount per kwh paid by the
local governmental entities for electricity (with certain exceptions) in such
QSWEFs' respective jurisdictions and (b) typically exceeds the public utilities'
respective Avoided Costs. Eligibility for the Rate Incentive Program is based on
compliance with the requirements contained in the Illinois Public Utility Act,
regulations promulgated by the ICC ("ICC Regulations") and the ICC Orders issued
by the ICC respecting QSWEFs. A QSWEF would lose all or some of the benefits
provided by the Rate Incentive Program if it were found to be in non-compliance
with these requirements. Similarly, a QSWEF may lose all or some of such
benefits in the event of modifications to the Illinois Public Utility Act, the
ICC Regulations, the ICC Orders or ICC policies or repeal of the Illinois Public
Utility Act. In such event, the revenues and profits from the affected QSWEFs
may be materially adversely impacted.
The rate incentive received by each QSWEF, which must be reimbursed to Illinois,
represents the excess of the Gross Contract Rate received by such QSWEF from the
public utility less the public utility's Avoided Cost. Therefore, the QSWEF's
rate incentive and corresponding reimbursement obligation will depend, among
other things, on the level of such Avoided Cost, which is beyond the control of
the QSWEF.
Loss of QSWEF status could trigger defaults under covenants to maintain QSWEF
status in various purchase and loan agreements (including the loans agreements
with Countryside Fund) and result in termination, penalties or acceleration of
indebtedness under such agreements plus interest.
Illinois Subsidy Liability Repayment
The ICC has broad powers to enforce and interpret the provisions of the Illinois
Public Utility Act, ICC Regulations and ICC Orders. In the future, the ICC may
promulgate new regulations and establish new policies or modify existing
regulations and policies. Such actions, if taken and upheld by the courts, may
have a materially adverse impact on some or all of the Illinois-based Biogas
Projects. The ICC has enforcement authority to direct each owner of an
Illinois-based Biogas Project to satisfy its subsidy liability repayment
obligations, which authority may extend to, among other matters, the legal
entity that is to hold the Illinois Accounts, the amount of funds to be
deposited annually in the Illinois Accounts and the kinds of investments in
which such funds are or may be invested. Although the ICC has considered
imposing and has imposed such requirements in the past as a condition to its
approval of certain proposed transactions, it cannot be predicted with certainty
whether and under what similar or different circumstances the ICC may attempt to
impose any of such requirements in the future. However, provided the QSWEFs (a)
remain in compliance in good faith with the current Illinois Public Utilities
Act, ICC Regulations and ICC Orders, (b) make timely deposits to their Illinois
Accounts that, together with earnings thereon from a reasonable and balanced
investment portfolio, are reasonably sufficient to meet the QSWEFs'
reimbursement obligations to the Illnois, and (c) do not seek approval from the
ICC for any transactions that require ICC approval or modify existing ICC
Orders, the we have no reason to believe that the ICC will take any such actions
respecting the QSWEFs in a manner materially adverse to them.
22
Under the Illinois Retail Rate Program, each QSWEF must begin to repay the
subsidy it has received to Illinois beginning no later that the earlier of the
date the QSWEF has paid or otherwise satisfied in full the capital costs or
indebtedness incurred in developing its facility and 10 years after the date its
facility commenced commercial operation, with such repayment to be completed no
later than the earlier of 20 years after such date of commencement of commercial
operation and the end of its facility's actual useful life. In order to meet
this obligation, each QSWEF has established an Illinois Account in which it has
deposited and will continue to deposit a portion of the subsidy as it is
received with the expectation that such deposits, when invested prudently in a
balanced portfolio managed by professional advisors, will over time generate
sufficient earnings to permit such QSWEF to meet its reimbursement obligations
to Illnois as and when they come due. However, in the event the ICC exercised
its enforcement authority in a manner that resulted in a lower return than
expected or the investments in the Illinois Accounts otherwise do not generate
the expected earnings, a QSWEF may not have sufficient funds to meet its
obligations to reimburse the Illnois when such obligations come due with
potential material adverse consequences to the affected QSWEF.
Future Foreign Currency Exchange Risk
Pursuant to the terms of the financing arrangements with the Countryside Fund,
USEB is required to make debt service payments to the Countryside Fund in
Canadian dollars. USEB has entered into a three year hedge agreement with a
financial institution fixing the US dollar to the Canadian dollar exchange rate
at approximately US$0.76 per Canadian dollar through March 31, 2007. Beginning
April 1, 2007, USEB is required to maintain a foreign currency hedge agreement
for a minimum of 75% of the remaining debt service payments. USEB will be at
risk for fluctuations in the currency exchange rate should the rate vary from
the exchange rate existing in the expiring hedge agreement and no new hedge
agreement is in place.
The energy business is very competitive and increased competition could
adversely affect us.
In addition to competition from electric utilities in the markets where our
projects are located, our energy business also faces competition from companies
currently involved in the cogeneration and independent power market throughout
the United States. Some of these companies are larger and better financed than
we are. Although we believe that we will be entering segments of the marketplace
where we will not face extensive competition, no assurances can be made that we
will be able to enter these markets or that there will not be competition in
such markets. Additionally, in recent years, such competition has contributed to
a reduction in electricity prices in certain markets.
While a majority of the off-takers of our projects are contractually obligated
to purchase electricity under long-term power PPAs, the projects based on market
pricing will be exposed to fluctuations in the wholesale price of electricity.
In addition, should any of the long-term contracts terminate or expire, we will
be required to either negotiate new PPAs or sell into the wholesale market for
electricity, in which case the prices for electricity will depend on market
conditions at the time. Similarly, when the Biogas Projects located in Illinois
are no longer eligible to receive incentives under the Rate Incentive Program,
it is expected that the projects will seek to negotiate new contracts in the
Green Power Market based on rates prevailing in the Green Power Market at the
time. Further, the Gross Contract Rate which USEB's Illinois-based Biogas
Projects receive is equal to the average amount per kwh paid by the local
government entities in the project's respective jurisdiction and, therefore, may
be subject to change.
We operate in an emerging industry and have limited marketing capabilities.
Although the energy markets in which we operate have been in existence for a
number of years, they are still in the development stage. As is typically the
case in an emerging industry, levels of demand and market acceptance for
products and services are highly uncertain. Further, we have limited financial,
personnel and other resources to undertake extensive marketing activities.
23
We may experience project development risks.
Our ability to develop new projects is dependent on a number of factors outside
our control, including obtaining customer contracts, power agreements,
governmental permits and approvals, fuel supply and transportation agreements,
electrical transmission agreements, site agreements and construction contracts.
No assurances can be made that we will be successful in obtaining these
agreements, permits, and appraisals. Project development involves significant
environmental, engineering and construction risks.
Although we have insurance it may not cover every potential risk associated with
our operations.
Although we maintain insurance of various types to cover many of the risks that
apply to our operations, including $2,000 of general liability insurance, a
$20,000 umbrella policy, as well as separate insurance for each project, our
insurance will not cover every potential risk associated with our operations.
The occurrence of a significant adverse event, the risks of which are not fully
covered by insurance, could have a material adverse effect on our financial
condition and results of operations. Moreover, no assurance can be given that we
will be able to maintain adequate insurance in the future at rates we consider
reasonable.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Fluctuations in interest rates and investment yields will effect earnings
derived from the investment of the various reserve accounts which could have a
material effect on the Company's financial performance. Fluctuations in the
foreign currency exchange rate between the US dollar and the Canadian dollar as
it relates to the payment of debt service on the the Countryside Fund loan could
also have a material effect on the Company's financial performance. The exchange
rate is currently fixed per a foreign currency hedge agreement that expires in
March, 2007. See notes A(19) and E to our consolidated financial statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements together with the report of the
independent registered public accounting firm thereon, are presented under Item
15 of this report.
Supplementary Financial Information
2004 (Dollars in thousands, except share amounts)
==========================================================================================================
First Quarter Second Quarter Third Quarter Fourth Quarter
==========================================================================================================
Operating Revenue $ 5,117 $ 4,479 $ 6,213 $ 4,299
Operating Income (6,501) (759) 1,812 1,419
Net income for Common Stock (4,181) 5,272 536 (1,811)
Basic Earnings per Common Stock (0.35) 0.44 0.04 (0.15)
Diluted Earnings per Common Stock -- 0.32 0.03 --
2003 (Dollars in thousands, except share amounts)
==========================================================================================================
First Quarter Second Quarter Third Quarter Fourth Quarter
==========================================================================================================
Revenue $ 5,883 $ 6,207 $ 6,390 $ 6,519
Operating Income 1,657 1,121 741 1,516
Net income for Common Stock 143 1,370 315 (818)
Basic Earnings per Common Stock 0.01 0.11 0.03 (0.07)
Diluted Earnings per Common Stock 0.01 0.08 0.02 --
24
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
On or about November 18, 2004, we received a letter from Kostin, Ruffkess and
Company, LLC, our outside auditor (the "Former Auditor"), stating that they
intended "to withdraw from audit work in the public company arena." This change
will take place subsequent to the audit of the year 2004 financial statements.
The Former Auditor's reports on our consolidated financial statements during the
years ended December 31, 2004, 2003 and 2002 did not contain an adverse opinion
or a disclaimer of opinion, nor was it qualified or modified as to uncertainty,
audit scope, or accounting principles.
During the years ended December 31, 2004, 2003 and 2002 and all subsequent
interim periods preceding the resignation, there were no disagreements with the
Former Auditor on any matter of accounting principles or practices, financial
statement disclosure, or auditing scope or procedure, which disagreement, if not
resolved to the satisfaction of the Former Auditor, would have caused it to make
a reference thereto in its reports on our financial statements for each period.
ITEM 9A. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, the Company carried out an
evaluation, under the supervision and with the participation of the Company's
management, including the Company's Chief Executive Officer and the Company's
Chief Accounting Officer, of the effectiveness of the design and operation of
the Company's disclosure controls and procedures (as defined in Rules 13a-15(e)
and 15d-15(e) under the Securities and Exchange Act of 1934, as amended). Based
on this evaluation, the Company's Chief Executive Officer and Chief Accounting
Officer (i.e., its chief financial officer) concluded that the Company's
disclosure controls and procedures were effective, in timely manner alerting
them to material information relating to the Company required to be included in
the Company's periodic filings with the Securities and Exchange Commission. It
should be noted that in designing and evaluating the disclosure controls and
procedures, management recognized that any controls and procedures, no matter
how well designed and operated, can provide only reasonable assurance of
achieving the desired control objectives, and management necessarily was
required to apply its judgment in evaluating the cost-benefit relationship of
possible controls and procedures. The Company has designed its disclosure
controls and procedures to reach a level of reasonable assurance of achieving
desired control objectives and, based on the evaluation described above, the
Company's Chief Executive Officer and ChiefAccounting Officer (i.e., its chief
financial officer) concluded that the Company's disclosure controls and
procedures were effective at reaching that level of reasonable assurance.
There was no change in the Company's internal control over financial reporting
(as defined in Rules 13a-15(f) and 15d-15(f) under the Securities and Exchange
Act of 1934, as amended) during the Company's most recently completed fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, the Company's internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
The required information is incorporated by reference from our definitive proxy
statement to be filed with the SEC by May 2, 2005.
25
ITEM 11. EXECUTIVE COMPENSATION
The required information is incorporated by reference from our definitive proxy
statement to be filed with the SEC by May 2, 2005.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The required information is incorporated by reference from our definitive proxy
statement to be filed with the SEC by May 2, 2005.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The required information is incorporated by reference from our definitive proxy
statement to be filed with the SEC by May 2, 2005.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The required information is incorporated by reference from our definitive proxy
statement to be filed with the SEC by May 2, 2005.
ITEM 15. EXHIBITS AND FINANCIAL SCHEDULES
(a) The following documents are flied as part of this report
(3) Financial Statements
Description
Report from Independent Registered Public Accounting Firm
Consolidated Balance Sheet as of December 31, 2004 and 2003
Consolidated Statement of Operations and Other Comprehensive Income
(Loss) for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Statement of Changes in Stockholders Equity for the
Years Ended December 31, 2004, 2003 and 2002
Consolidated Statement of Cash Flows for the Years Ended December
31, 2004, 2003 and 2002
Notes to Consolidated Financial Statements
(4) Exhibits
Exhibit Description
Number
3.1 Restated Certificate of Incorporation of the Company filed with the
Secretary of State of Delaware (1)
3.2 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of the Company (4)
3.3 Amended and Restated By-Laws of US Energy (5)
3.4 Form of Certificate of Designation for US Energy's Series C
Preferred Stock (8)
26
Exhibit Description
Number
3.5 Form of Certificate of Designation for US Energy's Series D
Preferred Stock (8)
3.6 Certificate of Correction to Certificate of Designation of Series B
Preferred Stock (8)
4.1 Specimen Stock Certificate (1)
4.2 Certificate of Designation of Series B Convertible Preferred Stock
of the Company as filed with the Secretary of the State of Delaware
(7)
4.3 Amended and Restated Plan of Recapitalization dated as of July 31,
2000 by and between the Company and the parties identified therein
(8)
4.4 Form of Series B Warrant to Purchase Shares of Common Stock (4)
4.5 Form of Series C Redeemable Common Stock Purchase Warrant of US
Energy (5)
10.1 Purchase Agreement, dated as of January 24, 1994, between Lehi
Co-Gen Associates, L.C. and Lehi Envirosystems, Inc. (2)
10.2 Operating Agreement among Far West Capital, Inc., Suma Corporation
and Lehi Envirosystems, Inc. dated January 24, 1994 (2)
10.3 Agreement among the Company, Plymouth Envirosystems, Inc., IEC
Plymouth, Inc. and Independent Energy Finance Corporation dated
November 16, 1994 (1)
10.4 Amended and Restated Agreement of Limited Partnership of Plymouth
Cogeneration Limited Partnership between PSC Cogeneration Limited
Partnership, Central Hudson Cogeneration, Inc. and Plymouth
Envirosystems, Inc. dated November 1, 1994 (1)
10.5 Amended and Restated Agreement of Limited Partnership of PSC
Cogeneration Limited Partnership among IEC Plymouth, Inc.,
Independent Energy Finance Corporation and Plymouth Envirosystems,
Inc. dated December 28, 1994 (1)
10.6 Security Agreement and Financing Statement among the Company, Lehi
Envirosystems, Inc., Plymouth Envirosystems, Inc. and Anchor Capital
Company, LLC dated June 14, 1995, as amended (1)
10.7 Certificate of Designations (1)
10.8 Loan and Option Agreement dated August, 1996 by and among NRG
Company, LLC and Reno Energy, LLC and ART, LLC and FWC Energy, LLC,
and Amendments thereto (1)
10.9 Form of Debenture Conversion Agreement (1)
10.10 Subscription Agreement, dated March 20, 1998, between the Company
and Energy Systems Investors, LLC (3)
10.11 Registration Rights Agreement, dated March 20, 1998, between the
Company and Energy Systems Investors, LLC (3)
10.12 Amended and Restated Stock Option Agreement between the Company and
Lawrence I. Schneider dated May 10, 2000 with respect to 750,000
shares of the Company Common Stock (4)
10.13 Amended and Restated Stock Option Agreement between the Company and
Goran Mornhed dated May 10, 2000 with respect to 1,000,000 shares of
the Company Common Stock (4)
10.14 Pledge Agreement dated as of July 31, 2000 by and between the
Company and Energy Systems Investors, L.L.C. (4)
10.15 Limited Recourse Promissory Note dated July 31, 2000 issued by
Energy Systems Investors, L.L.C. in favor of the Company (4)
27
Exhibit Description
Number
10.16 Registration Rights Agreement dated November 28, 2000 by and among
US Energy and the Zapco Stockholders (5)
10.17 Performance Guaranty dated as November 28, 2000 of US Energy (5)
10.18 Performance Guaranty of Cinergy Solutions Holding Company, Inc.
dated as of November 28, 2000 (5)
10.19 Subscription Agreement dated as of November 28, 2000 by and among US
Energy, US Energy Sub and Cinergy Energy (5)
10.20 Stockholders Agreement dated as of November 28, 2000 by and among US
Energy, US Energy Sub and Cinergy Energy (5)
10.21 Indemnification Agreement dated as of November 28, 2000 by and among
US Energy, US Energy Sub and Cinergy Energy (5)
10.22 Employment Agreement dated as of May 10, 2000 by and between the
Company and Lawrence Schneider (6)
10.23 Employment Agreement dated as of May 10, 2000 by and between the
Company and Goran Mornhed (6)
10.24 2000 Executive Incentive Compensation Plan (6)
10.25 2000 Executive Bonus Plan (6)
10.26 Stock Option Agreement between the Company and Lawrence Schneider
with respect to 1,000,000 shares of Common Stock (6)
10.27 Stock Option Agreement between the Company and Goran Mornhed with
respect to 187,500 shares of Common Stock (6)
10.28 Stock Option Agreement between the Company and Goran Mornhed with
respect to 562,500 shares of Common Stock (6)
10.29 Standby Payment Agreement dated as of June 11, 2001 by and among
U.S. Energy Systems, Inc., USE Canada Acquisition Corp. and AJG
Financial Services, Inc. (9)
10.30 Development Incentive Plan (10)
10.31 Corporate Incentive Plan (10)
10.32 Finance Incentive Plan (10)
10.33 Employment Agreement dated as of January 1, 2002 between the Company
and Edward Campana (10)
10.34 Employment Agreement dated as of September 8, 2000 between the
Company and Henry Schneider (10)
10.35 Agreement by and among AJG Financial, as agent, U.S. Energy, Cinergy
Energy, U.S. Energy Biogas and Tannenbaum, Helpern as agent dated as
of October 16, 2003 (11)
10.36 Escrow letter by and among, Tannenbaum, Halpern escrow agent, AJG
Financial, Cinergy Energy, US Energy, U.S. Energy Biogas Corp (11)
10.37 Amended and Restated Subordinated Note from U.S. Energy Biogas Corp.
to AJG Financial Services, Inc. (11)
10.38 Loan Agreement dated as of November 3, 2003 (11)
10.39 2003 Finance Incentive Plan (11)
28
Exhibit Description
Number
10.40 2003 Development Incentive Plan (11)
10.41 Royalty Agreement dated as of April 8, 2004 by and between U.S.
Energy Biogas Corp., Countryside Canada Power, Inc., the Registrant
and Cinergy Energy Solutions, Inc. (12)
10.42 Amendment to Note Purchase Agreement dated as of April 8, 2004 by
and between U.S. Energy Biogas Corp., Avon Energy Partners, LLC and
the other parties identified therein (12)
10.43 Amendment to Indenture of Trust and Security Agreement dated as of
April 8, 2004 by and among US Energy Biogas Corp., Countryside
Canada Power, Inc. and the other parties identified therein (12)
10.44 Amendment dated April 8, 2004 among BMC Energy LLC, Countryside
Canada Power Inc. and the other parties identified therein to the
(i) Security Agreement dated as of May 2, 2001 among BMC Energy LLC,
Countryside Canada Power, Inc. (as successor to AJG Financial
Services, Inc.) and the other parties identified therein and (ii)
Cash Collateral Pledge and Security Agreement dated as of April 30,
2001 among BMC Energy, LLC, Countryside Canada Power, Inc. (as
successor to ABB Energy Capital, LLC) and the other parties
identified therein (12)
10.45 Form of Restricted Stock Unit for Directors (13)
10.46 Form of Restricted Stock Unit for Officers (13)
10.47 Purchase Agreement dated September 30, 2004 among AJG Finanacial
Services, Inc. and U.S. Energy Biogas Corp. (13)
10.48 Assignment Agreement dated September 30, 2004 among AJG Financial
Services, Inc. and U.S. Energy Biogas Corp. (13)
10.49 Severence Agreement and Mutual Release is by and between Edward M.
Campana and US Energy Systems, Inc.
10.50 Severence Agreement, Mutual Release and Consulting Agreement by and
between Allen J. Rothman and US Energy Systems, Inc.
23.1 Consent of Kostin, Ruffkess and Company, LLC.
31.1 Rule 13a-14(a)/15d-14(a) certifications
31.1 Rule 13a-14(a)/15d-14(a) certifications
32.1 Section 1350 certification
(1) Incorporated by reference to the Company's Registration Statement on
Form SB-2 (File No. 333-94612)
(2) Incorporated by reference to the Company's Annual Report on Form
10-KSB for the year ended January 31, 1994
(3) Incorporated by reference to the Company's Current Report on Form
8-K filed on March 26, 1998
(4) Incorporated by reference to the Company's Quarterly Report on Form
10-QSB for the quarter ended July 31, 2000
(5) Incorporated by reference to the Company's Quarterly Report on Form
10-QSB for the quarter ended October 31, 2000
(6) Incorporated by reference to the Company's Current Report on Form
8-K dated May 4, 2000
(7) Incorporated by reference to the Company's Annual Report on Form
10-KSB for the year ended January 31, 1999
29
Exhibit Description
Number
(8) Incorporated by reference to the Company's Report on Form 10-KSB for
the period ended December 31, 2000
(9) Incorporated by reference to the Company's Current Report on Form
8-K dated June 11, 2001
(10) Incorporated by reference to the Company's Quarterly Report on Form
10-QSB dated August 14, 2002
(11) Incorporated by reference to the Company's Report on Form 10-K for
the period ended March 31, 2003, as amended
(12) Incorporated by reference to the Company's Report on Form 10-Q for
the period ended March 31, 2004
(13) Incorporated by reference to the Company's Report on Form 10-Q for
the period ended September 30, 2004
30
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting
Firm....................................................................F-2
Consolidated Balance Sheets as of December 31, 2004 and 2003.................F-3
Consolidated Statements of Operations and Other Comprehensive Income
(Loss) for the Years ended December 31, 2004, 2003 and 2002.............F-5
Consolidated Statements of Cash Flows for the Years ended December
31, 2004, 2003 and 2002.................................................F-7
Consolidated Statements of Changes in Stockholders' Equity for the
Years ended December 31, 2004, 2003 and 2002............................F-9
Notes to Consolidated Financial
Statements.............................................................F-11
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
U.S. Energy Systems, Inc.
White Plains, New York
We have audited the accompanying consolidated balance sheets of U.S. Energy
Systems, Inc. and subsidiaries as of December 31, 2004 and 2003 and the related
consolidated statements of operations and other comprehensive income (loss),
changes in stockholders' equity and cash flows for each of the years ended
December 31, 2004, 2003 and 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits. We did not examine
the financial statements of USE Canada Energy Corp. for the year ended December
31, 2003, a consolidated subsidiary whose statements reflect total assets and
income constituting 16% and 65%, respectively, of the related consolidated
totals. Those statements were audited by other auditors whose report has been
furnished to us and our opinion insofar as it relates to the amounts included
for USE Canada Energy Corp. as of December 31, 2003 and the related year ended
is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company
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. 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, based on our audit and the report of the other auditors in 2003,
the consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of U.S. Energy Systems,
Inc. and subsidiaries as of December 31, 2004 and 2003 and the consolidated
results of their operation and their consolidated cash flows for each of the
years ended December 31, 2004, 2003 and 2002 in conformity with U.S. generally
accepted accounting principles.
Kostin, Ruffkess & Company, LLC
Farmington, Connecticut
/s/ Kostin, Ruffkess & Company, LLC
March 29, 2005
F-2
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In thousands, except share data)
ASSETS DECEMBER 31, DECEMBER 31,
2004 2003
------------ ------------
Current Assets:
Cash ..................................................................... $ 15,982 $ 3,725
Restricted Cash and Marketable Securities ................................ 29,609 17,188
Accounts Receivable (less allowance for doubtful accounts $46 and $1,313
in 2004 and 2003, respectively) ........................................ 4,857 9,105
Installments Sale Partnership Interest and Interest Receivable, Current
Portion ................................................................ 2,494 2,678
Other Current Assets ..................................................... 1,639 3,664
------------ ------------
Total Current Assets, Net ............................................ 54,581 36,360
------------ ------------
Property, Plant and Equipment, Net .......................................... 41,901 43,729
Construction in Progress .................................................... 198 595
Installment Sale Partnership Interest, less Current Portion ................. 23,537 12,987
Notes Receivable ............................................................ -- 1,247
Investments ................................................................. 801 8,251
Debt Issuance Costs, Net of Accumulated Amortization ........................ 11,266 2,405
Goodwill .................................................................... 26,618 26,218
Foreign Currrency Hedge ..................................................... 1,207 --
Deferred Tax Asset .......................................................... 12,409 11,812
Other Assets ................................................................ 11 257
Assets to be disposed of .................................................... -- 28,180
------------ ------------
Total Assets ......................................................... $ 172,529 $ 172,041
------------ ------------
LIABILITIES
Current Liabilities:
Current Portion Long-Term Debt ........................................... $ 1,373 $ 4,928
Notes Payable - Stockholder .............................................. -- 688
Accounts Payable and Accrued Expenses .................................... 4,057 5,887
Deferred Revenue Installment Sale Partnership Interest, Current Portion .. 398 1,007
------------ ------------
Total Current Liabilities ............................................ 5,828 12,510
------------ ------------
Long-Term Debt less Current Portion ......................................... 79,148 53,827
Notes Payable - Stockholder ................................................. -- 10,641
Deferred Revenue Installment Sale Partnership Interest, less Current Portion 2,699 5,105
Deferred Royalty ............................................................ 5,686 --
Illinois Subsidy Liability .................................................. 26,346 20,652
Advances from Joint Ventures ................................................ -- 102
Liabilities to be disposed of ............................................... -- 21,745
------------ ------------
Total Liabilities .................................................... 119,707 124,582
------------ ------------
Minority Interests .......................................................... 12,662 8,374
------------ ------------
See notes to consolidated financial statements
which are an integral part of the financial statements
F-3
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (Continued)
(In thousands, except share data)
============================================================================================================
STOCKHOLDERS' EQUITY DECEMBER 31, DECEMBER 31,
2004 2003
============================================================================================================
Preferred Stock, $.01 par Value, Authorized 10,000,000 Shares:
Series B, Cumulative, Convertible, Issued and Outstanding 368 Shares ..... $ -- $ --
Series C Cumulative, Convertible, Issued and Outstanding 100,000 Shares .. 1 1
Series D, Cumulative, Convertible, Issued and Outstanding 1,138,888 Shares 11 11
Total Common Stock, $.01 par Value, Authorized 50,000,000 Shares, issued
12,333,974 ............................................................... 123 123
Treasury Stock, at Cost ..................................................... (2,204) (2,204)
Additional Paid-in Capital .................................................. 64,063 64,891
Accumulated Deficit ......................................................... (23,516) (24,159)
Other Comprehensive Income .................................................. 1,682 422
------------ ------------
Total Stockholders' Equity ........................................... 40,160 39,085
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ........................... $ 172,529 $ 172,041
============ ============
See notes to consolidated financial statements
which are an integral part of the financial statements
F-4
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS AND OTHER
COMPREHENSIVE INCOME (LOSS)
(In thousands, except share data)
==========================================================================================================
Year Ended Year Ended Year Ended
December 31, 2004 December 31, 2003 December 31, 2002
----------------- ----------------- -----------------
Revenues $ 20,108 $ 24,999 $ 28,620
Costs and Expenses:
Operating Expenses 9,646 10,964 14,842
Investment Write-Offs 7,089 -- 3,684
General and Administrative Expenses 3,241 5,918 9,958
Depreciation and Amortization 4,279 3,874 5,906
(Gain) from Joint Ventures (118) (792) (60)
------------ ------------ ------------
Total Costs and Expenses 24,137 19,964 34,330
------------ ------------ ------------
Income (Loss) from Operations (4,029) 5,035 (5,710)
Interest and Dividend Income 2,828 1,135 1,729
Interest Expense (9,443) (6,779) (7,766)
Transaction costs (13,858) -- --
Other Income 2,642 -- --
Asset Sales -- (1,944) --
(Loss) on Investments -- -- (5,120)
Minority Interest 2,061 296 1,613
------------ ------------ ------------
Income(Loss) before Taxes and Cumulative
effect of Accounting Change and
Disposal of a Segment (19,799) (2,257) (15,254)
Income Tax Benefit (Expense) 10,003 1,227 5,671
------------ ------------ ------------
(Loss) Income before Cumulative effect of
Accounting Change and Disposal of a
Segment (9,796) (1,030) (9,583)
Income from discontinued operations 495 1,188 (4,192)
Gain/(Loss) on Disposal of a Segment (net
of Income Tax benefit/(expense) of
$(8,875), $(887) and $1,080
respectively) 9,945 1,680 (1,619)
Cumulative effect of Accounting Change in
Years Prior to 2002(net of Income Tax
benefit of $546) -- -- (754)
------------ ------------ ------------
Net (Loss) Income $ 644 $ 1,838 $ (16,148)
============ ============ ============
Dividends on Preferred Stock (828) (829) (831)
------------ ------------ ------------
Income (Loss) Applicable to Common Stock $ (184) $ 1,009 $ (16,979)
============ ============ ============
Other Comprehensive Income (Loss), Net of
Tax
Net (Loss) Income $ 644 $ 1,838 $ (16,148)
============ ============ ============
Unrealized Gain/Loss (net of Taxes, $771) 1,259 279 295
------------ ------------ ------------
Total Comprehensive Income (Loss) $ 1,903 $ 2,117 $ (15,853)
============ ============ ============
See notes to consolidated financial statements
which are an integral part of the financial statements
F-5
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS AND OTHER
COMPREHENSIVE INCOME (LOSS) (continued)
(In thousands, except share data)
===========================================================================================================
Year Ended Year Ended Year Ended
December 31, 2004 December 31, 2003 December 31, 2002
- -----------------------------------------------------------------------------------------------------------
INCOME (LOSS) PER SHARE OF COMMON STOCK:
(Loss)Income per Share of Common Stock - Basic $ (0.02) $ 0.08 $ (1.39)
(Loss)Income per Share of Common Stock -Diluted $ -- $ 0.11 $ --
Weighted Average Number of Common Shares
Outstanding - Basic 11,890 11,935 12,186
Weighted Average Number of Common Shares
Outstanding - Diluted 17,058 17,089 17,351
See notes to consolidated financial statements
which are an integral part of the financial statements
F-6
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands, except share data)
For the Year Ended For the Year Ended For the Year Ended
December 31, 2004 December 31, 2003 December 31, 2002
----------------- ----------------- -----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ................................... $ 644 $ 1,838 $ (16,148)
Adjustments to Reconcile Net Income (loss) to net
cash provided by (used in) operating activities:
Depreciation and Amortization ................... 4,279 3,874 6,123
Purchase Price Adjustment ....................... -- 1,100
Loss on Sale of Segment ......................... -- -- 1,619
Gain on sale of subsidiary ...................... (16,000) (1,680)
Minority Interest Income ........................ 2,061 (296) 1,000
Impairments and Write-offs ...................... -- 1,944 11,889
Gain on Acquisition of Debt ..................... (2,728) -- --
Unrealized Loss/(Gains) ......................... 1,260 -- --
Deferred Taxes .................................. (597) (526) (8,225)
Equity in (gain) Loss of Joint Ventures ......... -- -- (60)
Cumulative effects of Accounting Change on years
prior to 2002 (net of income tax of $546,000) -- -- 754
Changes in:
Accounts Receivable, Trade ...................... 4,248 (1,313) 746
Deferred Rate Swap .............................. (1,207) -- --
-- -- --
Other Current Assets ............................ 2,025 (2,188) 468
Other Assets .................................... 247 154 1,357
Accounts Payable and Accrued Expenses ........... (1,830) 1,809 1,552
Net effect of discontinued operation ............ -- 253 (1,465)
Minority Interest Liability ..................... -- -- 1,218
Deferred Revenue ................................ (513) (980) (1,185)
Rate Incentive Liability ........................ 5,694 5,452 5,619
------------ ------------ ------------
Net cash flows provided/Used In) by Operating
Activities .......................................... (2,417) 9,441 5,262
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Investments ..................................... -- (638) (3,099)
Proceeds from Sale of Subsidiary ................ 15,885
Net Acquisition of Equipment and Leasehold
Improvements .................................
Increase in Notes Receivable .................... (1,384) (512) (2,047)
Deferred Financing Costs ........................ -- (1,247) (51,450)
Goodwill ........................................ -- -- 2,492
(401) -- --
Net cash provided by (used in) Investing Activities .... ------------ ------------ ------------
14,100 (2,397) (55,104)
------------ ------------ ------------
F-7
For the Year Ended For the Year Ended For the Year Ended
December 31, 2004 December 31, 2003 December 31, 2002
----------------- ----------------- -----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Notes Receivable .................. $ 2,378 $ 2,425 $ 866
Payments of Long-term Debt ...................... (66,039) (3,930) (4,522)
Proceeds from Long-term Debt .................... 81,430 1,100 44,856
Debt Issuance Costs ............................. (9,531) -- --
Proceeds from Exercise of Options and Warrants .. -- -- 231
Deferred Royalty ................................ 5,686 -- --
Dividends on Preferred Stock .................... (828) (829) (831)
Minority Interests .............................. -- -- (613)
Advance from JV ................................. (101) -- --
------------ ------------ ------------
Net cash provided by (used in) Financing Activities .... 12,995 (1,234) 39,987
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH ........................ 24,677 5,810 (9,855)
Cash, Restricted Cash and Marketable Securities -
beginning of period ................................. 20,913 15,103 24,958
------------ ------------ ------------
CASH, RESTRICTED CASH AND MARKETABLE SECURITIES - END
OF PERIOD ........................................... $ 45,591 $ 20,913 $ 15,103
============ ============ ============
Supplemental Disclosure of Cash Flow Information:
Cash paid for Interest ....................... $ 7,445 $ 4,685 $ 5,350
============ ============ ============
Supplemental Schedule of Non-cash Financing
Activities:
Gain on Acquisition of Debt .................. 2,728 -- --
============ ============ ============
Contingent Notes Receivable ..................... 2,502 -- --
============ ============ ============
Note Receivable from Sale of Partnership Interest 14,000 -- --
============ ============ ============
State Taxes Paid 240 -- --
============ ============ ============
Conversion of Receivable to Investment by SEFL .. -- -- 5,085
============ ============ ============
Return of Treasury Stock ........................ -- 399 1,310
============ ============ ============
Issuance of Common Stock for investment interest
in SEFL ...................................... -- -- 675
============ ============ ============
Notes Receivable - SEFL ......................... -- 52,726 --
============ ============ ============
Long-Term Debt - SEFL ........................... $ -- $ 45,398 $ --
============ ============ ============
See notes to consolidated financial statements
which are an integral part of the financial statements
F-8
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL STOCKHOLDERS' EQUITY
FOR THE YEAR ENDED DECEMBER 31, 2004
(in thousands, except share data)
========================================================================================================================
Preferred Stock Preferred Stock Preferred Stock
Series B Series C Series D Treasury Stock
========================================================================================================================
No. of No. of No. of No. of No. of
Shares Amount Shares Amount Shares Amount Shares Amount Shares Amount
- ------------------------------------------------------------------------------------------------------------------------
Balance - Dec. 31,
2003 as previously
reported 368 -- 100,000 $ 1 1,138,88 $11 (445,930) $(2,204) 12,333,974 $ 123
Adjustments -- -- -- -- -- -- -- -- -- --
Balance - Dec. 31,
2003 as adjusted 368 -- 100,000 1 1,138,88 11 (445,930) (2,204) 12,333,974 123
Issuance of Common
Stock -- -- -- -- -- -- -- -- -- --
Othe Comprehensive
Income/(Loss) -- -- -- -- -- -- -- -- -- --
Treasury Stock -- -- -- -- -- -- -- -- -- --
Net Income for the
year ended
December 31, 2004 -- -- -- -- -- -- -- -- -- --
Dividends on
Preferred Stock: -- -- -- -- -- -- -- -- -- --
Series B -- -- -- -- -- -- -- -- -- --
Series C -- -- -- -- -- -- -- -- -- --
Series D -- -- -- -- -- -- -- -- -- --
- ------------------------------------------------------------------------------------------------------------------------
Balance -
December 31, 2004 368 -- 100,000 $ 1 1,138,88 $11 (445,930) $(2,204) 12,333,974 $123
========================================================================================================================
==============================================================================================
Common Stock
==============================================================================================
Foreign
Additional Currency
Paid in Translation Accumulated
Capital Adjustment Deficit Total
- ----------------------------------------------------------------------------------------------
Balance - Dec. 31,
2003 as previously
reported $64,891 $ 422 $(24,159) $ 39,085
Adjustments -- -- -- --
Balance - Dec. 31,
2003 as adjusted 64,891 422 (24,159) 39,085
Issuance of Common
Stock -- -- -- --
Othe Comprehensive
Income/(Loss) -- 1,259 -- 1,259
Treasury Stock -- -- -- --
Net Income for the
year ended
December 31, 2004 -- -- 644 644
Dividends on
Preferred Stock: -- -- -- --
Series B (33) -- -- (33)
Series C (180) -- -- (180)
Series D (615) -- -- (615)
- ----------------------------------------------------------------------------------------------
Balance -
December 31, 2004 $64,063 $ 1,681 $(23,516) $ 40,160
==============================================================================================
See notes to consolidated financial statements
which are an integral part of the financial statements
F-9
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL STOCKHOLDERS' EQUITY
FOR THE YEAR ENDED DECEMBER 31, 2003
(In thousands, except share data)
=====================================================================================================================
Preferred Stock Preferred Stock Preferred Stock
Series B Series C Series D Treasury Stock
=====================================================================================================================
No. of No. of No. of No. of No. of
Shares Amount Shares Amount Shares Amount Shares Amount Shares Amount
- ---------------------------------------------------------------------------------------------------------------------
Balance - Dec.31,
2002 as previously
reported 368 -- 100,000 $ 1 1,138,888 $ 11 (383,450) $ (1,805) 12,333,613 $123
Adjustments -- -- -- -- -- -- -- -- --
Balance - Dec.31,
2002 as adjusted 368 -- 100,000 1 1,138,888 11 (383,450) (1,805) 12,333,613 123
Shares Issued for
Exercised Options and
Warrants -- -- -- -- -- -- -- -- --
Issuance of Common
Stock -- -- -- -- -- -- -- 361 --
Treasury Stock -- -- -- -- -- 62,480 (399) -- --
Other Comprehensive
Income/(Loss) -- -- -- -- -- -- -- -- --
Net Loss for the year
ended December 31,
2003 -- -- -- -- -- -- -- -- --
Dividends on
Preferred Stock:
Series B -- -- -- -- -- -- -- -- --
Series C -- -- -- -- -- -- -- -- --
Series D -- -- -- -- -- -- -- -- --
- ---------------------------------------------------------------------------------------------------------------------
Balance -
December 31, 2003 368 -- 100,000 $ 1 1,138,888 $ 11 (445,930) $ (2,204) 12,333,974 $123
=====================================================================================================================
==============================================================================================
Common Stock
==============================================================================================
Foreign
Additional Currency
Paid in Translation Accumulated
Capital Adjustment Deficit Total
- ----------------------------------------------------------------------------------------------
Balance - Dec.31,
2002 as previously
reported $65,720 $ 701 $(23,154) $ 41,597
Adjustments -- -- (2,843) (2,843)
Balance - Dec.31,
2002 as adjusted 65,720 -- -- --
Shares Issued for
Exercised Options and
Warrants -- -- -- --
Issuance of Common
Stock
Treasury Stock -- -- -- --
Other Comprehensive
Income/(Loss) -- (279) -- (279)
Net Loss for the year
ended December 31,
2003 -- -- $ 1,838 1,838
Dividends on
Preferred Stock:
Series B (34) -- -- (34)
Series C (180) -- -- (180)
Series D (615) -- -- (615)
- ----------------------------------------------------------------------------------------------
Balance -
December 31, 2003 $64,891 $ 422 $(24,159) $ 39,085
==============================================================================================
See notes to consolidated financial statements
which are an integral part of the financial statements
F-10
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN TOTAL STOCKHOLDERS' EQUITY
FOR THE YEAR ENDED DECEMBER 31, 2002
(In thousands, except share data)
=======================================================================================================================
Preferred Stock Preferred Stock Preferred Stock
Series B Series C Series D Treasury Stock
=======================================================================================================================
No. of No. of No. of No. of No. of
Shares Amount Shares Amount Shares Amount Shares Amount Shares Amount
- -----------------------------------------------------------------------------------------------------------------------
Balance - Dec.31,
2001 as previously
reported 368 -- 100,000 $ -- 1,138,888 $ 11 (114,700) $ (495) 12,065,000 $ 121
Adjustments -- -- -- -- -- -- -- -- --
Balance - Dec.31,
2001 as adjusted 368 -- 100,000 -- 1,138,888 11 (114,700) (495) 12,065,000 121
Shares Issued for
Exercised Options and
Warrants -- -- -- -- -- -- -- -- 120,637 1
Issuance of Common
Stock -- -- -- -- -- -- -- -- 147,976 1
Treasury Stock -- -- -- -- -- -- (268,750) (1,310) -- --
Other Comprehensive
Income/(Loss) -- -- -- -- -- -- -- -- -- --
Net Loss for the year
ended December 31,
2002 -- -- -- -- -- -- -- -- -- --
Dividends on
Preferred Stock:
Series B -- -- -- -- -- -- -- -- -- --
Series C -- -- -- -- -- -- -- -- -- --
Series D -- -- -- -- -- -- -- -- -- --
- -----------------------------------------------------------------------------------------------------------------------
Balance -
December 31, 2002 368 -- 100,000 $ -- 1,138,888 $ 11 (383,450) $(1,805) 12,333,613 $ 123
=======================================================================================================================
==============================================================================================
Common Stock
==============================================================================================
Foreign
Additional Currency
Paid in Translation Accumulated
Capital Adjustment Deficit Total
- ----------------------------------------------------------------------------------------------
Balance - Dec.31,
2001 as previously
reported $ 65,647 $ 406 $ (7,733) $ 57,958
Adjustments -- -- (2,116) (2,116)
Balance - Dec.31,
2001 as adjusted 65,647 406 (9,849) 55,842
Shares Issued for
Exercised Options and
Warrants 230 -- -- 231
Issuance of Common
Stock 674 -- -- 675
Treasury Stock -- -- -- (1,310)
Other Comprehensive
Income/(Loss) -- 295 -- 295
Net Loss for the year
ended December 31,
2002 -- -- (16,148) (16,148)
Dividends on
Preferred Stock:
Series B (36) -- -- (36)
Series C (180) -- -- (180)
Series D (615) -- -- (615)
- ----------------------------------------------------------------------------------------------
Balance -
December 31, 2002 $ 65,720 $ 701 $(25,997) $ 38,754
==============================================================================================
See notes to consolidated financial statements
which are an integral part of the financial statements
F-11
U.S. ENERGY SYSTEMS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
NOTE A -- SIGNIFICANT ACCOUNTING POLICIES
Significant accounting policies followed in the preparation of the financial
statements are as follows:
(1) Consolidation. The consolidated financial statements of the Company
include the accounts of the Company and its wholly owned and majority-owned
subsidiaries. All inter-company accounts and transactions have been eliminated
in the consolidation. Certain items in 2003 have been reclassified to conform
with this year's presentation.
(2) Statement of Cash Flows and Equivalents. For purposes of reporting
cash flows, cash and marketable securities include cash on hand and investments
in equities and debt instruments with short term liquidity. All carrying amounts
approximate fair value.
(3) Property, Plant and Equipment. Property, plant and equipment is stated
at cost and is depreciated using the straight-line method over their estimated
useful lives ranging from three to 40 years with the power generation plants
between 15 to 25 years.
(4) Investments in Joint Ventures. Investments in joint ventures are
accounted for under the equity method.
(5) Goodwill and Other Long-Lived Assets. Goodwill represents the excess
of the cost of acquired companies over the fair value of their tangible net
assets acquired. The periods of amortization of goodwill and other long-lived
assets are evaluated at least annually to determine whether events and
circumstances warrant revised estimates of useful lives. This evaluation
considers, among other factors, expected cash flows and profits of the business
to which the goodwill and other long-lived assets relate. More specifically, the
Company performed a discounted cash flow analysis using a risk adjusted rate of
return, commensurate with specific business or asset characteristics and
potential business opportunities for the investment. Significant estimates
utilized in the discounted cash flow analysis include the amount of landfill gas
available for power generation, the rate paid for the power generation and the
investment yields on the investment of the Illinois Accounts. Changes in the
actual results compared to these estimates would effect the valuation of
goodwill.
In June 2001, the FASB issued Statement of Financial Accounting Standards No.
141, Business Combinations (SFAS 141), and No. 142, Goodwill and Other
Intangible Assets (SFAS 142). SFAS 141 requires all business combinations
initiated after June 30, 2001, to be accounted for using the purchase method.
With the adoption of SFAS 142, goodwill and other intangibles with indefinite
lives will no longer be subject to amortization. SFAS 142 requires that goodwill
be assessed for impairment upon adoption and at least annually thereafter by
applying a fair-value-based test, as opposed to the undiscounted cash flow test
applied under prior accounting standards. This test must be applied at the
"reporting unit" level, which is not permitted to be broader than the current
business segments. Under SFAS 142, an acquired intangible asset should be
separately recognized if the benefit of the intangible asset is obtained through
contractual or other legal rights, or if the intangible asset can be sold,
transferred, licensed, rented, or exchanged, regardless of the acquirer's intent
to do so.
We began applying SFAS 141 in the third quarter of 2001 and SFAS 142 in the
first quarter of 2002. The discontinuance of amortization of goodwill, which
began in the first quarter of 2002, was not material to our financial position
or results of operations. In 2004 and 2003, an impairment test of the goodwill
resulting from the acquisition of USEB was performed with no change in the
valuation. We will continue to perform goodwill impairment tests annually, as
required by SFAS 142, or when circumstances indicate that the fair value of a
reporting unit has declined below the amount necessary to maintain the goodwill
valuation.
F-12
Goodwill at December 31, 2004 and 2003 is presented net of amortization of $592.
Amortization has ceased with the adoption of SFAS No. 142. Goodwill was adjusted
in 2004 to reflect the payment of additional compensation to the former USEB
shareholders per the terms of the 2001 merger agreement.
(6) Per Share Data. Income (Loss) per share is computed by dividing income
available to common stockholders by the weighted average number of common shares
outstanding during the periods. In arriving at income available to common
stockholders, preferred stock dividends have been deducted. Potential common
shares have not been included due to their anti-dilutive effect for 2002 and
2004.
(7) Use of Estimates. The preparation of financial statements in
conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Estimates are utilized in
the value of Goodwill, Deferred Revenue and Installment Sales Receivable.
Estimates of landfill gas production, investment returns on reserve accounts,
inflation and energy rates are utilized in the valuation of these items. Actual
results may differ from the estimates used thereby effecting the future
valuation of the items.
(8) Fair Values of Financial Instruments. The estimated fair value of
financial instruments has been determined based on available market information
and appropriate valuation methodologies. The carrying amounts of cash, accounts
receivable, other current assets, accounts payable and accrued expenses payable
approximate fair value at December 31, 2004 and 2003 because of the short
maturity of these financial instruments. The estimated carrying value of the
Installment Sale Partnership Interests and long term debt are either contractual
or approximate fair value. The fair value estimates were based on information
available to management as of December 31, 2004 and 2003. If subsequent
circumstances indicate that a decline in the fair market value of a financial
asset is other than temporary, the financial instrument is written down to its
fair market value.
(9) Impairment of Long-Lived Assets. We evaluate long-lived assets for
impairment when events or changes in circumstances indicate that the carrying
value of such assets may not be recoverable. The determination of whether an
impairment has occurred is based on an estimate of the net present value,
discounted at an amount approximating our cost of capital, of the future cash
flows attributable to the assets, compared with the carrying value of the
assets. If an impairment has occurred, the amount of the impairment recognized
is determined by estimating the fair value of the assets and recording a
provision for an impairment loss if the carrying value is greater than the fair
value. Until the assets are disposed of, their estimated fair value is
reevaluated when circumstances or events change. There were no impairment of
assets in the year 2003 or 2004.
(10) Stock-Based Compensation. The Company accounts for its stock-based
compensation plans using the intrinsic value method prescribed by Accounting
Principles Board Opinion No. 25 (APB No. 25), Accounting for Stock Issued to
Employee's and discloses the pro forma effects on net loss and loss per share
had the fair value of options been expensed. Under the provisions of APB No. 25,
compensation arising from the grant of stock options is measured as the excess,
if any, of the quoted market price of the Company's common stock at the date of
grant over the amount an employee must pay to acquire the stock.
(11) Concentration of credit risk. A significant portion of the Company's
revenues are derived from investment grade utilities, and government and
industrial customers. They have contracted with the Company to purchase energy
over various terms. The concentration of credit with investment grade customers
reduces the Company's overall credit exposure.
The Company maintains demand deposits in excess of $100 with individual banks.
The Federal Deposit Insurance Corporation does not insure amounts in excess of
$100.
(12) Debt Issuance Costs. Debt issuance costs are amortized on a
straight-line basis over the terms of the related financing. For 2004, 2003 and
2002, amortization expense was $670, $339 and $200, respectively. The
unamortized balance on December 31, 2004 was $11,266. This will be amortized
over the remaining term of the respective debt. The amortization expense will be
approximately $795 per annum for the remaining term of the financing which
matures in 2019.
F-13
(13) Deferred Revenues. Deferred revenues primarily represent gains to be
recognized from the sale of the Company's limited partnership interests in
certain partnerships, further described. The majority of the proceeds from the
sale are to be paid in installments, the amount of which will be determined by
production and the value of benefits received by the purchasers; therefore, the
gain will be recognized as payments are received. In June, 2004 Deferred
Revenues were reduced by $2,502 to reflect revised estimates of the total amount
to be realized under the contingent note receivable from AJG to their
acquisition of various gasco interests. The decrease in deferred revenues was
offset by a decrease in Installment Note Receivable and did not result in any
charges against income.
(14) Income Taxes. The Company uses the liability method of accounting for
income taxes. Deferred income taxes result from temporary differences between
the tax basis of assets and liabilities and the basis as reported in the
consolidated financial statements. Differences in the timing of gain recognition
and the utilization of tax net operating losses constitute the majority of the
deferred tax asset. Income taxes have been accrued on the undistributed earnings
of all subsidiaries.
(15) Foreign Currency. The functional currency for all of our foreign
operations is the local currency. For these foreign entities, we translate
income statement amounts at average exchange rates for the period, and we
translate assets and liabilities at the end-of-period exchange rates. We report
exchange gains and losses on inter-company foreign currency transactions of a
long-term nature in Accumulated Other Comprehensive Income.
(16) Revenue Recognition. Revenues are recognized upon delivery of energy
or service.
(17) Expense Recognition. Expenses are recognized when the liability is
incurred.
(18) Capitalization Policy. The Company has major holdings in revenue
producing property, plant and equipment, it is critical to adhere to maintenance
and overhaul schedules to keep the equipment in good condition. For accounting
purposes it is equally important to discern and account for these two activities
properly. Unscheduled maintenance that does not extend the useful life of the
asset or enhance production is recognized as operations and maintenance expense
in the period incurred. Scheduled overhauls and major repairs that either extend
the useful life or enhance production are normally capitalized and depreciated
over the time until the next scheduled overhaul.
(19) Investments in Derivatives. The Company holds derivative financial
instruments for the sole purpose of hedging the risk of identifiable
transactions. The types of risks hedged are those relating to changes in foreign
currency exchange rates, the variablility of which impacts future earnings and
cash flows. The Company documents its risk management strategy and hedge
effectiveness at the inception of and during the term of the hedge. Changes in
the fair market value of derivatives are recorded each period in other
comprehensive income. For fair market value hedge transactions, changes in the
fair market value of the derivative instrument are generally offset in the
income statement by changes in the fair value of the item being hedged. For cash
flow hedge transactions, changes in the fair value of the derivative instrument
are reported in other comprehensive income.
NOTE B -- SUBSIDIARIES AND AFFILIATES
(1) U.S. Energy Biogas Corp. ("USEB"). On May 11, 2001 we, together with
Cinergy Energy Solutions, Inc. ("Cinergy Energy"), acquired through a merger,
Zahren Alternative Power Corporation ("Zapco"), and renamed such entity U.S.
Energy Biogas Corp. ("Biogas"). We own 54.26% and Cinergy Energy, a wholly owned
subsidiary of Cinergy Corp. ("Cinergy"), owns 45.74% of Biogas.
(2) USE Canada Energy Corp. ("USE Canada"). On June 11, 2001 USE Canada
Acquisition Corp., a wholly-owned Canadian subsidiary of the Company, purchased
100% of the issued and outstanding stock of Trigen Energy Canada Company, and
renamed it USE Canada Energy Corp. ("USE Canada"). Effective December 31, 2003
USE Canada became a discontinued operation pending its sale to the Countryside
Fund. On April 8, 2004, USE Canada was sold to the Countryside Fund.
F-14
(3) U.S. Energy Geothermal, LLC ("Geothermal"). Our former 95%-owned
subsidiary, U.S. Energy Geothermal, LLC ("Geothermal"), owned two geothermal
power plants in Steamboat Hills, Nevada. The Company sold its 95% interest in
Geothermal in June 2003 for approximately $1 million.
(4) Scandinavian Energy Finance, Limited /EnergiSystems I Sverige
AB("SEFL"). During the three month period ended March 31, 2004, the Company
reserved its entire $8,200 investment in SEFL due to pending litigation.
On July 8, 2004 in the context of an overall settlement of the litigation, SEFL
sold its loan and equity investments in ESS to its primary lender,
Lantbrukskredit AB ("LBK) for 35,500 Kronor and a release of SEFL and its
shareholders from all obligations under the financing agreements with LBK. In
addition, USEY and ESS terminated their service agreement. From the 35,500
Kronor received from LBK, SEFL paid the Company $1,100 as repayment of an
intercompany loan from the Company to SEFL. Since the amount reserved for SEFL
included this intercompany loan, the $1,100 was recognized during the third
quarter of 2004 as a reduction in the reserve amount.
NOTE C -- RECENT ACCOUNTING PRONOUNCEMENTS
The FASB issued Interpretation No. 46, Consolidation of Variable Interest
Entities in January 2003. This interpretation will significantly change the
consolidation requirements for special purpose entities (SPE). The Company
currently does not have any SPE's that it does not consolidate on its financial
statements.
In December 2003, the FASB issued SFAS No. 123R, "Share Based Payment" which
eliminates the alternative to measure stock-based compensation awards using the
intrinsic value approach permitted by Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock-Based Compensation" and by SFAS No. 123
Accounting for Stock-Based Compensation. As discussed in Note A, the Company
adopted the fair value method of acounting for stock-based compensation
provisions of SFAS No. 123 and the retroactive transitional provisions of SFAS
No. 148, "Accounting for Stock Based Compensation - Transition and Disclosure."
As a result, the Company has been recording stock-based compensation expense for
all employee stock awards that were granted or modified, and the adoption of
SFAS No. 123R is not expected to have a material effect on the consolidated
financial statements.
NOTE D -- RESTRICTED CASH AND MARKETABLE SECURITIES
USEB's financing arrangements with Countryside Power Canada , Inc. (the
"Countryside Fund") established various reserve accounts which are also
collateral for the financing with the Countryside Fund. These accounts include
the Illinois Subsidy Liability Reserve Account, a debt service reserve account
and an improvement reserve account. The funds held in the improvement reserve
account can be utilized to fund capital expenditures. The funds in the Illinois
Subsidy Liability Reserve Account (the "Illinois Accounts") are to be utilized
to retire the Illinois subsidy liability as it becomes due. See Note E.
Restricted cash and marketable securities as of December 31, 2004 consisted of
the following:
Illinois Subsidy Liability Reserve Accounts $ 23,438
Improvement Reserve 4,022
Debt Service Reserve 2,011
Project Contract Reserve 138
------------
$ 29,609
============
Included in the Illinois Subsidy Liability Reserve Accounts is $21,428 that is
managed by a professional investment manager under investment allocation
parameters established by the Company. The amounts managed by the professional
manager, as of December 31, 2004, included $13,352 invested in equity fund
accounts, $6,945 invested in debt accounts, and $1,131 being held in cash or
cash equivalent accounts. The cost basis of the investments, which have been
invested since July 2004, is $20,182. See Note E below for additional
information pertaining to the Illinois Accounts.
NOTE E - ILLINOIS RETAIL RATE PROGRAM
USEB has 10 operating projects in Illinois which are receiving a subsidy for
each kilowatt hour ("kwh") of electricity sold to the local utility under the
Illinois Retail Rate Program. In accordance with the Illinois Retail Rate
Program, the utility has contracted, for a ten year period, with each project to
purchase electricity for an amount that exceeds the utility's Avoided Cost (what
it would otherwise pay for the generation of electricity). The excess paid above
avoided cost is the subsidy. The utility then receives a tax credit from the
State of Illinois ("Illinois") equal to the amount of that excess. Each project
is obligated to begin to repay the subsidy to Illinois after the project has
recouped its capital investment and retired all debt associated with the
financing and construction of the project but,
F-15
in any case, no later than 10 years from the date the project commenced
commercial operations. All subsidy liabilities must be fully repaid to Illinois
(without interest) by the end of the actual useful life of the project but no
later than 20 years from the date the project commenced commercial opertions.
This subsidy is accounted for GAAP purposes in a manner similar to an original
issue discount whereby the amount to be repaid in the future is discounted to
its net present value and the discount is amortized (as interest expense) over
the 10-year period until repayment begins. The amount of power generation
revenue recognized each period is equal to the Avoided Cost rate plus the
difference between the subsidy received by the project and the net present value
of the subsidy. This unamortized discount and the liability are shown net on the
consolidated balance sheet as Rate Subsidy Liability.
USEB is required by the Countryside Fund to deposit funds into the Illinois
Accounts for repayment of the Illinois subsidy liability. The Illinois Accounts
are classified as restricted cash and marketable securities. The amount
deposited into the Illinois Accounts is based upon the amount of subsidy
received and contemplates an annual return sufficient to fund the current period
subsidy liability repayment as it becomes due. Regular deposits combined with
actual and expected returns on those deposits may not be sufficient to fully
repay the respective liabilities as they become due. Should the amounts in the
Illinois Accounts be insufficient to fully repay the obligations, any shortfall
would have to be funded from the project's operations or assets.
Following is a summary of significant dates pertaining to a project's
participation in the Illinois Retail Rate Program.
Estimated
Commencement of Expiration of Commencement
Commerical Illinois Retail of Repayment of
Project Operations Rate Program Subsidy Liability(1)
- --------------------------------------------------------------------------------
Countryside April, 2001 April, 2011 May, 2011
Dolton May, 1998 May, 2008 June, 2008
Dixon Lee July, 1999 July, 2009 August, 2009
Morris December, 2000 December, 2010 January, 2011
Roxana November, 1999 November, 2009 December, 2009
Upper Rock April, 2000 April, 2010 May, 2010
122nd Street July, 1998 July, 2008 August, 2008
Brickyard September, 1999 September, 2009 October, 2009
Streator January, 2000 January, 2010 February, 2010
Willow Ranch January, 1998 January, 2009 February, 2009
- --------------------------------------------------------------------------------
(1) The estimated commencement of the repayment of the liability is
based upon management's assumptions. One year before a project's
eligibility for participation in the program terminates, a proposed
repayment schedule must be presented to the Illinois Commerce
Commission for their approval. Until any repayment schedule is
approved by the Illinois Commerce Commission, it will continue to be
an estimated schedule.
The funds held in the Illinois Accounts are currently invested in equities and
fixed income securities. These investments are being managed by a third-party
professional money manager with the investment allocations being approved by the
management of the Company and USEB. The amount held in the Illinois Accounts as
of December 31, 2004 was $23,438. The amount of the subsidy liability owed to
Illinois as of December 31, 2004 was $49,028. It is anticipated that repayments
of the incentive will begin in 2008 and continue through 2021.
Under the terms of the Illinois Retail Rate Program, estimated rates are paid
for production sold to the utility with that rate being trued up annually, on
the anniversary date of the commencement of commercial operations of the
applicable project, to the actual rates paid for electricity by the local
municipality. After the actual rate is determined, sales for the preceding
calendar year, retroactive to the last anniversary date, are adjusted based upon
the actual rate. If the actual rate is greater than the estimated rate,
additional sales proceeds are paid to the project. If the actual rate is less
than the estimated rate, then prior sales proceeds received, equal to the excess
amounts paid, must be refunded to the utility. This actual rate then becomes the
estimated rate for the subsequent year.
F-16
During 2004, retail rates for three of the Illinois projects, Morris, Dixon Lee
and 122nd Street decreased by 27%, 26% and 40% per kwh, respectively. These
retroactive rate reductions resulted in a decrease in revenues of $867 in 2004.
In the past, the annual reconciliation of estimated rates to actual rates has
resulted in both increases and decreases in retroactive revenue. USEB has
participated in the Illinois Retail Rate program since 1998 and has never
experienced rate reconciliation changes of this magnitude. USEB has requested,
but never received, an explanation from Commonwealth Edison. USEB has a total of
10 projects in Illinois, representing 64% of its Power Generation Revenues. USEB
cannot predict whether any other major decreases in revenues from the Illinois
projects are likely.
From time to time during the past few years and in 2004 and 2005, the Governor
and/or Lieutenant Governor of Illinois and member of the Illinois legislature
have proposed changes to or the elimination of the Illinois Retail Rate Program
and have introduced legislation to that effect. While legislation has not been
adopted, the adoption of legislation or the implementation of rules that would
reduce or eliminate the benefits received by the Company under this program
would have a material adverse effect on the Company.
NOTE F -- TRANSACTIONS WITH AFFILIATES
USEB is a general partner in alternative energy and equipment finance
transactions with related limited partnerships and collects management fees from
the partnerships. Fees earned from such general partner undertakings amount to
$459 for the year ended December 31, 2004, $401 for the year ended December 31,
2003 and $140 for the year ended December 31, 2002.
USEB reimburses the Company for a majority of the costs incurred by them for the
benefit of USEB. These costs include management and accounting salary and
benefit costs, office expenses associated with the accounting services and an
allocation of rent expenses. The total reimbursements for 2004, 2003 and 2002
were $639, $2,442 and $1,773, respectively.
NOTE G -- INSTALLMENT SALE PARTNERSHIP INTEREST AND INTEREST RECEIVABLE
Installment Sale Partnership Interest consist of four notes pertaining to USEB's
sale of its limited partnership interests in several Gasco entities. Payments of
principal and interest on the three contingent installment notes are made
quarterly based upon the amount of landfill gas sold and the value of the tax
credits generated by the sale. Payments of principal and interest on the Fixed
Installment Notes are made quarterly based upon a mortgage style amortization.
In June 2004, the contingent installment note receivable for the 1999 sale of
gasco interests was written down by approximately $2,500 to reflect updated
projections for the amount of gas projected to be sold and the dollar value of
payments required under the contingent note. The write down of the note
receivable was offset by an equal reduction in deferred revenue and did not
result in a charge to operating income.
On April 8, 2004, AJG Financial Services, Inc. ("AJG") made a cash down payment
of $2,000 and delivered a $14,000 note payable to a subsidiary of USEB to
satisfy its obligation to pay for certain ownership interests in Illinois based
generating project entities AJG had previously acquired. The note matures in
2024, requires scheduled payments of principal and interest and bears interest
at a rate of 15% per annum. Payments on the note are limited to cash
distributions from the project entities with any excesses to the scheduled
payments being applied as an additional principal payment and any deficits to
scheduled payments being deferred. This transaction resulted in a gain for USEB
of $16,000 which was recognized in June, 2004.
F-17
Notes receivable as of December 31, 2004 consisted of the following:
(Dollars in thousands)
- -------------------------------------------------------------------------------------------------
Interest Current Long-Term
Rate Portion Portion
- -------------------------------------------------------------------------------------------------
Contingent Installment Note Receivable for 1999 Sale of
GASCO Interests Secured by the Interests 9.47% $ 621 $ 3,814
Fixed Installment Note Receivable for 2001 Sale of GASCO
Interests Secured by the Interests 6.00% 510 825
Contingent Installment Note Receivable for 2001 Sale of
GASCO Interests Secured by the Interests 6.00% 510 4,586
Contingent Notes Receivable for Sale of Barre, MA
Project's Gas Collection System and Related Assets,
Secured by the Interests 10.00% 10 533
Installment Note Receivable From AJG For Illinois
Electric Generation Partners II
Secured by Ownership Interests 15.00% 220 13,780
Accrued Interest Receivable -- 623 --
---------- ----------
$ 2,494 $ 23,538
========== ==========
A comparable breakdown as at December 31, 2003 is as follows:
(Dollars in thousands)
- -------------------------------------------------------------------------------------------------
Interest Current Long-Term
Rate Portion Portion
- -------------------------------------------------------------------------------------------------
Contingent Installment Note Receivable for 1999 Sale of
GASCO Interests Secured by the Interests 9.47% $ 1,090 $ 6,220
Fixed Installment Note Receivable for 2001 Sale of GASCO
Interests Secured by the Interests 6.00% 481 1,334
Contingent Installment Note Receivable for 2001 Sale of
GASCO Interests Secured by the Interests 6.00% 719 4,898
Contingent Notes Receivable for Sale of Barre, MA
Project's Gas Collection System and Related Assets,
Secured by the Interests 10.00% 10 535
Installment Note Receivable From AJG For Illinois
Electric Generation Partners II
Secured by Ownership Interests 15.00% 0 0
Accrued Interest Receivable 378 --
---------- ----------
$ 2,678 $ 12,987
========== ==========
F-18
A Gasco project is a project level entity (normally a limited partnership for
which Biogas or a Biogas subsidiary normally serves as general partner), which
collects and sells biogas to an affiliated project level entity (a "Genco"),
which uses the biogas to generate electricity.
USEB sold its limited partnership interests in several Gasco's during December
1999 to a current stockholder of the Company. The total sales price was
approximately $22,000 including interest imputed at 9.47%. A down payment of
approximately $4,285 was received in 1999. The balance of the sales proceeds
will be received based on the actual gas production of the projects over six
years. A gain on this sale of $49, and $182 was recognized in 2003 and 2002
respectively. There was no gain recongized in 2004 as the balance in the
deferred revenue account was written off against the note receivable balance to
reflect revised production and payment projections.
In 2001, USEB sold limited partnership interests in three other Gasco entities.
The purchaser was AJG Financial Services. The total purchase price was
approximately $12,300 including interest and consisted of a down payment of
$1,000 and two long-term notes receivable; one calling for fixed quarterly
payments of $145 and the other calling for contingent quarterly payments based
on actual gas production. Both bear interest at 6% per annum. Gains of $401,
$174 and $145 were recognized on the contingent note in 2004, 2003 and 2002,
respectively. Consistent with accounting principles generally accepted in the
United States for this transaction, the remaining deferred gain of $3,097 for
2004 relates to the contingent note and will be recognized over the remaining
three years as payments are received.
NOTE H -- PROPERTY, PLANT AND EQUIPMENT
Power generation and gas transmission assets consist primarily of the value of
the internal combustion engines and related equipment located at the landfill
gas to energy projects. The majority of these assets are depreciated using the
straight-line method over the useful life of the assets for financial statement
purposes.
Other property and equipment as of December 31, 2004 and 2003 consists of site
tools, office furniture, computer equipment and company vehicles. These assets
are depreciated over lives ranging from three to ten years.
Consolidated property, plant and equipment consist of the following at December
31, 2004 and 2003:
(Dollars in thousands) 2004 2003
---------- ----------
Land ................................................. $ 98 $ 98
Generation and Transmission Equipment and Peripherals 65,780 64,048
Other Property and Equipment ......................... 557 1,333
---------- ----------
$ 66,435 $ 65,479
Less Accumulated Depreciation ........................ (24,534) (21,750)
---------- ----------
$ 41,901 $ 43,729
=========== ==========
The decrease in Other Property and Equipment to $557 as of December 31 ,2004
from $1,333 as of December 31, 2003 is the result of the write off of fully
depreciated assets no longer in service.
NOTE I -- INVESTMENTS
Our total investments, including joint ventures, as of December 31, 2004 and
2003 are as follows:
(Dollars in thousands)
December 31, 2004 December 31, 2003
----------------- -----------------
SEFL ....................... -- 6,336
Plymouth Cogeneration ...... 345 347
Various Holdings of USEB ... 456 1,568
------------ ------------
Total Investments .......... $ 801 $ 8,251
============ ============
F-19
Plymouth Envirosystems, Inc. Our wholly owned subsidiary, Plymouth
Envirosystems, Inc., owns a 50% interest in Plymouth Cogeneration Limited
Partnership ("Plymouth Cogeneration") which owns and operates a CHP plant
producing 1.2 MW of electricity and 7 MW of heat at Plymouth State College, in
Plymouth, New Hampshire. The Plymouth Facility provides 100% of the electrical
and heating requirements for the campus, which is a part of the University of
New Hampshire system, under a long-term contract.
The day-to-day operations of the Plymouth Facility are managed by one of our
partners in this project, and management decisions are made by a committee
composed of representatives of the three partners in this project. The Company
reports gains from its investment in Plymouth Cogeneration under the category
Gain from Joint Venture in the financial statements. The gains recorded for
2004, 2003 and 2002 were $125, $72 and $72, respectively.
Lehi Envirosystems, Inc. In 1997, our wholly-owned subsidiary, Lehi
Envirosystems, Inc. ("LEHI"), acquired a 50% equity interest in Lehi Independent
Power Associates ("LIPA"), which owns a cogeneration facility in Lehi, Utah (the
"Lehi Facility") and the underlying real estate. The Lehi Facility has been
dormant since 1990. The Company does not record any asset value for this
invesment on its books but continues to record operating losses allocated from
LIPA under the category Gain from Joint Ventures in the financial statements.
The losses recorded for 2004, 2003 and 2002 were $7, $8 and $847 respectively..
SEFL. The Company's net investment in SEFL was written off in 2004. See Note B
for discussion of SEFL
NOTE J -- DEBT ISSUANCE COSTS
Debt Issuance costs consists of $11,859 of costs associated with the the
Countryside Fund transaction less $593 of accumulated amortization. Costs
included in the amount include legal and accounting expenses, underwriters fees
and other costs incurred completing this transaction. These costs will be
amoritzed over the 15 year term of the loan with annual amortization
approximating $795.
NOTE K -- LONG-TERM DEBT
Long Term Debt - Countryside Fund
On April 8, 2004, the Countryside Fund, an unincorporated open-ended, limited
purpose trust formed under the laws of the Province of Ontario, Canada acquired
the outstanding balance of existing USEB loans from John Hancock Life Insurance
Companies, ABB Energy Capital and AJG, a shareholder of the Company.
Immediately following the acquisition of the loans, the Countryside Fund and
USEB amended the existing loan agreements to denominate the loans in Canadian
currency, to provide an additional loan amount of $23,843 and to provide for a
remaining term of 15 years with a balloon payment at the maturity date of
$35,100. In connection with the amendment of the loans, USEB paid related costs
of $16,994. The amendment established several reserve accounts including a
$4,000 improvement reserve with funds to be utilized to expand USEB and a $2,000
debt service reserve. In addition, $8,200 of loan proceeds were deposited into
the Illinois Accounts. Immediately upon completion of the transaction, the total
amount owed to the Countryside Fund by USEB was CAD$107,000 which was equal to
US$81,431 based upon the currency exchange rate of US$0.76 per Canadian dollar
at the date of closing. The loan is secured by the USEB assets and bears
interest at a rate of 11% per annum. As of December 31, 2004, the amount of the
debt outstanding was $80,521.
The loan agreement with the Countryside Fund requires USEB to deposit $250 per
calendar quarter into the debt service reserve fund provided that cash
available, as defined in the loan agreement, is at a certain level. USEB was
only required to make $84 of additional deposits into the debt reserve fund
during 2004. Until an amount is deposited in the reserve equal to $250 per
quarter since the April 8, 2004 closing, USEB is precluded from making dividend
or royalty interest payments or from expending funds to expand its production or
capacity.
F-20
Due to the requirement in the amended loan documents that payments be made to
the Countryside Fund in Canadian dollars, USEB has entered into a three year
hedge agreement with a financial institution fixing the US dollar to the
Canadian dollar exchange rate at US$0.76 per Canadian dollar through March 31,
2007. According to the terms of the loan agreement with the Countryside Fund,
USEB is required to maintain a foreign currency hedge agreement for a minimum of
75% of the remaining debt service payments. After the expiration of the hedge
agreement, USEB will be at risk for fluctuations in the currency exchange rate
should the rate vary from the exchange rate existing in the expiring hedge
agreement.
Scheduled principal payments for the periods indicated on the Long Term Debt
owed to the Countryside Fund are as follows:
Year Amount
---- ------
2005 $1,373
2006 1,532
2007 1,710
2008 1,908
2009 2,128
As discussed above, the amount of the principal payment after March 31, 2007 ,
as denominated in US dollars, may fluctuate depending upon the currency exchange
rate at that time. Principal payments listed above for 2007, 2008 and 2009 are
based upon the hedged currency exchange rate then currently in effect and no new
hedge agreement is in place.
The notes payable to the Countryside Fund are senior secured notes utilizing
USEB's assets as collateral. The terms require that USEB maintain a minimum
fixed charge coverage ratio, as defined in the loan agreements of 1.10 to 1 in
2004, 1.15 to 1 for 2005 and 1.25 to 1 thereafter. The fixed charge coverage
ratio is calculated based upon operating results for the preceding four fiscal
quarters or, if four fiscal quarters have not elapsed since the closing of the
refinancing, for the number of quarters that have elapsed. The ratio is
calculated after deducting deposits made into the Illinois Accounts. Failure to
maintain the minimum fixed charge coverage ratio is a default under the terms of
the loan agreement. The fixed charge coverage ratio for the three fiscal
quarters ended December 30, 2004 was 1.16 to 1.
Note Payable to AJG Financial Services, Inc.
On September 30, 2004, USEB purchased the subordinated note owed by USEB to AJG.
The outstanding principal amount of $5,729 plus outstanding accrued interest was
purchased for $3,000. Funds for the acquisition were provided by equity
contributions to USEB from the USEB shareholders. The purchase resulted in a
gain of $2,729 to USEB. The gain represents the amount of the acquisition price
below the note's face value.
A breakdown of the Company's debt as of December 31, 2004 and 2003 follows:
(Dollars in thousands)
Issuer/Lender December 31, 2004 December 31, 2003 Maturity Interest Rate
- -------------------------------- ----------------- ----------------- ----------------- ------------------
Debt
Countryside Canada Power Inc. $ 80,521 $ 0 2019 11.00%
John Hancock - Series A (1) 0 33,511 2014 9.47%
John Hancock Series A(2) 0 2,774 2014 9.37%
J. Hancock - Series B 0 9,107 2014 Libor +2.39
ABB Energy 0 7,123 2011 9.70%
AJG Financial Services 0 6,240 -- 6..00%
------------ ------------
Total Debt: $ 80,521 $ 58,755
------------ ------------
F-21
NOTE L --DEFERRED REVENUES
Deferred revenues primarily represent gains to be recognized from the sale of
USEB's limited partnership interests in certain partnerships, further described
in Note G. The majority of the proceeds from the sales are to be paid in
installments, the amounts of which will be determined by production and other
considerations; therefore, the gain will be recognized as payments are received.
In June, 2004, Deferred Revenues were reduced by $2,502 to reflect revised
estimates of the total amount to be realized under the contingent note
receivable from AJG pertaining to their acquisition of various gasco interests.
The write down of the deferred revenue was offset by an equal reduction in
Installment Sales Partnership Interests and did not result in a charge to
operating income.
NOTE M --DEFERRED ROYALTY
On April 8, 2004, the Countryside Fund acquired a convertible royalty interest
in USEB for $6,000. Pursuant to the terms of the royalty agreement, the
Countryside Fund has the right to receive, on a quarterly basis, the sum of 7%
of net distributable cash flow and 1.8% of USEB's gross revenues, determined
pursuant to the royalty agreement. The total royalty payment to be made to the
Countryside Fund is not to exceed 49% of total distributions made to the
Countryside Fund and the shareholders of USEB, combined. The Countryside Fund
has the option, under the terms of the royalty agreement, to convert the
interest into non-voting common shares of USEB, equal to 49% of the outstanding
equity. the Countryside Fund can convert at the earlier of the date on which the
loan from the Countryside Fund is paid in full and April 8, 2024. The amount of
the royalty is accrued on a quarterly basis and paid upon the approval of
distributions by the Board of Directors of USEB.
For year ended December 31, 2004, USEB accrued $314 for royalty payments.
Payment of this liability, future royalty interest, and distributions to the
shareholders of USEB are dependent on sufficient cash flow being generated by
USEB to support operations after the distributions, all as determined and
approved by the Board of Directors of USEB. The payment of future royalty
payments may be restricted since, due to the terms of the the Countryside Fund
loan agreement, the payment of royalties is subordinate to the requirements to
fund a debt service reserve account. Until an amount is deposited into the debt
service reserve account equal to $250 per quarter since the April 8, 2004
closing, USEB is precluded from making royalty payments or distributions to
shareholders. See Note K for further discussion.
NOTE N -- INCOME TAXES
The provisions (benefits) for income taxes is as follows:
(Dollars in thousands)
2004 2003 2002
------------ ------------ ------------
Current $ 240 $ -- $ --
Deferred (1,368) (356) (7,297)
------------ ------------ ------------
Total $ (1,128) $ (356) $ (7,297)
============ ============ ============
The provision (benefit) for income taxes differs from the Federal statutory rate
for the following reasons:
(Dollars in thousands)
2004 2003 2002
---------- ---------- ----------
Provision (Benefit) at Statutory Rate (184) (906) $ (8,262)
Non-deductible Expenses 14 362 --
Illinois Subsidy and Deferred Revenue (993) -- --
Depreciation (401) -- --
Impact of Valuation Allowance (--) 201 --
State Income Tax 240 -- --
Other 196 (13) 965
Actual Provision (Benefit) for Income Taxes (1,128) (188) $ (7,297)
F-22
Provisions have been made for deferred taxes based on differences between the
financial statements and the tax basis of assets and liabilities using currently
enacted rates and regulations. The components of the net deferred tax assets and
liabilities are as follows:
(Dollars in thousands)
2004 2003
---------- ----------
Deferred Tax Assets:
NOL and Credit Carry Forward $ 20,439 $ 20,000
Property, Plant & Equipment 3,516 3,115
Deferred Revenue 2,598 2,445
Other -- --
Deferred Tax Liabilities:
Comprehensive Income (771) --
Rate Income Differential (6,442) (7,282)
Investments -- --
Valuation Allowance (6,931) (6,466)
---------- ----------
Totals $ 12,409 $ 11,812
========== ==========
At December 31, 2004 the Company had an aggregate of $39,000 of operating loss
carry forward. These net operating loss carry forwards expire in varying amounts
through the year 2023. It is anticipated that future operations will result in
taxable income against which the Company can utilize the operating loss carry
forwards.
NOTE O -- STOCKHOLDERS' EQUITY
As of December 31, 2004, we had warrants outstanding for the purchase of our
common stock as follows:
Expiration
Shares Exercise Price Date
------ -------------- ----
366,666 $ 6.00 May 1, 2006
1,500,000 $ 4.00 July 30, 2005
In 2004, 22,426 warrants which had a exercise price of $8.00 expired. There were
no changes in the warrants for 2003 and 2002.
2000 Executive Incentive Compensation Plan. The 2000 Executive Incentive
Compensation Plan (the "2000 Plan") provides for the granting of stock options,
stock appreciation rights, restricted stock, deferred stock and other stock
related awards and incentive awards that may be settled in cash, stock or
property. The total number of shares that may be issued under the 2000 Plan
equals the sum of 10,000,000 shares plus the number of shares that are
surrendered in payment of any award or any tax withholding requirements. All of
these shares may be incentive stock options.
The Board of Directors or a committee thereof administers the 2000 Plan. The
Board is permitted to impose performance conditions with respect to any award,
thereby requiring forfeiture of all or any part of any award if performance
objectives are not met, or to link the time of exercisability or settlement of
an award to the achievement of performance conditions. For awards intended to
qualify as "performance-based compensation" within the meaning of Section 162(m)
of the Internal Revenue Code, such performance objectives shall be based upon
the achievement of a performance goal based upon business criteria described in
or determined pursuant to 2000 plan.
During the calendar year 2002, options to acquire 200,000 shares of common stock
were issued under the 2000 Plan.
There were no options granted in the year 2003.
F-23
During the calender year 2004, options to acquire 100,000 shares of common stock
were cancelled and 120,000 options were granted under the 2000 Plan. The options
that were cancelled represented options held by an executive officer and were
cancelled upon the termination of his employment with the Company.
Stock option activity is summarized as follows:
F-24
Stock Option Activity -- Year Ended December 31, 2004
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended Year Ended Year Ended
December 31, 2004 December 31, 2003 December 31, 2002
----------------- ----------------- -----------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise Range of
Shares Price Shares Price Shares Price Exercise Price
------ ----- ------ ----- ------ ----- --------------
Options Outstanding at
Beginning of Year......... 6,118,925 $ 3.84 6,764,425 $ 3.84 6,965,425 $ 3.90 $0.65 - $2.50
Granted................... 120,000 1.23 -- -- 200,000 4.00 $2.875 - $3.00
Cancelled................. (100,000) 3.64 (645,500) 3.33 (280,000) 5.67 $3.00 - $3.875
Exercised................. -- -- -- -- (121,000) 2.46 $4.00 - $5.15
Options Outstanding at End
of Year................... 6,138,925 4.00 6,118,925 3.89 6,764,425 3.84 $6.00 - $7.00
----------------------------------------------------------------------------------------------------
Options Exercisable at End
of Year................... 6,138,925 $ 4.00 6,118,925 $ 3.89 6,764,425 $ 3.84
====================================================================================================
Stock Option Activity -- Year Ended December 31, 2004 (continued)
- -----------------------------------------------------------------------------------------------------------
Options Outstanding Options Exercisable
------------------- -------------------
Weighted
Weighted Average
Average Remaining Life Weighted Average
Shares Exercise Price in Years Shares Exercise Price
Options Outstanding at
Beginning of Year......... 521,000 $ 2.14 4.9 521,000 $ 2.141
Granted................... 1,339,925 2.95 5.1 1,339,925 2.95
Cancelled................. 790,000 3.03 5.8 790,000 3.03
Exercised................. 2,768,000 4.21 5.6 2,768,000 4.21
Options Outstanding at End
of Year................... 720,000 6.08 6.0 720,000 6.08
------------------------------------------------------------------------------
Options Exercisable at End
of Year................... 6,138,925 $ 3.83 5.5 6,138,925 3.83
==============================================================================
The weighted average fair value of options at date of grant for grants during
the year ended December 31, 2004 was $0.21. The fair value of the options at
date of grant was estimated using the Black-Scholes option-pricing model
utilizing the following assumptions:
For the year ended For the year ended
December 31, 2004 December 31, 2002
------------------------------------------------------------------------------------------------
Risk-free Interest Rates...................... 4.20% 3.91%
Expected Option Life in Years................. 10.00 10.00
Expected Stock Price Volatility............... 0.26 0.76
Expected Dividend Yield....................... 0.00% 0.00%
Had the Company elected to recognize compensation cost based on the fair value
of the options at the date of grant as prescribed by SFAS 123, pro forma net
profit or (loss) applicable to common stock during the years 2004 and 2002 would
have been net loss of $(214) and $(16,054), respectively.
F-25
NOTE P -- COMMITMENTS AND CONTINGENCIES
The Company and its subsidiaries have various financial commitments under office
and equipment leases and under the Development Agreement with the Countryside
Fund. The office and equipment leases, which include the lease for the corporate
headquarters in White Plains, NY expire on various dates. The $288 annual
obligation under the Development Agreement with the Countryside Fund expires in
March, 2009. Financial commitments for the next five years are:
Year Commitments
------------------------- ---------------------------------
2005 $ 579
2006 512
2007 494
2008 337
2009 79
---------------------------------
Total: $ 2,001
=================================
Lease expenses for the Company for 2004, 2003 and 1002 were $253, $296 and $318
respectively.
NOTE Q -- RETIREMENT AND PROFIT SHARING PLAN
Pursuant to the Company's 401(k) plan, employees may defer up to 15% of their
salaries up to the maximum contribution allowed under the Internal Revenue Code.
The Company matches 100% of the first 3% of salary contributed and 50% of the
next 2% of salary contributed to the plan. For the years ended December 31,
2004, 2003 and 2002, the Company's total contribution were $63, $82 and $78,
respectively.
NOTE R -- RELATED PARTY TRANSACTIONS
In the fiscal year 2004 and 2003, certain legal costs were incurred by us and
paid to an entity of which a member of our executive management was of counsel.
The amount paid were $220 in 2004, $59 in 2003 and $126 in 2002.
AJG Genco Transaction
AJG Financial Services, Inc. owns a 50% limited partnership interest in Illinois
Electrical Generation Partners L.P. ("IEGP") and a 50% limited partnership
interest in Illinois Electrical Generation Partners II L.P. ("IEGP"). IEGP owns
directly or indirectly three Biogas Projects and IEGP II owns directly or
indirectly eight Biogas Projects.
AJG Subordinated Loan
On September 30, 2004, USEB purchased the subordinated note owed by USEB to AJG.
The outstanding principal amount of $5,729 plus outstanding accrued interest was
purchased for $3,000. Funds for the acquisition were provided by equity
contributions to USEB from the USEB shareholders; $1,629 contributed by the
Company and $1,371 contributed by Cinergy. The purchase resulted in a gain of
$2,729. The gain represents the amount of the acquisition price below the note's
face value.
NOTE S -- BUSINESS OPERATIONS
As of December 31, 2004, the Company had no foreign operations. Certain key
financial data related to operations are reflected below:
F-26
U.S. Energy Systems, Inc. and Subsidiaries
Revenues and Net Income
For the Year Ended December 31, 2004
(Dollars in thousands)
Source of Revenue Corp Geothermal LLC USEB USE Canada Total
- ----------------- ---------- ---------- ---------- ---------- ----------
Energy $ -- $ -- $ 18,434 $ -- $ 18,434
Management Fees 207 -- 1,467 -- 1,674
Other -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Total Revenue $ 207 $ -- $ 19,901 $ -- $ 20,108
========== ========== ========== ========== ==========
Net Income $ 125 $ 0 $ 24 $ 495 $ 644
========== ========== ========== ========== ==========
U.S. Energy Systems, Inc. and Subsidiaries
Revenues and Net Income
For the Year Ended December 31, 2003
(Dollars in thousands)
Source of Revenue Corp Geothermal LLC USEB USE Canada Total
- ----------------- ------------ ------------ ------------ ------------ ------------
Energy $ -- $ -- $ 22,764 $ -- $ 22,764
Management Fees 550 -- 1,662 -- 2,212
Royalties 23 -- -- -- 23
------------ ------------ ------------ ------------ ------------
Total Revenue $ 573 $ -- $ 24,426 $ -- $ 24,999
============ ============ ============ ============ ============
Net Income $ 1,379 $ (8) $ (729) $ 1,196 $ 1,838
============ ============ ============ ============ ============
U.S. Energy Systems, Inc. and Subsidiaries
Revenues and Net Income
For the Year Ended December 31, 2002
(Dollars in thousands)
Geothermal US USE
Source of Revenue Corp LLC Enviro SEFL USEB Canada Total
------------ ------------ ------------ ------------ ------------ ------------ ------------
Energy $ -- $ -- $ -- $ -- $ 20,048 $ -- $ 20,048
Management Fees $ 449 -- -- -- 1,576 -- 2,025
Interest -- -- -- 3,453 326 -- 3,779
Royalties 249 -- -- -- -- -- 249
Other -- -- $ 2,519 -- -- -- 2,519
------------ ------------ ------------ ------------ ------------ ------------ ------------
Total Revenues $ 698 $ -- $ 2,519 $ 3,453 $ 21,950 $ -- $ 28,620
============ ============ ============ ============ ============ ============ ============
Net Income $ (10,291) $ (5,401) $ 56 $ 507 $ (2,228) $ 1,209 $ (16,148)
============ ============ ============ ============ ============ ============ ============
Effective June 30, 2003, the Company sold its 95% membership interest in US
Energy Geothermal, LLC to a subsidiary of Ormat Nevada, Inc. for approximately
$1.0 million in cash. As part of such transaction the purchaser and Ormat
Nevada, Inc. agreed to indemnify US Energy against certain potential liabilities
of U.S. Energy Geothermal, LLC, the subsidiary which owned the Steamboat
Geothermal Plant, including the pending lawsuit brought against U.S. Energy
Geothermal, LLC by Geothermal Development Associates and Delphi Securities up to
the amount of the purchase price.
The following pro forma combined revenue and net income as of September 30, 2003
is provided as if the sale of U.S. Energy Geothermal, LLC had taken place
effective January 1, 2003:
F-27
As of December
As of December As of June 31, 2003
31, 2003 30, 2003 Adjusted
------------ ------------ ------------
U.S. Energy
Geothermal,
U.S. Energy LLC U.S. Energy
------------ ------------ ------------
Revenues $ 24,999 $ 993 $ 24,006
============ ============ ============
Net Income (Loss) $ 1,838 $ (8) $ 1,830
============ ============ ============
Earnings per Share:
Income (Loss) per Share Common - Basic .08 -- .08
============ ============ ============
Income (Loss) per Share Common - Diluted .11 -- .11
============ ============ ============
Weighted Average Number of Shares Outstanding - Basic 11,935 11,950 11,935
Weighted Average Number of Shares Outstanding - Diluted 17,087 17,115 17,087
NOTE T -- MAJOR CUSTOMERS
During 2004 and 2003, one customer accounted for 42% and 34% of our
revenues(excluding revenues from discontinued operatons), respectively.
NOTE U -- DISCONTINUED OPERATIONS
USE Canada
The sale of USE Canada to the Countryside Fund was completed in April 2004 and
USE Canada was accounted for as a discontinued operation as of December 31,
2003. Assets and liabilities of USE Canada to be disposed of comprise the
following as of December 31, 2003 and 2002:
2003 2002
------------ ------------
Assets:
Cash $ 676 $ 1,049
Accounts Receivable 1,813 1,796
Other Current Assets 833 842
Property Plant and Equipment 22,948 17,979
Deferred Tax Asset 1,678 1,310
Other Assets 232 160
------------ ------------
Total Assets $ 28,180 $ 23,136
============ ============
Liabilities:
Current Portion of Long Term Debt $ 2,013 $ 733
Accounts Payable and Other 2,316 3,841
Long Term Debt less current portion 17,416 13,662
------------ ------------
Total Liabilities $ 21,745 $ 18,236
============ ============
These assets and liabilities are reflected on the Balance Sheet under the
caption "Assets to be disposed of" and "Liabilities to be disposed of".
Total revenues for USE Canada for 2003 and 2002, were $12,689 and $10,021,
respectively. USE Canada was purchased by the Company on June 11, 2001.
The Company sold Geothermal on June 30, 2003. These assets and liabilities are
reflected on the Balance Sheet under the caption "Assets to be disposed of" and
"Liabilities to be disposed of".
F-28
2003 2002
------------ ------------
Assets:
Cash $ -- $ 63
Accounts Receivable -- 263
Other Current Assets -- 21
Property Plant and Equipment -- 1,154
Deferred Tax Asset -- --
Other Assets -- --
------------ ------------
Total Assets $ -- $ 1,501
============ ============
Liabilities:
Current Portion of Long Term Debt -- --
Accounts Payable and Other -- 981
Long Term Debt less current portion -- --
------------ ------------
Total Liabilities $ -- $ 981
============ ============
Total revenues for the year 2003 and 2002 were $996 and $1,300, respectively.
NOTE V - ACCOUNTING CHANGES
The Company's accounting policy pertaining to the financial accounting of the
Illinois rate incentives received by its Illinois-based biogas to energy
projects was changed effective April 1, 2001. The change in tax accounting had
no impact on consolidated cash flow. In addition, an adjustment was also made to
the purchase accounting related to the acquisition of Biogas in 2001.
Following is a summary of the prior period adjustments made to the audited
financial statements:
Balance Sheet:
- -------------------------------------------------------------------------------
Deferred Tax Goodwill Minority Retained
Asset Interest Earnings
- -------------------------------------------------------------------------------
Year 2002 (4,809) (430) (2,396) (2,843)
Year 2003 (7,283) (430) (3,528) (4,185)
Statements of Operation:
- -------------------------------------------------------------------------------
Revenues Minority Income Tax Net Income
Interest Expense
- -------------------------------------------------------------------------------
Year 2002 -- 613 (1,340) (727)
Year 2003 -- 1,132 (2,474) (1,342)
- -------------------------------------------------------------------------------
Total $ (4015) $ 3,528 $ (3,698) $ (4,185)
===============================================================================
NOTE W - UNREALIZED GAINS
The unrealized gain is comprised of $1,246 of mark to market gains in open
trading positions from the investment of the Illinois Accounts and $784 in gains
associated with foreign currency exchange rates less taxes of $771.
F-29
SIGNATURES (Continued)
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
U.S. ENERGY SYSTEMS, INC.
By: /s/ LAWRENCE I. SCHNEIDER March 31, 2005
- -----------------------------------------------------
Lawrence I. Schneider,
Chairman of the Board of Directors, Chief Executive
Officer
By: /s/ RICHARD J. AUGUSTINE March 31, 2005
- -----------------------------------------------------
Richard J. Augustine
Chief Accounting 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.
/s/ STEPHEN BROWN March 31, 2005
- -----------------------------------------------------
Stephen Brown,
Director
/s/ EVAN EVANS March 31, 2005
- -----------------------------------------------------
Evan Evans,
Director
/s/ CARL GREENE March 31, 2005
- -----------------------------------------------------
Carl Greene,
Director
/s/ M. STEPHEN HARKNESS March 31, 2005
- -----------------------------------------------------
M. Stephen Harkness,
Director
/s/ JACOB FEINSTEIN March 31, 2005
- -----------------------------------------------------
Jacob Feinstein,
Director
/s/ RONNY STRAUSS March 31, 2005
- -----------------------------------------------------
Ronny Strauss,
Director
/s/ LAWRENCE I. SCHNEIDER March 31, 2005
- -----------------------------------------------------
Lawrence I. Schneider,
Chairman of the Board of Directors, Chief Executive
Officer