UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended June 30, 1996
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from _____ to _____
Commission File Number: Not Yet Issued
Reg. No. 33-69762
CONSOLIDATED HYDRO, INC.
(Exact name of registrant as specified in its charter)
Delaware 06-1138478
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
680 Washington Boulevard, Stamford, Connecticut 06901
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (203) 425-8850
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
The aggregate market value of voting stock held by non-affiliates of the
Registrant is not available since there is no public market for the stock.
Indicate the number of shares of each of the issuer's classes of common stock,
as of the latest practicable date:
Class A Outstanding as of September 25, 1996
- -------------------------------- ------------------------------------
Common stock, $.001 par value 1,285,762
Class B Outstanding as of September 25, 1996
- -------------------------------- ------------------------------------
Common stock, $.001 par value NONE
Page 1 of _____
Exhibit Index begins on page ____
<PAGE>
CONSOLIDATED HYDRO, INC.
1996 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
PART I
Page
Item 1. Business................................................. 3
Item 2. Properties............................................... 25
Item 3. Legal Proceedings........................................ 25
Item 4. Submission of Matters to a Vote of Security Holders...... 25
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.................................... 25
Item 6. Selected Financial Data.................................. 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 28
Item 8. Financial Statements..................................... 40
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................... 71
PART III
Item 10. Directors and Executive Officers of the Registrant..... 71
Item 11. Executive Compensation................................. 75
Item 12. Security Ownership of Certain Beneficial Owners and
Management 80
Item 13. Certain Relationships and Related Transactions......... 81
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 84
-i-
<PAGE>
PART I
Item 1. BUSINESS
Consolidated Hydro, Inc. ("CHI", and together with its consolidated
subsidiaries the "Company") is principally engaged in the development, operation
and management of hydroelectric power plants. Based on operating megawatts, the
Company is the largest independent hydroelectric power producer in the United
States. To date, the Company has expanded primarily by acquiring existing
conventional hydroelectric facilities in the United States. As of June 30, 1996,
the Company owned, operated or leased 91 projects in the United States and
Canada, with aggregate capacity of approximately 344 megawatts. In November
1995, the Company established a subsidiary, CHI Power, Inc., for the purpose of
developing, acquiring, operating and managing industrial energy facilities and
related industrial assets.
The Company's operating hydroelectric projects are located in 15
states and one Canadian province. The U.S. projects are clustered in four
regions: the Northeast, Southeast, Northwest and West, with a concentration in
the Northeast, a region characterized by relatively consistent long-term water
flow and power purchase contract rates which are higher on average than in most
other regions of the country. Additionally, the Company operates three projects
with an aggregate capacity of 80 megawatts in Ontario, Canada pursuant to an
operations and maintenance ("O&M") contract, and is in the late development
stage of a 15-megawatt hydroelectric project in Newfoundland. CHI has developed
what it believes to be an efficient "hub" system of project management designed
to maximize the efficiency of each facility's operations. The economies of scale
created by this system include reduced costs related to centralized
administration, operations, maintenance, engineering, insurance, finance and
environmental and regulatory compliance. The hub system and the Company's
operating expertise have enabled the Company to successfully integrate
acquisitions within its current portfolio and increase the efficiency and
productivity of its projects.
The electric power industry in the United States is undergoing
significant structural changes, evolving from a highly regulated industry
dominated by monopoly utilities to a deregulated, competitive industry providing
energy customers with an increasing degree of choice among sources of electric
power supply. Many industrial companies in the United States and Canada and
certain U.S. utilities are evaluating the divestiture of their non-strategic
hydroelectric assets. However, recent reductions in prices for electricity,
increased efficiency of combustion turbines and other competing technologies and
the deregulation and restructuring of the electric power industry have created a
climate of uncertainty with respect to future power prices and make it more
difficult to obtain long-term power purchase contracts, thereby severely
limiting the Company's near-term opportunities to acquire or develop additional
hydroelectric capacity at acceptable rates of return.
On June 30, 1996, the Company had a 100% ownership or long-term lease
interest in 67 projects (153 megawatts) including 20 projects under contract for
sale, a partial ownership interest in 14 projects (86 megawatts) and O&M
contracts with 10 projects (105 megawatts). CHI sells substantially all of the
output from these projects, excluding the Canadian projects, to public utility
companies pursuant to take and pay power purchase agreements. These contracts
vary in their terms but typically provide scheduled rates throughout the life of
the contracts, which are generally for a term of 15 to 40 years from inception.
See "-- Power Purchase Agreements". The Company has significantly reduced the
carrying value of certain of its assets. See Part II, Item 7 "Managements
Discussion and Analysis of Financial Condition and Results of Operations --
General".
Currently, all of the Company's revenue is derived from the ownership
and operation of hydroelectric facilities. The Company has begun to seek
opportunities to provide energy-related products and services to industrial and
utility customers in an effort to respond to changing market conditions. Such
opportunities, if available, would permit the Company to move away from relying
exclusively on hydropower ownership and operation in a business climate driven
largely by legislation and regulation and the structural industry trends
described above and in which the Company currently believes that acquisition and
development opportunities are limited as discussed further below. The Company
will seek to capitalize on these new opportunities in energy-related
<PAGE>
products and services, by taking advantage of its existing technical and
financial expertise and using its geographic presence to realize economies of
scale in administration, operation, maintenance and insurance of facilities.
Nevertheless, the performance of the Company in the future will be
affected by a number of factors, in addition to the structural changes to the
electric power industry discussed above. First, the Company competes for
hydroelectric and industrial energy projects with a broad range of electric
power producers including other independent power producers of various sizes and
many well-capitalized domestic and foreign industry participants such as
utilities, equipment manufacturers and affiliates of industrial companies, many
of whom are aggressively pursuing power development programs and have relatively
low return-on-capital objectives. Opportunities to acquire or develop power
generation assets on favorable economic terms in such an environment are
increasingly limited, particularly with regard to hydroelectric facilities.
Second, the Company is highly leveraged and its debt service obligations, the
cash portion of which commence in January 1999, along with its preferred stock
obligations, the cash portion of which commence in September 1998, make it
difficult to source capital on favorable terms that would allow the Company to
successfully pursue significant acquisition and development opportunities and,
in some cases, make it difficult to establish the creditworthiness necessary to
develop the project or to obtain contracts to develop products and services for
the industrial and utility customers described above. See "-- Certain Risk
Factors".
The Company had also been a developer of pumped storage hydroelectric
power plants in the United States. By cycling water between upper and lower
reservoirs, a pumped storage hydroelectric facility is able to convert low value
off-peak energy into high value peak power. However, as a result of continued
restructuring of the U.S. electric power industry and other events which have
created a climate of uncertainty regarding the future structure of the U.S.
electric power industry, the Company in 1996 wrote down virtually all of its
previous investments in pumped storage development and has reached an agreement,
subject to final documentation, to sell its pumped storage interests except
those related to the 1,500 megawatt Summit project located in Norton, Ohio (see
"Part III, Item 11, "Employment Contracts and Special Employment Arrangements").
The Company will limit its pumped storage development activities to the minimum
necessary to maintain the viability of the Summit project. Project development
carries a high degree of risk, however, and there can be no assurance that the
project will be completed.
As of September 15, 1996, the Morgan Stanley Leveraged Equity Fund,
II, L.P. ("MSLEF II") owns 80.0% of the Company's 8.0% Senior Convertible Voting
Preferred Stock (the "Series F Preferred Stock") and 80.0% of the Company's
9.85% Junior Convertible Voting Preferred Stock (the "Series G Preferred
Stock"), both of which series currently have 25 votes per share and which, if
converted, would in the aggregate currently represent 48.8% of CHI's Common
Stock on a fully diluted basis. Madison Group, L.P. ("Madison") owns 17.8% of
the Company's Series F Preferred Stock and 17.8% of the Company's Series G
Preferred Stock which, if converted, would in the aggregate currently represent
10.8% of CHI's Common Stock on a fully diluted basis. See Part III, Item 12,
"Security Ownership of Certain Beneficial Owners and Management".
CHI is a Delaware corporation. The Company's executive and
administrative offices are located at 680 Washington Boulevard, Stamford,
Connecticut 06901, and its telephone number is (203) 425-8850.
The Hydroelectric Power Industry
Until the establishment of its CHI Power, Inc. subsidiary in November
1995 to pursue industrial energy and related opportunities, the Company had been
engaged exclusively in the development, acquisition, and operation of
hydroelectric facilities and currently derives all of its revenues from this
source. Hydroelectric power has proven to be a reliable, cost-effective and
non-polluting source of energy since the nineteenth century. Hydroelectric power
generally offers the following advantages over various other forms of power
generation: (i) hydroelectric technology is a proven technology that has existed
essentially unchanged for many years; (ii) unlike fossil fuels, water is a
renewable and non-depleting source of energy; (iii) hydroelectric power
facilities have relatively low operating and labor costs; (iv) hydroelectric
power typically has no fuel cost; (v) hydroelectric power does not create
harmful
-2-
<PAGE>
pollutants; (vi) hydroelectric power facilities typically have economic lives of
50 years or more; and (vii) hydroelectric power facilities can produce other
beneficial impacts such as recreational enhancements, flood control and water
supply management. The disadvantages of hydroelectric power include seasonality,
dependence on satisfactory levels of precipitation and water flow, a factor
which creates difficulty in predicting generating levels for discrete periods,
and, in some cases, environmental impact on both aquatic life and certain
recreational uses near facilities.
During the late 1970's, development of small hydroelectric power
facilities was stimulated by rising oil prices, the enactment by Congress of the
Public Utility Regulating Policies Act of 1978 ("PURPA") and the adoption of the
regulations thereunder, and certain tax incentives, including the business
energy tax credit and the investment tax credit. PURPA reduced regulatory
procedures for small non-utility power production facilities and required
electric utilities to purchase power from such facilities at a price based on
the purchasing utility's full avoided cost, which is equal to the incremental
cost that would have been incurred if the utility had generated the energy
itself or purchased it from another source. See "-- Energy and Environmental
Regulation - Energy Regulation". Each state utility commission is empowered
under PURPA to define avoided cost. PURPA also expressly authorized utilities to
negotiate with power producers for rates different from those rates established
by the state public utility commission based on avoided cost.
By the time CHI was organized in July 1985, the hydroelectric power
industry had already begun a transition period. Fragmented ownership,
inefficient operating practices and inappropriate capitalization led many early
developers to leave the industry. In addition, the regulatory process became
more difficult as a result of an increased focus on environmental issues. Also,
the Tax Reform Act of 1986 repealed or phased out many of the tax incentives for
hydroelectric power projects. These factors had the greatest impact on the less
efficient, inexperienced operators by compressing their operating margins and
diminishing investors' returns.
In its 1992 report on hydroelectric resources (the most recent such
report available), FERC reported that there were approximately 73,500 megawatts
of existing conventional hydroelectric capacity in the United States, in
addition to approximately 18,100 megawatts of existing pumped storage
hydroelectric capacity, for a total of 91,600 megawatts. According to FERC,
hydroelectricity represents approximately 12% of all U.S. electric generation
capacity.
-3-
<PAGE>
Conventional Hydroelectric Projects
The following table set forth the Company's projects as of June 30, 1996
with 100% ownership, with partial ownership and with O&M contracts:
<TABLE>
<CAPTION>
Projects with 100% Ownership as of June 30, 1996
(including sale-leasebacks)
Power Purchase FERC Date of CHI
Agreement License Approximate Acquisition or
Expiration Expiration Capacity in Commencement
Project Location Power Purchasing Entity Date Date Megawatts of Operations(1)
- ------- -------- ----------------------- -------------- ---------- ----------- ----------------
<S> <C> <C> <C> <C> <C> <C>
Apalache........... Greer, SC Duke Power Co. Dec. 1997(2) July 2024 0.40 May 1989
Aziscohos(3)....... Wilson Mill, ME Central Maine Power Co. July 2008 Mar. 2025 5.31 June 1988
Barber Dam......... Boise, ID Idaho Power Co. July 2022 Nov. 2023 4.14 Dec. 1992
Barker Mill Lower(13) Auburn, ME Central Maine Power Co. Dec. 2008(9) Jan. 2019 1.50 Apr. 1986
Barker Mill Upper(3,13) Auburn, ME Central Maine Power Co. July 2007(4) July 2023 0.95 Aug. 1987
Beaver Valley Beaver Falls, PA Dusquesne Power Open Ended(12) Exempt 1.30 Feb. 1995
Black Canyon Gooding, ID Idaho Power Co. May 2019 Exempt 0.10 May 1993
Boott(3)........... Lowell, MA Commonwealth Elec. Apr. 2023 Apr. 2023 24.82 Dec. 1986
Brown's Mill(13) Dover-Foxcroft, ME Central Maine Power Co. Dec. 2008(9) Exempt 0.59 Sept. 1985
Canal Creek Joseph, OR Pacific Power & Light Dec. 2020(5) Exempt 1.13 Aug. 1991
Coneross........... Seneca, SC City of Seneca Mar. 1998 Mar. 2015 0.90 May 1989
Crescent........... Russell, MA Town of Groton Oct. 2009(10) May 2024 1.50 Feb. 1995
Damariscotta(13) Damariscotta, ME Central Maine Power Co. Dec. 2008(9) Licensing in 0.46 July 1986
Progress
Dewey's Mill Hartland, VT Vermont Power Exchange July 2015 Dec. 2032 1.90 Aug. 1993
Dexter............. Dexter, NY Niag. Mohawk Power Corp. Dec. 2023 Exempt 4.30 Feb. 1995
Diamond Island Watertown, NY Niag. Mohawk Power Corp. Dec. 2023 Exempt 1.20 Feb. 1995
Dietrich Drop Dietrich, ID Idaho Power Co. July 2022 Apr. 2037 4.77 Dec. 1992
Eagle & Phenix Columbus, GA Fieldcrest Cannon6 June 2006 Feb. 2009 4.26 June 1991
Eustis(13)......... Eustis, ME Central Maine Power Co. Dec. 2008(9) Licensing in
Progress 0.25 July 1986
Ferguson Ridge. Joseph, OR Pacific Power & Light Dec. 20205 Exempt 1.44 Aug. 1991
Fowler #7.......... Fowler, NY Niag. Mohawk Power Corp. Dec, 1999(11) Oct. 2002 .90 Feb. 1995
Fries.............. Fries, VA Virginia Elec. Power Co. Jan. 1999 May 2020 5.21 May 1989
& Apalachian Power Co.
Gardiner(13)....... Gardiner, ME Central Maine Power Co. Dec. 20089 Apr. 2019 1.00 July 1985
Geo-Bon II......... Lincoln County, ID Idaho Power Co. March 2020 Exempt 1.00 June 1994
Glendale........... Stockbridge, MA Town of Groton Oct. 2009(10) Oct. 2009 .70 Feb. 1995
Goodyear Lake Milford, NY N.Y. State Elec. Aug. 2010 Feb. 2019 1.30 Feb. 1995
& Gas Corp.
Great Falls Lower(13) Somersworth, NH Pub. Serv. Co. of NH Dec. 2011 Apr. 2022 1.29 July 1985
Great Works(13) South Berwick, ME Central Maine Power Co. Dec. 2008(9) Non- 0.53 July 1986
Jurisdictional
Hailesboro #3 Fowler, NY Niag. Mohawk Power Corp. Dec. 2023 Exempt .90 Feb. 1995
Hailesboro #4 Fowler, NY Niag. Mohawk Power Corp. Dec. 2023 Dec. 2002 1.80 Feb. 1995
Hailesboro #6 Fowler, NY Niag. Mohawk Power Corp. Dec. 2023 Exempt .90 Feb. 1995
High Falls......... Franklin County, NY N.Y.S. Elec. Gas Corp. Dec. 2002 Jan. 2026 1.75 Oct. 1993
High Shoals High Shoals, NC Duke Power April 1997 Exempt 1.56 July 1993
Kelley's Falls(13) Manchester, NH Pub. Serv. Co. of NH Dec. 2005 Mar. 2024 0.45 Dec. 1985
Kings River Fresno, CA Pacific Gas & Electric Jan. 2021 July 2037 1.35 June 1994
Kinneytown......... Seymour, CT CT Light & Power Nov. 2016 Exempt 2.36 Nov. 1986
LaChute Lower(3) Ticonderoga, NY Niag. Mohawk Power Corp. Dec. 2015 Exempt 3.60 Dec. 1987
LaChute Upper(3) Ticonderoga, NY Niag. Mohawk Power Corp. Dec. 2015 Exempt 4.90 Dec. 1987
Lawrence........... Lawrence, MA New England Power Co. Dec. 2011(7) Nov. 2028 16.80 July 1986
Long Shoals Long Shoals, NC Duke Power Nov. 1999 Exempt 0.75 July 1993
Low Line Rapids Kimberly, ID Idaho Power Co. June 2022 Exempt 2.80 Dec. 1992
Lower Wilson1(3) Greenville, ME Central Maine Power Co. Dec. 2008(9) Non- 0.57 July 1986
Jurisdictional
<PAGE>
Power Purchase FERC Date of CHI
Agreement License Approximate Acquisition or
Expiration Expiration Capacity in Commencement
Project Location Power Purchasing Entity Date Date Megawatts of Operations(1)
- ------- -------- ----------------------- -------------- ---------- ----------- ----------------
Mechanic Falls(13) Mechanic Falls, ME Central Maine Power Co. Dec. 2008(9) Licensing in 1.30 Apr. 1986
Progress
Milo13............. Milo, ME Bangor Hydro-Elec. Co. Dec. 2014 Exempt 0.60 July 1985
Milstead.......... Milstead, GA Municipal Elec. Auth. Apr. 2000 Exempt 1.00 July 1993
of GA
New Dam(13)........ Sanford/Alfred, ME Central Maine Power Dec. 2008(9) Licensing in 0.78 July 1986
Co.(8) Progress
Norway(13)......... Norway, ME Central Maine Power Co. Dec. 2008 Non- 0.32 July 1986
Jurisdictional
Old Falls(13) West Kennebunk, ME Central Maine Power Dec. 2008(9) Under Appeal 0.47 July 1986
Co.(8)
Ottauquechee N. Hartland, VT Vermont Power Exchange Sept. 2017 Exempt 1.89 June 1994
Pelzer Lower Williamston, SC Duke Power Co. Sept. 1998(2) Nov. 2017 3.30 Feb. 1990
Pelzer Upper Pelzer, SC Duke Power Co. Sept. 1998(2) Nov. 2017 2.00 Feb. 1990
Piedmont........... Piedmont, SC Duke Power Co. Dec. 1997(2) Dec. 2018 1.00 May 1989
Pittsfield(13) Pittsfield, ME Central Maine Power Co. Dec. 2008(9) Licensing in
Progress 1.05 July 1986
Pumpkin Hill(13) Lowell, ME Bangor Hydro-Elec. Co. Feb. 2017 Sept. 2023 0.95 Apr. 1987
Rollinsford(13) Rollinsford, NH Public Serv. Co. of NH Sept. 20 Aug. 2021 1.49 Oct. 1986
Rock Creek II Twin Falls, ID Idaho Power Co. July 2019 Aug. 2036 1.90 Dec. 1992
Salmon Falls(13) South Berwick, ME Public Serv. Co. of NH Dec. 2006 Licensing in
Progress 1.20 July 1986
Theresa............ Theresa, NY Niag. Mohawk Power Corp. Dec. 2023 Exempt 1.30 Feb. 1995
Upper Little Sheep
Creek............ Joseph, OR Pacific Power & Light Dec. 2020(5) Exempt 4.44 Aug. 1991
Victory Mills Saratoga, NY Niag. Mohawk Power Corp. Dec. 2025 Apr. 2024 1.66 Dec. 1986
Walden............. Walden, NY N.Y.State Elec. & Nov. 1988 May 2022 2.82 Apr. 1986
Gas Corp.
Ware Shoals Ware Shoals, SC Duke Power Co. Dec. 1997(2) Sept. 2001 6.20 May 1989
West Hopkinton(13). West Hopkinton, NH Pub. Serv. Co. of NH Nov. 2012 Exempt 1.00 July 1985
Willimantic I Willimantic, CT CT Light & Power Dec. 2018 Nov. 2025 0.77 Dec. 1991
Willimantic II. Willimantic, CT CT Light & Power Dec. 2018 Sept. 2025 0.77 Dec. 1991
Woodside I. Norris, SC Duke Power Co. Dec. 1997(2) Non- 0.40 May 1989
Jurisdictional
Woodside II Cateechee, SC Duke Power Co. Dec. 1997(2) Non- 0.44 May 1989
Jurisdictional
Number of Projects: 67 Megawatt Subtotal 152.69
=======
- ------------------------
(1) Whichever is later.
(2) The terms of the power purchase agreements relating to these projects
may be extended for an additional five years at negotiated rates at
the option of the Company.
(3) These projects are subject to sale-leaseback arrangements pursuant to
which the Company is the lessee.
(4) The term of the power purchase agreement for this project may be
extended for three five-year periods at the option of the utility.
(5) Includes utility's option to extend for an additional three years.
(6) Revenue is derived pursuant to a lease arrangement.
(7) The term of the Lawrence power purchase agreement may be extended
through 2028 at the option of the purchasing utility.
(8) The New Dam and Old Falls projects operate under one power purchase
agreement.
(9) The terms of the power purchase agreement relating to these projects
may be extended for no less than five years based on mutually
agreeable terms.
(10) May be extended by mutual agreement.
(11) The term of the power purchase agreement for this project may be
extended for an additional 20 years at the option of the utility.
(12) Agreement remains in effect as long as Duquesne Power's tariff with PA
Public Utility Commission remains valid and effective.
(13) Projects which the Company has reached an agreement to sell, subject
to certain conditions, but which the Company would continue to operate
if sold.
</TABLE>
-5-
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Projects with Partial Ownership as of June 30, 1996(1)
Power Purchase FERC Approximate Date of CHI
Agreement License Project Acquisition or
Expiration Expiration Capacity in Commencement
Project Location Power Purchasing Entity Date Date Megawatts of Operations(2)
- ------- -------- ----------------------- -------------- ---------- ----------- ----------------
<S> <C> <C> <C> <C> <C> <C>
Bear Creek......... Shingletown, CA Pacific Gas & Elec. Co. Dec. 2015 Exempt 3.20 Feb. 1990
Copenhagen......... Copenhagen, NY Niag. Mohawk Power Corp. Dec. 2023 Exempt 3.30 Feb. 1995
Denley Dam......... Lyonsdale, NY Niag. Mohawk Power Corp. Dec. 2026 Exempt 1.50 Feb. 1995
Hillsborough Hillsborough, NH Pub. Serv. Co. of NH July 2004 Exempt 1.20 Nov. 1989
Lacomb............. Lacomb, OR Pacific Power & Light Dec. 2022 Exempt 0.96 Feb. 1990
Lower Saranac Saranac, NY N.Y. State Elec. & Gas Oct. 2029 May 2027 9.30 June 1992
Port Leyden Lyonsdale, NY Niag. Mohawk Power Corp. Dec. 2026 Exempt 2.00 Feb. 1995
Prather............ MacDoel, CA Pacific Power & Light Dec. 2012 Exempt 0.10 Feb. 1990
Pyrites............ Canton, NY Niag. Mohawk Power Corp. Dec. 2023 Aug. 2023 8.20 Feb. 1995
Rock Island Lyonsdale, NY Niag. Mohawk Power Corp. Dec. 2026 Exempt 1.90 Feb. 1995
Scotts Flat Nevada City, CA Pacific Gas & Elec. Co. Dec. 2003 Exempt 0.83 Feb. 1990
Sheldon Springs Sheldon, VT Vermont Power Exchange Aug. 2016 Sept. 2024 24.97 Sept. 1993
Slate Creek Lakehead, CA Pacific Power & Light Dec. 2018(3) Exempt 4.20 May 1990
Twin Falls......... North Bend, WA Puget Power & Light Co. Dec. 2025 April 2035 24.00 Apr. 1989
Number of Projects: 14 Megawatt Subtotal 85.66
=====
- -------------------------
(1) Projects with Partial Ownership are defined as those projects in which
the Company has an equity (or equivalent) investment of less than
100%.
(2) Whichever is later.
(3) The power purchase agreement for this project may be extended through
2023 at the option of the utility.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Projects with Operation and Maintenance Contracts as of June 30, 1996(1)
Approximate Project Date of CHI Acquisition
Approximate Project Date of CHI Acquisition
Project Location Capacity in Megawatts of O&M Contract
- ------- -------- --------------------- -----------------------
<S> <C> <C> <C>
Arbuckle Mountain Platina, CA 0.40 Feb. 1990
Combie North Grass Valley, CA 0.30 Feb. 1990
Combie South Grass Valley, CA 1.50 Feb. 1990
Iroquois Falls Ontario, Canada 21.49 Apr. 1994
Island Falls Ontario, Canada 38.40 Apr. 1994
Pigeon Cove Filer, ID 1.75 Aug. 1990
Schaads............ San Andreas, CA 0.28 Feb. 1990
Terminus........... Tulare County, CA 17.00 Apr. 1995
Twin Falls......... Ontario, Canada 20.25 Apr. 1994
Weeks Falls North Bend, WA 4.34 June 1990
Number of Projects: 10 Megawatt Subtotal: 105.71
======
- --------------------
(1) These are projects where the Company's only current significant
interest is through operation and maintenance contracts.
Total Number of Projects: 91
Total Megawatts Owned, Leased or Operated: 344.06
======
</TABLE>
<PAGE>
The Company has reached an agreement to sell 20 of its smaller
projects in Maine and New Hampshire, aggregating approximately 16.75 megawatts
of capacity, to a purchaser for a price of approximately $16.0 million including
working capital. The Company anticipates that it will receive half of the sale
proceeds in cash at closing and the balance within 90 days of closing. The sale
is subject to customary conditions precedent for transactions of this nature. It
is expected that the Maine projects, representing 75% of the transaction value,
will close by October 31, 1996. The closing of the New Hampshire projects will
occur subsequent to the Maine closing due to the timing of required regulatory
approvals. Under the terms of the agreement, the Company will continue to
operate and maintain the projects for a period of 15 years pursuant to an O&M
contract. The total operating revenue and income from operations from the 20
projects during the years ended June 30, 1996, 1995 and 1994 was $6.8 million,
$5.6 million and $6.1 million, and $4.5 million, $3.9 million and $3.9 million,
respectively. Although the transactions if completed will provide greater
liquidity to the Company, there can be no assurance that they will be
consummated, on the terms currently anticipated.
The Company has found that the most efficient way to operate its
projects is to have several projects in a geographic area with operators who can
go to any of the projects as needed. This is part of the Company's regional hub
system, where each individual project remains under supervision of a regional
office. Each of the Company's regions is broken up into several smaller areas
for purposes of assigning project operators. To address more technical matters,
the Company bases maintenance people and other technicians at its hubs, with
more sophisticated equipment and a more widely varied inventory of spare parts
and supplies than are kept at an individual project, all available for dispatch
to each project.
Power Purchase Agreements
As of June 30, 1996, substantially all energy and capacity of the
Company's existing majority-owned projects in the United States is sold to 17
public utilities pursuant to take and pay long-term power purchase agreements
with remaining terms ranging from approximately 1 to 30 years. The Company's
power purchase agreements generally require the utility company to purchase all
energy delivered by the relevant facility. These power purchase agreements
generally do not provide for termination prior to expiration except in the case
of continuing nonperformance by the Company and certain events of bankruptcy or
insolvency of the project subsidiary.
The Company's power purchase agreements have either fixed or
fluctuating rates or a combination thereof. Fluctuating rates and combination
rate contracts are generally based on avoided costs, or a percentage thereof,
and typically incorporate minimum prices which enable the Company to benefit
from increases in energy prices but insulate it against significant decreases.
The Company's fixed rate contracts often contain (i) blended rates typically
based on projected annual avoided costs averaged over a 15 to 30 year period; or
(ii) an escalation factor that reflects estimated increases in projected annual
avoided cost over the term of the contract. The escalation factor is often
indexed to the Gross Domestic Product ("GDP") deflator. The Company also has
contracts that provide for fixed rates or escalating fixed rates for up to 20
years, followed by adjustable rates based on a fixed percentage of actual annual
avoided costs for the remaining term. Certain power purchase contracts provide
for different rates based on peak or off-peak generation of energy. As the
Company's existing contracts mature or change from fixed rates to rates based on
avoided cost, the Company will receive lower prices for its power to the extent
that the currently low market price for electricity continues. Prices for
electricity remain low as a result of reductions in the cost of power produced
from natural gas due to lower natural gas prices and technological improvements
which have lowered the capital cost and increased the efficiency of combustion
turbines and other competing technologies. Federal regulators and a number of
states, including some in which the Company operates, are exploring ways in
which to increase competition in electricity markets, most notably by opening
access to the transmission grid. Although the character and extent of this
deregulation are as yet unclear, the Company expects that these efforts will
increase uncertainty with respect to future power prices and make it more
difficult to obtain long-term power purchase contracts. Opportunities to secure
long-term economically advantageous power purchase agreements in such an
environment are severely limited.
-8-
<PAGE>
All of the Company's existing conventional facilities in the United
States are qualifying facilities (each a "QF") under PURPA, which requires
utilities to purchase power from QFs, and exempts QFs from most utility
regulatory requirements. Pursuant to PURPA, electric utilities are required to
purchase power from QFs at prices based on the utilities' current avoided cost.
Implementation of the regulations is delegated to state public utility
commissions which may, at their discretion, establish long-term rates for a
specified period higher than short-term avoided costs or may provide other kinds
of incentives to QFs. In recent years, a number of utilities have begun to
challenge certain provisions of PURPA as no longer appropriate in the current
U.S. energy market. See "-- Energy and Environmental Regulation".
The following table sets forth the Company's power sales by customer,
the majority of which are utilities, for the year ended June 30, 1996:
<TABLE>
<CAPTION>
Combined
Revenues
Revenues of of Projects
Projects in Revenues of 100%
Consolidated Projects Only Owned and
Results of Partially Partially
Operations % Owned % Owned %
<S> <C> <C> <C> <C> <C> <C>
Niagara Mohawk Power Corp. ............... $ 9,139,542 18.4 $ 3,226,157 15.1 $12,365,699 17.4
Commonwealth Electric Co. ................ 9,527,874(1) 19.1 -- -- 9,527,874 13.4
Vermont Power Exchange (2) ............... 1,347,064 2.7 7,406,600 34.7 8,753,664 12.3
Central Maine Power Co. .................. 8,340,977 16.7 -- -- 8,340,977 11.7
New England Power Co. .................... 5,132,611 10.3 -- -- 5,132,611 7.2
Puget Power .............................. -- -- 6,546,960 30.6 6,546,960 9.2
Duke Power Co. ........................... 3,581,342 7.2 -- -- 3,581,342 5.0
Idaho Power Co. .......................... 2,982,733 6.0 -- -- 2,982,733 4.2
Public Service Co. of NH ................. 1,888,711 3.8 376,164 1.7 2,264,875 3.2
PacifiCorp ............................... 1,866,886 3.8 170,857 .8 2,037,743 2.9
N.Y. State Electric & Gas Corp. .......... 1,286,309 2.6 2,834,924 13.3 4,121,233 5.8
All other customers ...................... 4,667,241 9.4 807,885 3.8 5,475,126 7.7
----------- ----- ----------- ----- ----------- -----
Total .................................... $49,761,290 100.0% $21,369,547 100.0% $71,130,837 100.0%
=========== ===== =========== ===== =========== =====
</TABLE>
(1) Includes business interruption revenue representing lost generation
recoverable from an insurance company as a result of an insurance claim.
See Note 17 of the Notes to the Consolidated Financial Statements for
additional information.
(2) Designated by the Vermont Public Service Board ("PSB") as purchasing agent
for several Vermont utilities. In 1996, a PSB order replaced Vermont Power
Exchange ("VPX") with Vermont Electric Power Producers, Inc. ("VEPPI") as
purchasing agent and assigned VPX contracts to VEPPI, effective in August
1996. Subsequent to the PSB order, VPX filed for bankruptcy under Chapter
11 of the U.S. Bankruptcy Code. The Company's contracts with VPX have not
been materially affected by the PSB order or the VPX bankruptcy filing, and
the Company does not anticipate any material impact in the future.
Substantially all of the Company's existing power purchase agreements
contain scheduled rates for delivered energy through 1998 or later, which
protects the Company from decreases in energy prices and avoided costs from
current levels until such time. Thereafter, certain contracts expire and others
provide for prices based upon avoided cost. However, lower avoided costs of
energy could significantly reduce the rates received by the Company under a
particular contract once the period of scheduled rates terminates and could make
it more difficult in the future for the Company to obtain contracts which can
economically support development of new projects.
The following table summarizes the actual or expected basis for
determining future rates which are anticipated to be in effect under current and
anticipated future power purchase arrangements for the Company's existing
consolidated projects. To develop the information below, the Company first
computed the average annual revenue for each project included in consolidated
power sales revenues using actual revenues for each of the three years in the
period ended June 30, 1996. This "revenue mix" was then applied to each of the
respective project's power purchase agreement terms on the assumption that the
Company's consolidated project portfolio and average revenue mix remains
unchanged for the ten-year period shown in the table. Power purchase agreements
which expire during the ten-year period shown are assumed to result in revenues
based upon avoided costs for the period subsequent to contract expiration. The
information shown below is not intended to represent actual future results, but
is believed to be indicative of the portion of existing revenue that will be
subject to avoided cost risk during the period shown. No assurance can be
provided as to what the actual avoided cost risk will be for the period shown.
-9-
<PAGE>
<TABLE>
<CAPTION>
% of Current Revenues
% of Current Revenues Subject to Rates
Subject to Minimum Determined Pursuant
Calendar Year-End Fixed or Schedul to Avoided Cost
<S> <C> <C>
1997......................................... 98.4 1.6
1998......................................... 93.7 6.3
1999......................................... 87.9 12.1
2000......................................... 86.2 13.8
2001......................................... 68.7 31.3
2002......................................... 67.8 32.2
2003......................................... 65.8 34.2
2004......................................... 65.8 34.2
2005......................................... 65.0 35.0
2006......................................... 64.6 35.4
</TABLE>
(1) Includes contracts with GDP or other similar adjustment provisions.
In recent years, several public utility companies have approached
independent power producers, including the Company (each an "IPP"), to
renegotiate specified rates in their power purchase agreements alleging that
these agreements force the utilities to purchase power from IPPs at rates higher
than current avoided cost, resulting in higher rates to consumers. On October 6,
1995, Niagara Mohawk Power Corporation ("NIMO"), a customer of the Company which
accounted for approximately 18.4% of consolidated power sales revenues in fiscal
1996, submitted a proposal to the New York State Public Service Commission in
which, among other items, NIMO proposed that it be relieved of its obligations
under contracts with IPPs that NIMO considers uneconomic. While offering to
renegotiate such contracts, NIMO proposed that, should negotiations fail and
NIMO be unable to gain alternative economic relief, NIMO would seek to take
possession of associated projects through the power of eminent domain. In its
press release announcing this proposal, NIMO indicated that it would consider
the possibility of restructuring under Chapter 11 of the U.S. bankruptcy code
should its proposal prove unachievable. NIMO has also unilaterally imposed a
"generation cap" on three of the fifteen power purchase agreements it has with
the Company, reducing rates for power produced over a cap specified by the
utility and withholding what has been to date a small amount of revenues. In
response, the Company, in conjunction with other IPPs, has sought redress in
court and expects the case to be tried during fiscal year 1997. During the
summer of 1996, NIMO offered to buy out forty-four of its power sales contracts
with IPPs in exchange for an undisclosed combination of cash and NIMO stock.
NIMO has not offered to buy out any of the Company's power sales contracts in
conjunction with the group buy out offer and, as of September 20, 1996, has not
indicated whether any of the IPPs are willing to accept the terms of the
proposed buy out.
During 1994, the Company negotiated new contracts with two other
utility customers, the net effect of which was to reduce the power sales rates
paid to the Company through 1997 in exchange for extending the terms of the
contracts as well as the scheduled rate periods pursuant to such contracts. The
reduction in power generation revenue as a result of such negotiations, based on
average water flows, is expected to be approximately $2.1 million in fiscal 1997
compared to the revenue expected prior to the negotiations. Although the Company
believes that its power purchase agreements are valid, binding and enforceable
contracts, and economic when analyzed over the life of such contracts, and that
the arguments raised by the utilities fail to acknowledge that IPP power is
still often less expensive than alternative sources and less expensive than
rates that might prevail had the utilities built their own additional capacity,
there can be no assurance additional customers of the Company will not attempt
to modify their contracts with the Company and, if such attempts succeed, that
any such modifications will not have a material adverse effect on the Company's
future revenues. Additionally, increased competition in the electricity industry
might cause certain utilities to become higher credit risks. Although the
ratings of the debt securities of most of the utilities which purchase power
from the Company are currently investment grade, there can be no assurance of
the long-term creditworthiness of any of the Company's customers. Should any
customer fail, it might be difficult for the Company to replace an existing
long-term contract with such a customer with a new contract with another
customer
-10-
<PAGE>
on similar economic terms in the current environment. See Part II, Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources".
The Company has obtained certain power purchase agreements with
"front-loaded" scheduled rates that enhance the Company's ability to obtain
favorable non-recourse project financing. Front-loaded agreements provide for
payment by the utilities that are above avoided cost in the early years of the
agreement, thereby subsidizing the power producer in the early years. The
utility company may recover the initial subsidy (which, in some cases, is
secured or otherwise collateralized) in the later years of the contract if
avoided costs rise above the contract rate. The extent of a utility company's
recovery of subsidies contained in the Company's power contracts is typically a
function of power production levels and actual avoided cost rates.
Business Development
General. The performance of the Company in the future will be affected
by a number of factors, in addition to the structural changes to the electric
power industry described above. First, the Company competes for hydroelectric
and industrial energy projects with a broad range of electric power producers
including other independent power producers of various sizes and many
well-capitalized domestic and foreign industry participants such as utilities,
equipment manufacturers and affiliates of industrial companies, many of whom are
aggressively pursuing power development programs and have relatively low
return-on-capital objectives. Opportunities to acquire or develop power
generation assets on favorable economic terms in such an environment are
increasingly limited, particularly with regard to hydroelectric facilities.
Second, the Company is highly leveraged and its debt service obligations, the
cash portion of which commence in January 1999, along with its preferred stock
obligations, the cash portion of which commence in September 1998, make it
difficult to source capital on favorable terms that would allow the Company to
successfully pursue significant acquisition and development opportunities and,
in some cases, difficult to establish the creditworthiness necessary to develop
the project or to obtain contracts to develop products and services for the
industrial and utility customers described above.
Hydroelectric Acquisitions and O&M Contracts. To date, the Company has
expanded primarily by acquiring existing conventional hydroelectric facilities
in the United States. Although the Company continues to evaluate opportunities
to expand its hydroelectric business primarily through the acquisition of
additional operating facilities or projects in the later stages of development
and securing O&M contracts on hydroelectric facilities owned by third parties,
as explained above, such opportunities are expected to be severely limited. The
Company has taken over the ownership or management of 85 projects since fiscal
1986 representing an aggregate capacity of approximately 339 megawatts. The
Company evaluates projects on the basis of cash flow and will generally acquire
facilities that meet its rate of return criteria. Acquisition considerations
include (i) hydrological characteristics of the project and the region; (ii) the
operating history and condition of assets of the project and the ability to make
enhancements cost- effectively; (iii) the project's existing power purchase
agreements; (iv) the environmental and regulatory history of the project; and
(v) the project's geographical fit into the Company's existing portfolio.
The Federal Energy Regulatory Commission ("FERC") estimates that there
are approximately 24,500 megawatts of conventional hydroelectric facilities in
the United States owned by independent generators, by industrials (such as paper
companies) or by non-federal public entities such as municipalities, and
approximately 28,000 megawatts of hydroelectric capacity owned by investor-owned
utilities. Additionally, based on available information, the Company believes
there are over 5,000 megawatts of such facilities in Canada. The Company
believes that certain independent and industrial facilities, as well as smaller
municipal and utility projects, are the most likely candidates for acquisition
or for operation and maintenance contracts because, in many cases, the owner is
not primarily engaged in the business of hydroelectric ownership and operation
and might not view its hydroelectric facility as a productive asset, or might
not be able to operate the facility productively due to lack of expertise or
economies of scale.
Industrial Energy Development and Acquisition. In November 1995, the
Company established a subsidiary, CHI Power, Inc., for the purpose of
developing, acquiring, operating and managing industrial energy facilities and
-11-
<PAGE>
related industrial assets in such sectors as pulp and paper, petroleum refining,
chemicals, textiles, and other energy- intensive industries. The Company has
begun to seek opportunities for providing energy-related products and services
in an effort to respond to changing market conditions. Such opportunities, if
available, will permit the Company to move away from relying exclusively on
hydropower ownership and operation where the business climate is driven largely
by legislation and regulation and the structural industry trends described above
and where the Company currently believes that acquisition and development
opportunities are limited. Currently, all of the Company's revenue is derived
from the ownership and operation of hydroelectric facilities. The Company will
seek to acquire or develop the energy and infrastructure assets of energy and
capital intensive entities, such as pulp and paper, textiles, chemicals and
petroleum refining companies. Such assets may include assets used to produce
electricity, steam, or chilled water, or facilities used for chemical recovery,
storage, and water and wastewater treatment. These assets are typically
"non-core" assets that are necessary but ancillary to the customer's primary, or
"core", manufacturing activities. The customer may derive a financial benefit
from such an arrangement and may also benefit from the opportunity to focus its
resources on its core business, while the Company may benefit from the long-term
revenue stream resulting from such an arrangement. While the Company believes it
possesses the expertise to successfully complete such transactions, no such
transactions have been completed as of June 30, 1996 and there can be no
assurance that any such transactions will be completed in the future. The
Company may be disadvantaged in such transactions by a lack of widespread name
recognition and a highly leveraged balance sheet. Also, the Company's highly
leveraged capital structure and its debt service obligations, the cash portion
of which commence in January 1999, as well as its preferred stock obligations,
the cash portion of which commence in September 1988, may in some cases make it
difficult to establish the creditworthiness necessary to complete such
transactions.
Conventional Hydroelectric Development. Due to regulatory restrictions
that increase the cost of hydroelectric development, combined with the current
energy market in which low energy prices do not make hydroelectric development
economically attractive, the Company believes that near-term prospects for
successful development of new hydroelectric facilities in North America are
severely limited. However, the Company evaluates hydroelectric development
opportunities that occasionally arise, and currently is in the late stages of
developing a 15-megawatt project in Newfoundland, Canada, which the Company is
developing in partnership with another company. As of June 30, 1996 the
partnership had made substantial progress in obtaining required environmental
approvals for the project and had obtained a long-term power purchase agreement
for project output from the provincial utility. The project is scheduled to
begin construction in early 1997 with completion anticipated in late 1998.
However, there can be no assurance that the project will be successfully
developed, financed or completed.
Pumped Storage Development. As of June 30, 1996, the Company held
interests in the development of four pumped storage facilities through its
majority-owned subsidiaries Consolidated Pumped Storage, Inc. ("CPS") and Summit
Energy Storage Inc. ("SES"). The Company has concluded however, that the
prospects for successfully developing its pumped storage prospects are remote,
and is currently limiting its pumped storage activities to the minimum necessary
to maintain the viability of the Summit project and the monitoring of market
conditions relevant to the project with the intention of pursuing commitments
from utilities for the balance of the project's capacity. In fiscal year 1995,
the Company wrote off its $1.3 million investment in two of its early stage
pumped storage development projects, Boulder Valley and Lewis River. In fiscal
year 1996, in conjunction with its implementation of Statement of Financial
Accounting Standards No. 121 Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of ("SFAS 121"), the Company
additionally wrote off all but $0.1 million of its remaining pumped storage
investments, amounting to a write-off of $38.5 million. See Note 4 of the Notes
to the Consolidated Financial Statements for additional information.
In August 1996, the Company entered into a letter agreement, subject
to final documentation and other conditions, with Carol Cunningham, an executive
vice president of the Company and chief executive officer of CPS, pursuant to
which Ms. Cunningham has agreed to acquire CPS and each of its subsidiaries in
exchange for an early termination of her employment contract and certain other
considerations (see "Part III, Item 11, "Employment Contracts and Special
Employment Arrangements"). As a result, the Company's pumped storage interests
will be limited to the Summit project.
-12-
<PAGE>
Summit Project. The Company is the developer of the Summit project
through its majority owned subsidiary Summit Energy Storage Inc. ("SES"). The
project is the first independent sponsored pumped storage project to receive a
FERC license, which was issued in April 1991. The license required project
construction to commence by April 1993, a deadline that FERC extended under its
existing legal authority until April 1995. Under current federal laws, FERC does
not have authority to extend this deadline further unless authorized to do so by
the U.S. Congress by means of legislation enacted for this purpose. In February
1995, at the request of SES, identical legislation was introduced in the U.S.
Senate (S.468) and the House of Representatives (HR 1011) authorizing FERC to
extend the construction commencement date for up to three additional two-year
periods. FERC staff is aware of the proposed legislation and has continued to
routinely process project related submittals required under the conditions of
the license. As of June 30, 1996, HR 1011 had been passed by the House of
Representatives and S.468 had been approved unanimously by the Senate Energy
Committee. The Company believes that Congress will authorize FERC to extend the
construction deadline as specified in the current legislation and that FERC will
issue the required extension. However, no assurances can be given that Congress
or FERC will take such actions.
There are a number of significant steps, both financial and
operational, which must be completed prior to Summit's commencement of
commercial operation. These steps, none of which can be assured, include
entering into agreements, approved by appropriate regulatory bodies, for the
sale of all Summit's capacity, securing extension of the deadline for start of
construction from Congress and the FERC and additional development capital and,
additionally, contracting for and financing the approximately $2 billion project
construction cost and actual construction of the project. It is highly unlikely
that Summit will be successfully developed. See Part III, Item 13 "Certain
Relationships and Related Transactions".
Energy and Environmental Regulation
Energy Regulation. The Company is subject to federal and state (or in
Canada, provincial) energy laws and regulations in connection with the
development and operation of its hydroelectric and industrial energy projects.
Depending on the project, these laws and regulations may govern the ownership
structure of the projects, the rates, terms and conditions under which the
Company may sell electric output from the projects to utilities or other
customers, and the procedures under which these projects are constructed and
operated.
FPA. The Federal Power Act of 1935 ("FPA") is the federal statute
which provides the basic structure for regulating all aspects of hydroelectric
projects in the United States. The FPA grants the FERC exclusive rate-making
jurisdiction over wholesale sales of electricity in interstate commerce. The FPA
provides the FERC with on-going as well as initial jurisdiction, enabling FERC
to revoke or modify previously approved rates. Such rates may be based on
cost-of-service or are determined through competitive bidding or negotiation.
Licensing. The FPA also requires that substantially all of the
Company's existing hydroelectric projects be subject to varying degrees of
regulation by FERC. Depending upon their size and certain other factors, all
hydroelectric power projects must either be licensed by FERC or granted an
exemption from licensing, unless they are on non-navigable waterways and have
also been in continuous operation since 1935. Projects on public lands or using
federally owned dams must also obtain a license or exemption. The Company has
several unlicensed projects (all of which are small), as to some of which FERC
has asserted license jurisdiction. While the Company has had some success at
defeating or limiting this asserted jurisdiction, it has accepted jurisdiction
for some unlicensed projects and is proceeding with the licensing process. There
can be no assurance as to whether or not additional conditions that would
adversely affect project economics might be imposed in the course of such
process, nor as to the likelihood of FERC asserting jurisdiction on the
remaining unlicensed projects or on any additional conditions that might be
imposed in the course of licensing those projects.
The licensing and relicensing process is expensive, especially when
considering the small size of some of the affected projects. The licensing
process can require, among other things, preparation of an extensive
environmental assessment relating to the particular facility.
-13-
<PAGE>
For a conventional hydroelectric project, a FERC license typically
requires between two and three years to obtain (longer as the size and
complexity of the project increase). The increased scrutiny being given to
environmental concerns might result in delays which exceed the normal regulatory
time frames. Approximately 8% of the Company's current operating capacity of
wholly or partially-owned projects is subject to licensing or relicensing
requirements during the next twenty years. See "-- Conventional Hydroelectric
Projects".
ECPA. In 1986, Congress enacted the Electric Consumer Protection Act
("ECPA"), which amended the FPA to require that in addition to power production,
FERC give equal consideration to environmental concerns, including fish,
wildlife and recreation, in deciding whether to license or relicense a project.
ECPA requires FERC to give increased consideration to recommendations by federal
and state environmental agencies both in the licensing of new projects and
relicensing of old ones. This may result in the imposition of increased costs to
deal with environmental impact mitigation associated with the project.
PUHCA. Under the Public Utilities Holding Company Act of 1935, as
amended ("PUHCA"), any person (defined by PUHCA to include corporations and
partnerships and other legal entities) which owns or controls ten percent or
more of the outstanding voting securities of an "electric utility company" or a
company which is a "holding company" of an "electric utility company" is subject
to registration with the Securities and Exchange Commission and regulation under
PUHCA unless eligible for an exemption, such as is available to QFs under PURPA,
or as established elsewhere under PUHCA. A holding company of an electric
utility company is required by PUHCA to limit its operation to a single
integrated utility system and to divest any other operations not functionally
related to the operation of that utility system.
PURPA. The enactment in 1978 of PURPA and the adoption of regulations
thereunder by FERC provided incentives for the development of small power
production facilities meeting certain criteria.
Under PURPA, QFs (depending on their size and fuel source) are exempt
from certain provisions of PUHCA, the FPA and, except under certain limited
circumstances, state laws respecting rate or financial regulation. An electric
generating project must also be a QF in order to take advantage of certain rate
and regulatory incentives provided by PURPA.
The exemptions afforded by PURPA to QFs from extensive federal and
state regulation are important to the Company and its competitors. Except for
the projects which have been declared to be exempt wholesale generators ("EWG"),
each of the operating conventional hydroelectric projects in the U.S. that the
Company currently owns, operates or in which it has an investment meets the
requirements under PURPA for being a QF.
PURPA provides two primary benefits to QFs owned and operated by
independent generators. First, hydroelectric facilities which are less than 30
megawatts and are QFs, and certain non-hydroelectric generating facilities that
meet legal requirements for obtaining QF status, are relieved of compliance with
certain federal, state and local regulations which control not only the
development and operation of an energy-producing project, but also the prices
and terms on which energy may be sold by the project. Second, PURPA requires
that electric utilities purchase electricity generated by QFs at a price equal
to the purchasing utility's avoided cost. Avoided costs are defined by PURPA as
the "incremental costs to the electric utility of electric energy or capacity or
both which, but for the purchase from the QF, such utility would generate itself
or purchase from another source". The FERC regulations also permit QFs and
utilities to negotiate agreements for utility purchases of power at rates other
than the purchasing utility's avoided cost. While electric utilities are not
required by PURPA to enter into long-term contracts, PURPA helped to create a
regulatory environment in which it has become more common for such contracts to
be negotiated.
As an owner of QFs, the Company is exempt from many of the provisions
of the FPA and PUHCA. However, some larger hydroelectric facilities (including
all of the Company's pumped storage projects) do not, or will not when
operational, qualify as QFs. In addition, the Company believes that certain
industrial energy facilities that it may acquire or develop in the future may
not be QFs. The non-legal term for a non-utility facility that does
-14-
<PAGE>
not meet the requirements of a QF is an IPP. IPPs are subject to various degrees
of regulation by FERC under terms of the FPA. Most importantly, the rates
charged by IPPs to utilities for interstate power sales or leases are subject to
regulation by FERC. Traditionally, FERC requires that such rates be "just and
reasonable", which has meant that there is an embedded cost cap on such rates.
However, recently FERC has allowed IPPs to charge market-based rates under
certain conditions. The primary condition is that the IPP must demonstrate that
the rates were agreed to on an arm's-length basis and the IPP had no market
power over the purchaser. Even if FERC does allow market-based rates, the state
public service commission will also have the opportunity to review the purchase
by the utility in order to determine whether the specific power sales contract
or lease is consistent with the particular state's standards.
National Energy Policy Act. The National Energy Policy Act of 1992
("NEPAct") contains several provisions that affected opportunities for the
Company, both as an independent power producer and a developer of hydroelectric
and other generation facilities. For example, under this act the Company has
been able to file applications with FERC to qualify project entities as EWGs,
which are allowed to own and operate electric generating facilities which do not
have to meet the size, fuel, production and ownership requirements of PURPA to
be exempt from PUHCA. The projects the Company operates in Canada are EWGs. The
Company believes the EWG provisions of the NEPAct will be beneficial to
independent power developers seeking to build and operate large, non-QF
facilities, particularly with regard to raising equity capital from investors
unwilling to be regulated under PUHCA.
The NEPAct will also make it easier for the Company to invest in
Canada and other foreign countries through provisions which will enhance the
ability to invest in foreign-based generation facilities and to enter into
project ownership agreements with utilities without PUHCA regulation.
Certain provisions of the act also enhance FERC's authority to require
utilities to transmit electricity at the request of non-utility generators such
as the Company. However, full implementation of these provisions has been
delayed by factors such as regulatory delays in determining the appropriate
pricing of transmission services and competing legislative and regulatory
initiatives at the state level; thus, the actual impact of the NEPAct's
transmission provisions will not be fully ascertainable for some time. The clear
trend, however, of the NEPAct and such state initiatives, in management's
opinion, reflects an incremental deregulation of the utility industry and is
aimed at making the market for electricity more competitive and more accessible
to entities such as the Company and its competitors.
Other aspects of the NEPAct which have significance for hydroelectric
developers include a requirement that new projects on federal lands obtain
right-of-way permits from federal land management agencies; a broadening of the
existing ban on original FERC licenses on national park land; restrictions on a
licensee's right to exercise eminent domain on sites owned by governmental units
as parks; and reimbursement requirements for costs incurred by agencies studying
the license applications. The act also imposes statutory parameters on the
rights of agencies other than the FERC to prescribe and make mandatory fishways
requirements at new or relicensed projects and allows developers of
hydroelectric projects to hire third-party contractors at the developer's
expense, to speed up the licensing process.
Electric Industry Restructuring. In recent years the federal government
and many state governments have begun consideration of proposed legislation or
regulations that would partially or wholly deregulate the electric power
industry and institute competition at the level of retail electricity customers.
In April 1996, FERC issued Order No. 888 which, among other things, requires
electric utilities to file open access tariffs that offer others the same
transmission services that the electric utilities provide themselves, encourages
the establishment of Independent System Operators ("ISOs") as a means of fair
administration of an open-access transmission system, and provides for utility
recovery of investments that utilities do not expect to recover from their
ratepayers under deregulation ("Stranded Costs"). In late 1995 the California
Public Utility Commission issued an electric utility restructuring plan that
implements retail customer choice in phases beginning in 1998 and requires
divestiture of certain utility generating assets. Many other states (including
New York and Maine among those in which the Company has significant interests)
have considered, or are believed likely to consider, plans for electric utility
restructuring that
-15-
<PAGE>
may include asset divestiture, ISOs, retail customer choice, and Stranded Cost
recovery, although the details of such plans may vary considerably from state to
state and may be in conflict with another state's plans or with FERC's Order No.
888. In July 1996, a bill was introduced in the U.S. Congress (H.R. 3790,
"Electric Consumers' Power to Choose Act of 1996") which, among other things,
calls for full retail customer choice by 2000 and the repeal of PURPA and PUHCA
in states that provide for full retail electric competition. This bill is
considered unlikely to pass in its present form, but is viewed as a framework
for future federal electric industry restructuring legislation. The Company
believes that such restructuring, including significant elements of retail
competition, is likely within the next few years, with a variety of potential
impacts, both positive and negative, on the Company. In the area of acquiring
and developing industrial energy facilities, removing restrictions on retail
sales of energy to industrial customers is likely to enhance the Company's
prospects for completing transactions with such customers. In the area of
hydroelectric generation, it is uncertain to what extent the Company's smaller
hydroelectric facilities would be competitive in a fully deregulated energy
market without the current benefits of PURPA that require electric utilities to
purchase the output from these facilities. While the Company believes that its
existing long term power purchase contracts with utilities are legally binding
for the duration of the contracts, there can be no assurance that the provisions
of these contracts will not be affected by future legislation or regulation
dealing with electric industry restructuring. (see "-- Power Purchase
Agreements").
Environmental Regulation. The Company is subject to extensive federal,
state (and in Canada, provincial) and local environmental laws and regulations
applicable to the development and operation of its projects. Environmental laws
and regulations may affect the Company's operations by delaying construction of
a project or, although the Company has never experienced such an event, the
closing down of an operating project for a period of time. In addition,
environmental laws and regulations may affect the development time, site
selection and permitting of new projects. The development of a power generation
project typically requires numerous licenses, permits, approvals and
certificates from governmental agencies. Procedures followed by certain of these
permitting authorities may be affected by political factors. As of June 30,
1996, the Company has not applied for and obtained certain permits, approvals
and certificates for completion and operation of the projects in development,
but the Company does not foresee substantial difficulties in obtaining such
permits, approvals and certificates, or in complying with applicable legislation
and regulations. There can be no assurance, however, that the Company will be
able to obtain all necessary permits, approvals and certificates for the
proposed projects or that completed facilities will comply with all applicable
statutes and regulations.
The Company monitors applicable environmental laws and regulations and
evaluates its facilities for compliance with applicable standards. Based on
current trends, however, the Company expects that environmental and land use
regulation will become more stringent. Accordingly, the Company plans to
continue to place a strong emphasis on the development and use of its available
technology to minimize potentially harmful effects on the environment that may
result from the operation of its facilities. In addition, the Company has
developed expertise and experience in obtaining necessary licenses, permits and
regulatory approvals.
The Company's hydroelectric facilities are subject to environmental
regulatory requirements pursuant to their FERC licenses or exemptions or, in the
case of facilities not subject to FERC jurisdiction, applicable state
environmental requirements. The Company's prospective industrial energy
facilities are likely to be subject to federal and state laws and regulations
governing atmospheric emissions and, in some cases, governing the discharge of
effluents into water bodies. Environmental regulatory requirements for such
facilities are often complex, and specific requirements are dependent upon the
nature of the individual project and site.
Precipitation, Water Flow and Seasonality
For hydroelectric facilities, the amount of energy generated at any
particular facility depends upon the quantity of water flow at the site of the
facility. Dry periods tend to reduce water flow at particular sites below
historical averages, particularly if the facility has low storage capacity.
Excessive water flow may result from prolonged periods of higher than normal
precipitation or sudden melting of snow packs, possibly causing flooding of
facilities and/or a reduction of generation at such sites until water flows
return to normal. In cases of reduced
-16-
<PAGE>
or excess water flow, energy generation at such sites may be diminished.
Pursuant to the Company's power purchase agreements, any diminished energy
generation will have an adverse effect on revenues from that facility. While the
Company does not have business interruption insurance to cover lost revenues as
a result of drought or dry periods, the Company maintains business interruption
insurance to cover, among other things, the loss of revenues above certain
deductible levels, and subject to applicable insurance policy sub-limits and
overall limits, arising from interruption of electricity generation due to
damage caused by flooding and other catastrophic events.
Production of electricity by the Company is typically greatest in its
third and fourth fiscal quarters (January through June), when water flow is at
its highest at most of the Company's projects, and lowest in the first fiscal
quarter (July through September). The Company normally shuts down selected
operations for periods during the relatively dry first fiscal quarter in order
to perform routine maintenance. The amount of water flow in any given period
will have a direct effect on the Company's production, revenues and cash flow.
Competition
In its hydroelectric business, the Company competes with a number of
smaller and regional independent hydroelectric development companies (e.g.,
Adirondack Hydro Development Corp., Synergics, Inc., Independent Hydro
Developers, Inc., STS HydroPower, Ltd. and Developpements HydroMega, Inc.) and,
on occasion, with other independent energy producers (e.g., Ogden Corp.),
utilities and utility subsidiaries (e.g., Georgia Power Company, CRSS and Ida
West) for the rights to acquire and develop additional conventional
hydroelectric projects, which may cause fewer projects to be available at prices
that will permit the level of return on investment which the Company seeks.
As the hydroelectric industry has matured, the strength and number of
the Company's competitors from among the smaller and regional independent
hydroelectric development companies have declined. Many factors, including the
increasingly complex environmental and regulatory requirements, the expiration
of certain tax incentives and tax recapture provisions, coupled with the
tightened credit environment, have accelerated the maturation of the independent
hydroelectric industry. Based on available information, the Company currently
believes it has more power producing capacity than its next three largest
competitors in the U.S. independent hydroelectric power industry combined. The
decline of the smaller and regional independent producers has been accompanied
by increasing competition for available properties from both domestic and
international utility affiliates, thereby driving down competitive rates of
return and making it more difficult for the Company to successfully acquire
additional projects.
Substantially all energy output from the Company's projects is sold to
various utilities pursuant to long-term power purchase agreements requiring the
purchase of such output. However, increasing competition within the electric
power industry, declining natural gas prices in real terms, and ongoing
technological improvements have driven down avoided costs and may negatively
affect the power purchase rates the Company can obtain in the future. The
Company competes for opportunities with a broad range of electric power
producers including other independent power producers of various sizes and many
well-capitalized domestic and foreign industry participants such as utilities,
equipment manufacturers and affiliates of industrial companies, many of whom are
aggressively pursuing power development programs and have relatively low
return-on-capital objectives. Prices for electricity have declined in recent
years as a result of reductions in the cost of power produced from natural gas
due to lower natural gas prices and technological improvements which have
lowered the capital cost and increased the efficiency of combustion turbines and
other competing technologies. Federal regulators and a number of states,
including some in which the Company operates, are exploring ways in which to
increase competition in electricity markets, most notably by opening access to
the transmission grid. Although the character and extent of this deregulation
are as yet unclear, the Company expects that these efforts will increase
uncertainty with respect to future power prices and make it more difficult to
obtain long-term power purchase contracts. In its industrial energy business,
the Company competes with a large number of well capitalized companies,
including many U.S. and foreign electric utilities and their affiliates, who are
also attempting to serve the energy needs of industrial companies. However, the
Company
-17-
<PAGE>
believes that there are relatively few companies seeking to serve the industrial
energy market in the same manner as the Company, principally through
requirements-based contracts and by offering multiple products and services.
Properties Owned and Leased
The Company leases its administrative offices at 680 Washington
Boulevard, Stamford, Connecticut under a lease calling for annual lease payments
of approximately $170,000 per year. Additional administrative offices and
maintenance facilities are leased in Houston, Texas; Greenville, South Carolina;
Anderson, California; Boise and Twin Falls, Idaho; Andover, Massachusetts; North
Bend, Washington; and Montreal, Canada with aggregate annual rental payments of
approximately $200,000. The Company owns administrative offices in Lawrence,
Massachusetts and Dexter, New York and a maintenance facility in Sanford, Maine.
In addition to the foregoing, the Company owns and leases real estate
in California, Connecticut, Idaho, Massachusetts, Maine, New Hampshire, New
York, Ohio, Oregon, Pennsylvania, Washington, Virginia, South Carolina, North
Carolina, Vermont, and Georgia. Except for certain small non-hydroelectric real
estate parcels, this additional real estate constitutes property used in the
hydroelectric generating projects operated by the Company. In the case of each
of the conventional hydroelectric projects owned or leased by the Company, the
project generally consists of a dam, water rights and interests and rights in
real estate sufficient for the purposes of operating the facility, a powerhouse
for the generation of electricity and other necessary equipment. Except as
listed in the table entitled "Projects with Partial Ownership as of June 30,
1996" under "Conventional Hydroelectric Projects" above, such property and the
federal and state permits and licenses are owned or leased by one or more
subsidiaries of the Company or various limited partnerships in which such
subsidiaries are the sole general and limited partners. The water rights held by
the Company are subject to various restrictions and limitations with respect to
environmental and other matters. In the opinion of management, none of such
restrictions will have a material adverse effect on the business or operations
of the Company.
Employees
The Company employs approximately 160 full-time and 100 part-time and
temporary employees as of September 15, 1996. The Company's current employees
are not represented by a collective bargaining group, and management considers
its relations with employees to be good.
Certain Risk Factors
Certain statements contained in this Form 10-K that are not related to
historical facts may contain "forward looking" information, as that term is
defined in the Private Securities Litigation Reform Act of 1995. Such statements
are based on the Company's current beliefs as to the outcome and timing of
future events, and actual results may differ materially from those projected or
implied in the forward looking statements. Further, certain forward looking
statements are based upon assumptions of future events which may not prove to be
accurate. The forward looking statements involve risks and uncertainties
including, but not limited to, the uncertainties relating to the Company's
existing debt, industry trends and financing needs and opportunities; risks
related to hydroelectric, industrial energy, pumped storage and other
acquisition and development projects; risks related to the Company's power
purchase contracts; risks and uncertainties related to weather conditions; and
other risk factors detailed herein and in other of the Company's Securities and
Exchange Commission filings. Certain of these risks are discussed more fully
below and should be carefully considered along with the other matters described
herein.
High Leverage; Deficiency of Earnings to Fixed Charges and Preferred
Stock Dividends; Maturing Obligations
The Company is highly leveraged, primarily as a result of a management
buyout in 1988 (the "Management Buyout") (see Part III, Item 13, "Certain
Relationships and Related Transactions -- GECC Relationship"), the refinancing
of debt and capital in 1993 (See Note 10 of the Notes to Consolidated Financial
Statements) and the limited recourse and non-recourse debt financing of the
acquisitions of its conventional hydroelectric power plants.
-18-
<PAGE>
As of June 30, 1996, the Company's total liabilities were $413.3 million,
including $98.6 million of mandatorily redeemable preferred stock, its total
assets were $244.7 million and its stockholders' deficit was $168.6 million. For
each of the years ended June 30, 1996, 1995, 1994, 1993 and 1992, the earnings
(before fixed charges, provisions for income taxes, extraordinary items and
cumulative effect of accounting change) net of non-cash charges to cover
fixed charges ratios were 1.61, 1.34, 1.32, 1.08 and 1.10, respectively. For the
years ended June 30, 1996, 1995, 1994, 1993 and 1992, the deficiency of earnings
(before fixed charges, preferred stock dividends, provision for income taxes,
extraordinary items and cumulative effect of accounting change) and net of
non-cash charges to cover fixed charges and preferred stock dividends were $5.2
million, $13.1 million, $13.1 million, $16.9 million, and $6.2 million,
respectively. See calculations in Item 6, "Selected Financial Data", Footnotes
10 and 11.
The Company expects that, through calendar 1998, it will generate
sufficient cash flows from existing operations to meet its capital expenditure
and working capital requirements. Commencing on September 30, 1998, however,
cash dividends become payable on the Company's 13 1/2% Cumulative Redeemable
Exchangeable Preferred Stock (the "Series H Preferred Stock") and on January 15,
1999, cash interest becomes payable on the Company's 12% Senior Discount Notes
due 2003, Series B (the "Senior Discount Notes"). In order to meet such
obligations, the Company currently anticipates that it will have to rely on
proceeds from asset sales, additional debt or equity offerings or other sources.
However, the Company also currently anticipates that it may not be able to
obtain the necessary additional debt or equity financing or sufficient proceeds
from asset sales or other sources in order to satisfy such dividend and interest
payment obligations on a timely basis as well as meet the Company's other
obligations, including accrued and unpaid dividends since issuance under the
Series F Preferred Stock, and its capital expenditure and working capital
requirements at such time. As a result, it may be necessary to restructure the
Company's debt and equity structure either before or at such time. In addition,
the Company anticipates that it would need to obtain financing for the principal
payments on its Senior Discount Notes at their maturity in 2003 and to redeem
the Series H Preferred Stock at its 2003 redemption date. There can be no
assurance that any such additional financing will be available to the Company.
Also, the Company may consider from time to time, either prior to 1998 or
thereafter, the use of available cash, if any, to engage in repurchases of the
Senior Discount Notes, subject to applicable contractual restrictions and other
appropriate uses, in negotiated transactions or at market prices. There can be
no assurance that, if the Company decides to engage in repurchases of the Senior
Discount Notes, any Senior Discount Notes will be available for repurchase by
the Company on terms that would be favorable or acceptable to the Company.
Restrictions Imposed by the Company's Existing Indebtedness
The Indenture relating to the Senior Discount Notes (the "Indenture")
and the certificate of designation relating to the Series H Preferred Stock (the
"Certificate of Designation") as well as the working capital facility (the "DnB
Facility") with Den norske Bank ("DnB") (see Part II, Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Summary of Indebtedness") contain certain restrictive covenants. Such
restrictions will affect, and in many respects will significantly limit or
prohibit, among other things, the ability of the Company to incur recourse
indebtedness, make prepayments of certain indebtedness, pay dividends, make
investments, engage in transactions with stockholders and affiliates, issue
capital stock of restricted subsidiaries, create liens, sell assets and engage
in mergers and consolidations. The covenants are subject to various exceptions
which are generally designed to allow the Company to continue to operate its
business without undue restraint and, therefore, are only limited prohibitions
with respect to certain activities.
There can be no assurance that the Company will be able to comply with
covenants and other restrictions contained in the Indenture, its other
indebtedness and the Certificate of Designation. In the event of a default under
the terms of any of the indebtedness of the Company, the obligees thereunder
would be permitted to accelerate the maturity of such obligations, which may
cause defaults under other obligations of the Company.
As of June 30, 1996, the Company was in compliance with its covenants
under the DnB Facility. However, as of March 31, 1996 based on the Company's
financial performance for the twelve month period then ended, the Company
continued to be unable to meet one of the financial covenants as required under
the DnB Facility. In
-19-
<PAGE>
response to an earlier request from the Company, the bank had waived compliance
with respect to the covenant for the twelve month period ended September 30,
1995 and, pending a further review of the Company's performance and
opportunities, has limited availability under the DnB Facility to $6.1 million,
the amount outstanding to provide letters of credit at September 27, 1995. Due
to the extremely low water flow in the Northeast region during the fourth
quarter of fiscal 1995 and the first quarter of fiscal 1996, and because the
measurement contained in the financial covenant is applied at the end of each
fiscal quarter on the basis of the four most recently completed quarters, the
Company was unable to meet the covenant for the twelve months ended December 31,
1995.
DnB has not waived the previous defaults by the Company but has offered
to do so in conjunction with the execution by the Company of an amendment which
will, among other things, change the final expiration date of the DnB Facility
to June 30, 1998 from June 30, 1997, reduce (in steps) the total commitment
under the facility from approximately $6.0 million at September 30, 1996 to zero
at June 30, 1998, limit the use of the facility to letters of credit and modify
certain financial covenants. The Company is currently negotiating the amendment
and waiver with DnB. There can be no assurance that the Company and DnB will
reach agreement on the terms of such an amendment. If the additional waiver is
not granted, the Company may need to replace some or all of the outstanding
letters of credit with cash deposits or other letters of credit which could be
more expensive, if available. If the Company fails to reach agreement with DnB
and the outstanding letters of credit are not replaced, it is likely that the
letters of credit under the DnB Facility will be drawn upon. If the indebtedness
created by such drawn letters of credit is not paid when due, a default under
the DnB Facility would occur and all amounts outstanding thereunder would become
due and payable after the passage of applicable notice and grace periods. The
Company does not currently expect that it will require use of the DnB Facility
for additional working capital purposes during fiscal 1997.
The DnB Facility contains certain affirmative and restrictive covenants
which are generally consistent with the terms of the Senior Discount Notes and
the Series H Preferred Stock. As of June 30, 1996, no borrowings were
outstanding under the DnB Facility, approximately $5.9 million of the DnB
Facility was employed to provide letters of credit as of June 30, 1996 and 1995,
respectively.
Leveraged Project Financing
The Company's existing hydroelectric projects are, and its future
hydroelectric and industrial projects, if any, would likely be financed using a
variety of structures primarily consisting of limited recourse or non-recourse
debt. As of June 30, 1996, the Company had $115.5 million (exclusive of the
Boott project operating lease) of direct project financing obligations that are
limited recourse or non-recourse to CHI. As limited recourse or, except to the
extent set forth below, non-recourse obligations, each such obligation is
structured to be fully serviced out of each applicable project's cash flow,
generally without any claim against CHI's general corporate funds. In the event
of a project default and assuming CHI is unable or chooses not to cure such
default within applicable cure periods (if any), the lenders or lessor would
generally have rights to the facility, related contracts and all licenses and
permits necessary to operate the facility and, in the event of foreclosure after
such a default, the Company might not retain any interest in such project.
Certain project acquisitions have been financed by General Electric
Capital Corporation ("GECC"), which has required the guarantee of CHI
Acquisitions, Inc. ("CHI Acquisitions"), a subsidiary of CHI which is the parent
of each of the entities formed to acquire such projects. Thus, each such project
is vulnerable in the event of a default by any of the other projects owned
indirectly by CHI Acquisitions. Although all of this guaranteed financing has
been repaid, a tax indemnity and performance guarantee relating to one project
will remain (see Note 11 of the Notes to Consolidated Financial Statements for
additional information with respect to the tax indemnity). Certain other
projects acquired by CHI Acquisitions II, Inc. ("CHI Acquisitions II"), a
subsidiary of CHI, were financed by CHI Acquisitions II with two loans from GECC
(see Note 5 of the Notes to Consolidated Financial Statements for additional
information). One such loan has been secured by the projects acquired and the
other loan by the cash flows of certain other projects of which CHI Acquisitions
II is the parent. In addition, there can be no assurance that, in respect of any
financing of projects in the future, GECC will not require CHI Acquisitions, CHI
Acquisitions II or another subsidiary of CHI to guarantee or otherwise secure
the indebtedness in respect of such future projects, rendering projects owned by
such guaranteeing subsidiary vulnerable in the event of a default in respect of
any one of such projects.
-20-
<PAGE>
Net Losses, No Assurance of Future Profitability
The Company incurred the following net losses for each of the last five
fiscal years: $88.3 million for the fiscal year ended June 30, 1996 including
$87.2 million of a non-cash charge for the impairment of long-lived assets;
$16.3 million for the fiscal year ended June 30, 1995 (including a $1.3 million
of a non-cash charge for the impairment of long-lived assets); $33.6 million for
the fiscal year ended June 30, 1994 (including $19.2 million for a non-cash
charge related to a cumulative effect of an account change); $10.8 million for
fiscal year ended June 30, 1993; and $37.8 million for fiscal year ended June
30, 1992 (including $30.5 million of non-cash charges relating to the
Recapitalization). These results were due primarily to the effects of the debt
and other costs associated with the extensive acquisition program carried on
since the Company's inception, the 1988 Management Buyout and, with respect to
the fiscal years ended June 30, 1992 and 1993, the Recapitalization and the
Refinancing, respectively, and accounting requirements associated with their
respective components and with respect to fiscal year ended June 30, 1996, the
charge for the impairment of long-lived assets. There can be no assurance of the
future profitability of the Company.
Dependence on Precipitation and Effects of Variations in Water Flow
and Seasonality
The amount of hydroelectric energy generated at any particular
conventional hydroelectric facility depends upon the quantity of water flow at
the site of the facility. In cases of reduced or excessively high water flow,
energy generation at such site may be diminished, particularly if the facility
has low storage capacity. Pursuant to the Company's power purchase agreements,
any diminished energy generation will have an adverse effect on revenues from
that facility. In the three years prior to 1996, the Company experienced low
water flow relative to long-term indications at many of its facilities. The
effect on revenues of the lower than average flows was most adverse in the
Northeast, a region in which a majority of the Company's projects are located
and where the Company's rates received for power sales are highest on average.
The Northeast region experienced below average water flows during 1995, 1994 and
1993, while experiencing above average flows in 1996. While the Company does not
have business interruption insurance to cover lost revenues as a result of
drought or dry periods, the Company carries business interruption insurance to
cover, among other things, the loss of revenues above certain deductible levels
and subject to applicable insurance policy sub-limits and overall limits arising
from interruption of electricity generation due to damage caused by flooding.
There can be no assurance that such coverage will remain available on acceptable
terms. In general, the business interruption insurance carried on any one
project is intended to cover damages in an amount of up to one year's revenue
from such project. There can be no assurance that the Company's business
interruption insurance will be adequate to cover any damages in excess of such
amounts, and any business interruptions resulting in claims in excess of the
amount of such coverage could have a material adverse effect on the Company.
Production of electricity by the Company is typically greatest in its
third and fourth fiscal quarters (January through June), when water flow is at
its highest level at most of the Company's projects, and lowest in the first
fiscal quarter (July through September). The amount of water flow in any given
period will have a direct effect on the Company's production, revenues and cash
flow.
Changes in Applicable Rates; Energy Price Declines
From 1997 through 2006, rates paid to the Company pursuant to power
purchase agreements representing approximately 35.4% of the Company's average
power sales revenues for the fiscal year ended June 30, 1996, will be affected
by changes from scheduled rates to rates based on the applicable utilities' then
current avoided cost. Use of avoided cost is driven by either the specific terms
of certain power purchase agreements or the expiration of the remaining
agreements during the period presented and the assumed utility purchase of
project generation, in accordance with the requirements of PURPA and the
regulations adopted thereunder. A utility's avoided cost rate is equal to the
incremental cost that would have been incurred if the utility had generated the
energy itself or purchased it from another source. Consequently, the Company's
revenue at such time will be adversely affected if the then current utility
avoided cost is lower than the scheduled rate previously in effect.
The majority of the generating capacity of the Company's operating
projects is contracted through 2020. However, if energy prices remain at current
levels or decline, the rates negotiated by the Company for new contracts,
contract rates based upon utility avoided costs or extensions of existing
contracts could be adversely affected. In recent years, several public utility
companies have approached independent power producers, including the Company
-21-
<PAGE>
(each an "IPP"), to renegotiate specified rates in their power purchase
agreements alleging that these agreements force the utilities to purchase power
from IPPs at rates higher than current avoided cost, resulting in higher rates
to consumers. In addition to directly challenging contracts, a number of
utilities have begun challenges in Congress to certain provisions of PURPA as no
longer appropriate in the current U.S. energy market. Niagara Mohawk Power
Corporation ("NIMO"), a customer of the Company which accounted for
approximately 18.4% of consolidated power sales revenues in fiscal 1996, has
unilaterally imposed a "generation cap" on three of the fifteen power purchase
agreements it has with the Company, reducing rates for power produced over a cap
specified by the utility and withholding what has been to date a small amount of
revenues. In response, the Company, in conjunction with other IPPs, has sought
redress in court and expects the case to be tried during fiscal year 1997.
Dependence on Commonwealth Electric Company ("CEC"), Central Maine Power
Company("CMP"), Niagara Mohawk Power Corporation, New England Power Company
("NEPCO") and Duke Power Company ("Duke"); Creditworthiness of the Company's
customers.
A substantial portion of the Company's power is sold to five customers
pursuant to various long-term power purchase agreements. Sales to CEC, CMP,
NIMO, NEPCO and Duke represented approximately 19%, 17%, 18%, 10% and 7%,
respectively, of the consolidated revenues of the Company for the fiscal year
ended June 30, 1996. On October 6, 1995, NIMO, a customer of the Company which
accounted for approximately 18.4% of consolidated power sales revenues in fiscal
1996, submitted a proposal to the New York State Public Service Commission in
which, among other items, NIMO proposed that it be relieved of its obligations
under contracts with independent power producers that NIMO considers uneconomic.
While offering to renegotiate such contracts, NIMO proposed that, should
negotiations fail and NIMO be unable to gain alternative economic relief, NIMO
would seek to take possession of associated projects through the power of
eminent domain. In its press release announcing this proposal, NIMO indicated
that it would consider the possibility of restructuring under Chapter 11 of the
U.S. bankruptcy code should its proposal prove unachievable. The Company
understands that the ratings of the debt securities of NIMO were lowered to
below investment grade following NIMO's filing of a proposal with the New York
State Public Service Commission on October 6, 1995. During the summer of 1996,
NIMO offered to buy out forty-four of its power sales contracts with IPPs in
exchange for an undisclosed combination of cash and NIMO stock. NIMO has not
offered to buy out any of the Company's power sales contracts in conjunction
with the group buy out offer and, as of September 20, 1996, has not indicated
whether any of the IPPs are willing to accept the terms of the proposed buy out.
There can be no assurance of the long-term creditworthiness of any of the
Company's customers.
Energy and Environmental Regulation
All of the Company's existing operating hydroelectric projects, while
exempt from public utility regulation, are subject to varying degrees of
regulation by FERC and state agencies. Depending on their size and certain other
factors, all hydroelectric projects that have not been in continuous operation
since prior to enactment of FPA, administered by FERC, must be either licensed
by FERC or granted an exemption from licensing. Substantially all of the
Company's generating capacity has either been licensed or granted an exemption
from licensing. As of June 30, 1996, the Company had 12 hydroelectric projects
aggregating 7.8 megawatts which were neither licensed nor granted an exemption
from licensing, though certain of these projects aggregating 2.3 megawatts have
been declared non-jurisdictional by FERC (that is, not subject to licensing or
exemption requirements). There is no guarantee that a FERC license can be
obtained or renewed. Although the Company has not encountered significant
difficulties in transferring, amending or obtaining licenses, there can be no
assurance that it will not encounter significant difficulties in this regard in
the future, nor can there be any assurance that existing regulations will not be
revised or that new regulations will not be adopted or become applicable to the
Company that could have an adverse effect on its operations.
The Company's activities require numerous permits, approvals and
certificates from appropriate federal, state and local government agencies as
well as compliance with certain environmental protection legislation and the
FPA. While the Company believes it has obtained the requisite approvals for its
existing operations and that its business is operated in accordance with
applicable law, it remains subject to a varied and complex body of regulations
that both public officials and private individuals may seek to enforce. Such
laws and regulations may affect operations by delaying construction or forcing a
temporary or permanent closure of a project and may affect site selection or
permitting of new projects. Based on current trends, the Company expects that
environmental and land use regulation will become more stringent. There can be
no assurance that existing regulations will not be revised or that new
-22-
<PAGE>
regulations that could have an adverse effect on its operations, will not be
adopted or become applicable to the Company nor can there be any assurance that
the Company will be able to obtain all necessary licenses, permits, approvals
and certificates for proposed projects or that completed facilities will comply
will all applicable statutes or regulations.
Uncertainty as to Success of Acquisition of Additional Capacity and
O&M Contracts and Development
Hydroelectric Acquisitions and O&M Contracts. The Company believes that
opportunities to continue to expand its conventional hydroelectric generation
business through the acquisition of additional facilities and the securing of
O&M contracts are likely to be severely limited. There can also be no assurance
that the Company will be able to take advantage of such opportunities on terms
acceptable to it, nor can there be any assurance that the Company will be able
to obtain financing, on the basis described above or otherwise, with respect to
such opportunities. In addition, a number of industry issues, including issues
related to the availability, term and pricing of future power purchase
agreements and higher acquisition prices resulting from increased competition in
certain segments are limiting and are expected to continue to limit the
Company's near term opportunities to acquire additional hydroelectric capacity
at acceptable rates of return. See Part II, Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources".
Hydroelectric Development. Due to regulatory restrictions that increase
the cost of hydroelectric development combined with the current energy market in
which low energy prices do not make hydroelectric development economically
attractive, the Company believes that near-term prospects for successful
development of new hydroelectric facilities in North America are severely
limited. The development of new hydroelectric projects includes certain risks
not associated with the purchase of operating facilities, including licensing,
environmental, engineering, equipment, power sales, construction and
distribution risks, as well as implementation risks such as cost overruns,
delays and performance risks. There is no assurance that the Company will be
able to raise development capital and obtain satisfactory project development
agreements, construction contracts, power purchase agreements, licenses and
permits or financing commitments with respect to the projects currently under
development or any projects that the Company might wish to develop in the
future. The Company has not applied for and obtained all permits, approvals and
certificates for completion and operation of certain projects under development.
The failure of the Company to obtain all such permits, approvals and
certificates could have a material adverse effect on the Company's development
program. Further, there can be no assurance that equity or non-recourse or
limited recourse development capital, similar to that which the Company has used
generally to finance development projects, is currently available or will be
available on a similar basis in the future. If the Company terminates a project,
it would generally not be able to recover its investment in such a project and
would expense all capitalized development costs incurred in connection
therewith.
Pumped storage project development shares all of the regulatory
requirements and inherent risks of conventional hydroelectric project
development in addition to the risks associated with longer development and
construction schedules. In addition, because of their size, pumped storage
facilities are not QFs from which utilities are required to purchase power and
are not insulated from federal rate regulation; as a result, these projects are
also subject to the risk of the FERC not approving power sales agreements or
leases at negotiated rates. Although pumped storage facilities have been
successfully constructed in the United States, no independent pumped storage
facilities have been constructed to date.
The continued restructuring and other events which have created
uncertainty regarding the future structure of the U.S. utility industry have
made it increasingly difficult to secure long-term contracts with utilities and
have, therefore, significantly slowed the development of the company's pumped
storage projects. As a result, the Company has concluded that the prospects for
successfully developing its pumped storage prospects are remote, and is
currently limiting its pumped storage activities to the minimum necessary to
maintain the viability of the Summit project as well as the monitoring of market
conditions relevant to the project with the intention of pursuing commitments
for the balance of the project's capacity. There can be no assurance that the
industry climate will not further adversely affect the Company's Summit project
causing the Company to cease altogether its development efforts. While the
Company has invested significant time and effort in the development of the
Summit project, numerous steps remain to be completed prior to financing,
construction and commencement of commercial operations, and no assurance can be
provided that this project will be successfully developed.
-23-
<PAGE>
Industrial Energy Development and Acquisition. Recognizing the barriers
to continued growth in its hydroelectric business, in November 1995, the Company
established a subsidiary, CHI Power, Inc., for the purpose of developing,
acquiring, operating and managing industrial energy facilities and related
industrial assets in such sectors as pulp and paper, petroleum refining,
chemicals, textiles, and other energy-intensive industries. The Company has
begun to seek opportunities for providing energy-related products and services
to industrial and utility customers in an effort to respond to changing market
conditions. Such opportunities, if available, will permit the Company to move
away from relying exclusively on hydropower ownership and operation where the
business climate is driven largely by legislation and regulation and certain
adverse trends and where the Company currently believes that acquisition and
development opportunities are limited. Currently, all of the Company's revenue
is derived from the ownership and operation of hydroelectric facilities. The
Company believes that opportunities exist for industrial energy transactions and
that it possesses the required technical and development expertise to complete
such transactions successfully. However, the Company may be disadvantaged in
such transactions by lack of widespread name recognition and a highly leveraged
balance sheet. As of June 30, 1996 the Company had not completed any such
transaction, and there can be no assurance that any such transaction will occur.
Effective Subordination of Senior Discount Notes as a Result of
Incurrence of Additional Indebtedness
The Indenture permits, subject to certain limitations, the Company to
incur a substantial amount of additional indebtedness, including senior
indebtedness, indebtedness secured by the liens on the Company's assets and an
unlimited amount of indebtedness that is Non-Recourse Debt (as defined in the
Indenture). The Indenture permits the Company to incur any indebtedness, all of
which would be pari passu with and, if incurred by a subsidiary of CHI,
effectively senior to the Senior Discount Notes, if after giving effect to the
incurrence of such indebtedness, the Company's Interest Coverage Ratio (as
defined in the Indenture) through January 14, 1999 is at least 1.25:1 and
thereafter is at least 1.50:1. For the fiscal year ended June 30, 1996, the
Company's Interest Coverage Ratio was .99:1. Without regard to the Company's
Interest Coverage Ratio, the Company may incur an unlimited amount of
Non-Recourse Debt in connection with the acquisition or refinancing of a
facility, all of which may be secured by the assets of such facility. To the
extent such Non-Recourse Debt is incurred by a subsidiary of CHI and is secured,
it would be effectively senior to the Senior Discount Notes. The Company has
financed and expects to continue to finance a substantial number of its
acquisitions using Non-Recourse Debt.
Control by MSLEF II and Madison
As of September 15, 1996, MSLEF II owns 80.0% of the Company's Series F
and Series G Preferred Stock which currently has 25 votes per share and which
would, if converted, currently represent 48.8% of CHI's Common Stock on a fully
diluted basis. Madison Group, L.P. owns 17.8% of the Company's Series F and
Series G Preferred Stock which would, if converted, currently represent 10.8% of
CHI's Common Stock on a fully diluted basis. See Part III, Item 12, "Security
Ownership of Certain Beneficial Owners and Management". The general partner of
MSLEF II and Morgan Stanley & Co. Incorporated ("Morgan Stanley") are both
wholly owned subsidiaries of Morgan Stanley Group Inc. ("MS Group"), and two of
the directors of the Company are officers of Morgan Stanley. As a result of
these relationships, MS Group and its affiliates will continue to have
significant influence over the management policies and corporate affairs of the
Company.
As a result of such ownership and certain rights of MSLEF II and
Madison (together, the "Investors"), pursuant to CHI's Restated Certificate of
Incorporation and the Amended and Restated Stockholders, Option holders and
Warrantholders Agreement, dated as of March 25, 1992 (as it may be amended from
time to time, the "Stockholders Agreement") among CHI and certain stockholders,
optionholders and warrantholders of CHI, MSLEF II would be in a position, acting
either separately or together with Madison, to control the affairs of CHI, under
certain circumstances. In addition, the Investors have granted each other
certain first refusal rights in the event one of them approves a sale of CHI to
an independent third party.
Certain decisions concerning the operations or financial structure of
the Company may present conflicts of interest between or among the holders of
CHI's voting capital stock and its other securities. For example, if the Company
encounters financial difficulties, or is unable to pay its debts as they mature,
the interests of CHI's equity investors might conflict with those of the holders
of the Senior Discount Notes or the holders of the Series H Preferred Stock. In
that regard, Morgan Stanley, as a holder of the Senior Discount Notes and Series
H Preferred Stock may, in certain circumstances, have interests that are
different than those of other holders of the Senior
-24-
<PAGE>
Discount Notes or Series H Preferred Stock. In addition, the equity investors
may have an interest in pursuing acquisitions, divestitures, financings or other
transactions that, in their judgment, could enhance their equity investment,
even though such transactions might involve risks to the holders of the Senior
Discount Notes or the holders of the Series H Preferred Stock. Morgan Stanley
has certain agreements with the Company pursuant to which Morgan Stanley may be
compensated for advice to the Company and its affiliates. (See Part III, Item 13
"Certain Relationships and Related Transactions)".
Item 2. Properties
The information concerning properties required by Item 2 is set forth
in Part I, Item 1, of this Form 10-K.
Item 3. Legal Proceedings
CHI's management currently believes that none of the pending claims
against the Company will have a material adverse effect on the Company.
Item 4. Submission of Matters to A Vote of Security Holders
There were no matters submitted during the fourth quarter of the year
ended June 30, 1996.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
As of September 15, 1996, the number of holders of record of the Class
A Common Stock of CHI was 55, and no shares of Class B Common Stock are
outstanding. There is no public market for CHI's Common Stock. No dividends were
declared on either class of CHI's Common Stock in fiscal 1996 or 1995.
-25-
<PAGE>
Item 6. Selected Financial Data
The following Income Statement and Balance Sheet Data has been derived
from financial statements audited by Price Waterhouse LLP, independent
accountants. The data set forth below should be read in conjunction with the
Consolidated Financial Statements for the fiscal years ended June 30, 1996,
1995, 1994, 1993 and 1992, and the related Notes thereto, and Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations":
<TABLE>
<CAPTION>
Year Ended June 30,
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(Dollars in Thousands, Except Per Share Amounts)
----------------------------------------------
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Revenue
Power generation revenue............................ $ 49,761 $ 39,387 $ 36,184 $ 32,776 $ 34,325
Management fees and operation and maintenance revenue 4,986 4,326 5,677 2,501 2,598
Equity income in partnership interests and other
partnership income 635 245 335 -- --
--------- --------- --------- --------- ---------
Total revenue........................................ 55,382 43,958 42,196 35,277 36,923
--------- --------- --------- --------- ---------
Costs and expenses
Operating........................................... 17,815 15,895 16,466 11,762 11,200
General and administrative.......................... 6,487 6,799 7,285 5,204 4,020
Write-off of previously incurred merger costs, due to
Recapitalization.................................. -- -- -- -- 5,620
Non-cash charge for employee and director equity
participation programs............................ 259 339 670 1,075 24,903(1)
Depreciation and amortization....................... 9,846 9,625 8,679 7,601 7,344
Lease expense....................................... 6,072 5,753 5,386 5,230 5,540
Charge for impairment of long-lived assets 87,202 1,272 -- -- --
--------- --------- --------- -------- ---------
Total costs and expenses............................. 127,681 39,683 38,486 30,872 58,627
--------- --------- --------- --------- ---------
(Loss)/income from operations........................ (72,299) 4,275 3,710 4,405 (21,704)
Other income......................................... 368 185 107 186 387
Interest income...................................... 1,032 1,416 1,052 987 969
Interest expense..................................... (26,876) (21,778) (18,980) (13,868) (16,056)
Minority interests in loss/(income) of consolidated
subsidiaries........................................ 2,063 3 (15) 100 --
--------- --------- --------- -------- --------
Loss before income taxes, extraordinary
items and cumulative effect of accounting change (95,712) (15,899) (14,126) (8,190) (36,404)
Benefit/(provision) for income taxes 7,381 (377) (264) (319) (141)
--------- --------- --------- -------- --------
Loss before extraordinary items and cumulative
effect of accounting change....................... (88,331) (16,276) (14,390) (8,509) (36,545)
Extraordinary items(2)
Loss on early extinguishment of debt -- -- -- (2,269) (1,233)
--------- --------- --------- --------- --------
Loss before cumulative effect of accounting change (88,331) (16,276) (14,390) (10,778) (37,778)
Cumulative effect of accounting change(3) -- -- (19,204) -- --
--------- --------- --------- --------- --------
$et loss............................................. $ (88,331) $(16,276) (33,594) (10,778) (37,778)
= ========= ======== ======= ======= =======
$et loss applicable to common stock $(112,063) $(38,384) (54,281) (29,007) (45,901)
= ========= ======== ======= ======= =======
Net loss per common share -- before extraordinary
$items and cumulative effect of accounting change $ (87.45) (30.21) (27.70) (21.12) (26.35)
Net loss per common share -- primary and fully
$diluted(4).......................................... $ (87.45) $(30.21) (42.87) (22.91) (27.08)
Cash dividends per common share -- -- -- -- --
Operating Data:
Megawatts operated................................... 344.06 379.08 329.08 220.98 228.40
Capital expenditures
Cost of acquisitions and partnership interests $ -- $ 35,503 $ 15,230 $ 16 $ 2,486
Pumped storage and other development(5) 1,968 6,392 8,319 10,580 7,300
-26-
<PAGE>
All other capital expenditures associated with
operating projects, net........................... 3,777 2,288 (332) 4,244 3,635
Cash interest, net(6)................................ 8,303 4,753 4,009 11,514 13,713
Ratios and Other Data:
EBDIAT(7)............................................ 25,376 15,696 13,166 13,267 16,550
EBDIAT/Interest, net(8).............................. 468 4,666 4,762 1.03 1.10
EBDIAT/Cash interest, net............................ 3.06 3.30 3.28 1.15 1.21
Net debt(9)/EBDIAT................................... 9.57 15.11 14.48 12.05 7.46
Net debt(9) and mandatorily redeemable preferred
stock/EBDIAT........................................ 13.45 20.51 19.98 16.68 9.99
Deficiency of earnings to fixed charges(10) $ 97,417 $ 18,850 $ 16,429 $ 8,743 $ 36,806
Deficiency of earnings to fixed charges and preferred
stock dividends(11)................................. 121,149 40,958 37,117 26,972 44,929
Balance Sheet Data:
Cash and cash equivalents............................ 23,834 16,682 14,155 42,617 21,655
Current assets....................................... 33,041 25,454 24,649 49,467 29,293
Current liabilities.................................. 16,958 13,908 9,990 22,465 14,554
Total assets......................................... 244,657 330,617 286,827 286,521 240,542
Long-term debt....................................... 260,158 248,887 201,620 189,186 139,773
Mandatorily redeemable preferred stock 98,604 84,690 72,401 61,428 41,946
Stockholders' equity/(deficit)....................... (168,627) (66,641) (38,414) 5,472 38,317
- ---------------
(1) This non-cash charge accounts for the equity entitlements granted to
certain key employees and certain directors pursuant to both the
arrangements surrounding the conversion of the Class B Common Stock to
Class A Common Stock and the vested entitlements under the Performance Unit
Plan pursuant to the Stock Option Plan. See Notes 13 and 14 of the Notes to
Consolidated Financial Statements for the fiscal years ended June 30, 1996,
1995 and 1994 (the "Consolidated Financial Statements").
(2) The fiscal 1992 and 1993 amounts consist of premiums paid and the write-off
of certain debt issuance costs associated with the early extinguishment of
debt, which included the repurchase of $17,300,000 and $13,195,000
principal amount of 13% Debentures in 1992 and 1993, respectively, and the
repayment of approximately $2,900,000 and $20,435,000 principal amounts of
GECC project indebtedness in 1992 and 1993, respectively.
(3) Represents the adoption of Statement of Financial Accounting Standards No.
109, Accounting for Income Taxes. See Note 2 of the Notes to the
Consolidated Financial Statements.
(4) See Note 2 of the Notes to Consolidated Financial Statements for
information on losses per common share.
(5) These amounts are substantially funded with proceeds from (i) outside
lenders on a non-recourse basis or (ii) sales of CHI equity securities,
primarily through the Recapitalization.
(6) Cash interest, net is defined as cash interest less interest income.
(7) EBDIAT is defined as income/loss from operations plus depreciation,
amortization, other non-cash charges to income, other income and cash
received from equity investments. EBDIAT and EBDIAT ratios are not measures
of performance or financial condition under generally accepted accounting
principles, but are presented to provide additional information related to
fixed charge service capability. EBDIAT should not be considered in
isolation or as a substitute for other measures of financial performance or
liquidity under generally accepted accounting principles. (8) Computations
resulting in a ratio of less than one are disclosed as a deficiency and
represent the dollar amount of EBDIAT required to attain a ratio of one-to-
one.
(9) Net debt is defined as total debt less cash and cash equivalents (which
include restricted cash that, at the end of each period presented, has
ranged from $4.3 million to $13.2 million and was $13.2 million at June 30,
1996).
(10) For the purpose of calculating the deficiency of earnings to fixed charges,
earnings are determined by adding fixed charges (excluding capitalized
interest) to loss before provision for income taxes, extraordinary items
and cumulative effect of accounting change. Fixed charges consist of
interest expense, amortization of debt issuance costs and the imputed
interest on the Company's Boott facility lease, which is accounted for as
an operating lease. These deficiencies primarily reflect non-cash charges.
An analysis of such non-cash charges and the resulting ratio or reduced
deficiency adjusted for such charges follows:
-27-
<PAGE>
</TABLE>
<TABLE>
<CAPTION>
Year Ended June 30,
1996 1995 1994 1993 1992
---- ---- -- ---- ----
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C>
Non-cash interest $ 18,629 $ 16,610 $ 14,629 $ 1,401 $ 860
Depreciation and amortization 9,846 9,625 8,679 7,601 7,344
Other non-cash charges 87,461 1,611 670 1,075 30,523
-------- -------- -------- -------- --------
$115,936 $ 27,846 $ 23,978 $ 10,077 $ 38,727
======== ======== ======== ======== ========
Resulting ratio of earnings to
fixed charges 1.61 1.34 1.32 1.08 1.10
</TABLE>
(11) For the purpose of calculating the deficiency of earnings to fixed charges
and preferred stock dividends, earnings are determined by adding fixed
charges (excluding capitalized interest) and preferred stock dividends to
loss before provision for income taxes, extraordinary items and cumulative
effect of accounting change. Preferred stock dividends consist of dividends
declared on Series A, B, C and H Preferred Stock, the cumulative undeclared
dividends on Series F and G Preferred Stock and dividends and accretion on
the Preferred Stock. These deficiencies primarily reflect non-cash charges.
The analysis of such non-cash charges is the same as that set forth in the
preceding footnote and the resulting ratio or reduced deficiency adjusted
for such charges follows:
<TABLE>
<CAPTION>
Year Ended June 30,
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C>
Resulting ratio of earnings to fixed charges
and preferred stock dividends -- -- -- -- --
Deficiency of earnings to fixed charges and
preferred stock dividends $ 5,213 $13,112 $ 13,139 $ 16,895 $ 6,202
</TABLE>
-28-
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
General
The Company is principally engaged in the development, operation and
management of hydroelectric power plants. The Company's operating hydroelectric
projects are located in 15 states and one Canadian province. In November 1995,
the Company established a subsidiary, CHI Power, Inc., for the purpose of
developing, acquiring, operating and managing industrial energy facilities and
related industrial assets.
The Company's existing U.S. projects are clustered in four regions: the
Northeast, Southeast, Northwest and West, with a concentration in the Northeast.
CHI has developed what it believes to be an efficient "hub" system of project
management designed to maximize the efficiency of each facility's operations.
The economies of scale created by this system include reduced costs related to
centralized administration, operations, maintenance, engineering, insurance,
finance and environmental and regulatory compliance. The hub system and the
Company's operating expertise have enabled the Company to successfully integrate
acquisitions within its current portfolio and increase the efficiency and
productivity of its projects.
The Company has expanded primarily by acquiring existing hydroelectric
facilities in the United States. On June 30, 1996, the Company had a 100%
ownership or long-term lease interest in 67 projects (153 megawatts) including
20 projects under contract for sale, a partial ownership interest in 14 projects
(86 megawatts), and operations and maintenance ("O&M") contracts with 10
projects (105 megawatts), including the acquisition of hydroelectric projects or
interests in hydroelectric projects or O&M agreements with an aggregate
operating capacity of 50 megawatts since January 1995. The acquisition of Hydro
Development Group Inc. ("HDG"), which was acquired by the Company on February
16, 1995, had a material impact on operations. An O&M contract relating to one
project (33 megawatts) in the West region was terminated pursuant to its terms
effective January 1, 1996. Although this project represented a significant
portion of the Company's total megawatt capacity for the region, it did not
represent significant revenues for the Company as a whole and, therefore, this
termination did not have a material adverse effect on the Company's results of
operations or financial condition.
CHI sells substantially all of the electric energy and capacity from
its U.S. projects to public utility companies pursuant to take and pay power
purchase agreements. These contracts vary in their terms but typically provide
scheduled rates throughout the life of the contracts, which are generally for a
term of 15 to 40 years from inception.
The Company has begun to seek opportunities to provide energy-related
products and services to industrial and utility customers in an effort to
respond to changing market conditions. Such opportunities, if available, would
permit the Company to move away from relying exclusively on hydropower ownership
and operation in a business climate driven largely by legislation and regulation
and the structural industry trends described above in which the Company
currently believes that acquisition and development opportunities are
increasingly limited, particularly with regard to hydroelectric facilities.
Currently, all of the Company's revenue is derived from the ownership and
operation of hydroelectric facilities.
In fiscal 1996, the Company has significantly written down the carrying
values of its pumped storage development assets, certain investments in
partnerships which own hydroelectric facilities and certain of its conventional
hydroelectric assets to $0.1 million, $0.8 million and $26.0 million,
respectively. The Company has determined that it is highly unlikely that the
Company will successfully develop its pumped storage projects. See "Year Ended
June 30, 1996 Compared to Year Ended June 30, 1995 - SFAS 121 - Accounting for
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of".
Power Generation Revenue
The Company's revenues are derived principally from selling electrical
energy and capacity to utilities under long-term power purchase agreements which
require the contracting utilities to purchase energy generated by the
-29-
<PAGE>
Company. The Company's present power purchase agreements have remaining terms
ranging from 1 to 30 years. Fluctuations in revenues and related cash flows are
generally attributable to increasing megawatts in operation, coupled with
variations in water flows and the effect of escalating contract rates in the
Company's power purchase agreements.
Management Fees and Operations & Maintenance Revenues
O&M contracts, from which management fees and operations and
maintenance revenues are derived, generally enable the Company to maximize the
use of its available resources and to generate additional income. Additionally,
the Company, in some instances, prefers to obtain an O&M contract prior to
acquiring a hydroelectric facility. An O&M arrangement with a potential
acquisition candidate allows the Company to obtain first-hand operating
information and utilize it to better analyze a potential acquisition.
Equity Income In Partnership Interests and Other Partnership Income
In accordance with generally accepted accounting principles, certain of
the Company's partnership interests are accounted for under the equity and the
cost method of accounting.
Operating Expenses
Operating expenses consist primarily of project-related costs such as
labor, repairs and maintenance, supplies, insurance and real estate taxes.
Operating expenses include direct expenses related to the production of power
generation revenue as well as direct costs associated with O&M contracts which
are rebillable to applicable third party owners directly or not rebillable since
they are covered through an established management fee.
Lease Expense
Lease expense includes operating leases associated with some of the
hydroelectric projects as well as leases for the corporate and regional
administrative offices. Certain leases provide for payments that are based upon
power sales revenue or cash flow for specific projects. Hence, varying project
revenues will impact overall lease expense, year-to-year.
-30-
<PAGE>
Certain Key Operating Results and Trends
The information provided in the tables below is included to provide an
overview of certain key operating results and trends which, when read in
conjunction with the narrative discussion that follows, is intended to provide
an enhanced understanding of the Company's results of operations. These tables
include information regarding the Company's ownership by region of projects as
well as information on regional precipitation. As presented, the Company's
project portfolio is concentrated in the Northeastern United States, a region
characterized by relatively consistent long- term water flow and power purchase
contract rates which are higher than in most other regions of the country.
This information should be read in conjunction with the Consolidated
Financial Statements, and the related Notes thereto, included herein.
Power Producing Facilities
<TABLE>
<CAPTION>
As of June 30
1996 1995 1994
-------------------------- ----------------------------------- -------------------
MWs #Projects MWs #Projects MWs #Projects
<S> <C> <C> <C> <C> <C> <C>
Northeast(4):
100% Ownership (1) 102.20(8) 44(8) 104.72(5) 45(5) 88.62 34
Partial Ownership(2) 52.37 8 52.37(6) 8 35.47 3
O&M Contracts (3) 80.14 3 80.14 3 80.14 3
---------- -- ---------- -- ---------- --
Total 234.71 55 237.23 56 204.23 40
========== == ========== == ========== ==
Southeast:
100% Ownership (1) 27.42 13 27.42 13 27.42 13
Partial Ownership(2) -- -- -- -- -- --
O&M Contracts (3) -- -- -- -- -- --
---------- -- ---------- -- ---------- --
Total 27.42 13 27.42 13 204.23 40
========== == ========== == ========== ==
==
West:
100% Ownership (1) 1.35 1 1.35 1 1.35 1
Partial Ownership(2) 8.33 4 8.33 4 8.33 4
O&M Contracts (3) 19.48(7) 5(7) 51.98 6 34.98 5
---------- -- ---------- -- ---------- --
Total 29.16 10 61.66 11 44.66 10
========== == ========== == ========== ==
</TABLE>
Continued
-31-
<PAGE>
<TABLE>
<CAPTION>
As of June 30
1996 1995 1994
-------------------------- ----------------------------------- -------------------
MWs #Projects MWs #Projects MWs #Projects
<S> <C> <C> <C> <C> <C> <C>
Northwest:
100% Ownership (1) 21.72 9 21.72 9 21.72 9
Partial Ownership (2) 24.96 2 24.96 2 24.96 2
O&M Contracts (3) 6.09 2 6.09 2 6.09 2
--
Total 52.77 13 52.77 13 52.77 13
========== == ======== == ======= ==
Total:
100% Ownership (1) 152.69(8) 67(8) 155.21(5) 68(5) 139.11 57
Partial Ownership (2) 85.66 14 85.66(6) 14(6) 68.76 9
O&M Contracts (3) 105.71(7) 10(7) 138.21 11 121.21 10
---------- -- ------ -- ------ --
Total 344.06 91 379.08 93 329.08 76
========== == ======= == ======= ==
</TABLE>
(1) Defined as projects in which the Company has 100% of the economic interest.
(2) Defined as projects in which the Company's economic interest is less than
100%.
(3) Defined as projects in which the Company is an operator pursuant to O&M
contracts with the project's owner or owners. The Company does not have any
ownership interest in such projects.
(4) Significant changes in the Northeast result from the acquisition of HDG (33
megawatts) on February 16, 1995. (5) Includes 11 projects (16.1 megawatts)
from the acquisition of HDG.
(6) Includes 5 projects (16.9 megawatts) from the acquisition of HDG.
(7) Reflects the termination of an O&M contract pursuant to its terms effective
January 1, 1996
(8) Includes 20 projects (16.8 megawatts) with respect to which the Company has
reached an agreement to sell, subject to certain conditions, but which the
Company would continue to operate if sold.
Selected Operating Information
Twelve months ended June 30,
1996 1995 1994
Power generation revenues (thousands) (1) $ 49,761(2) $ 39,387(2) $ 36,184
Kilowatt hours produced (thousands) (1) 647,664(3) 532,063(3) 466,766
Average rate per kilowatt hour (1) 7.7(cent)(4) 7.4(cent)(4) 7.8(cent)
- ---------
(1) Limited to projects included in consolidated revenues.
(2) Includes $5,131 and $1,953 resulting from the acquisition of HDG for the
years ended June 30, 1996 and 1995, respectively. (3) Includes 80,883 kWh
and 30,556 kWh resulting from the acquisition of HDG for the years ended
June 30, 1996 and 1995, respectively. (4) Excluding the acquisition of HDG,
the average rate per kilowatt hour is 7.9(cent) and 7.5(cent) for the years
ended June 30, 1996 and 1995, respectively.
-32-
<PAGE>
Precipitation, Water Flow and Seasonality
The amount of hydroelectric energy generated at any particular facility
depends upon the quantity of water flow at the site of the facility. Dry periods
tend to reduce water flow at particular sites below historical averages,
especially if the facility has low storage capacity. Excessive water flow may
result from prolonged periods of higher than normal precipitation, or sudden
melting of snow packs, possibly causing flooding of facilities and/or a
reduction of generation until water flows return to normal.
Water flow is generally consistent with precipitation. However, snow
and other forms of frozen precipitation will not necessarily increase water flow
in the same period of such precipitation if temperatures remain at or below
freezing. "Average", as it relates to water flow, refers to the actual long-term
average of historical water flows at the Company's facilities for any given
year. Typically, these averages are based upon hydrologic studies done by
qualified engineers for periods of 20 to 50 years or more, depending on the flow
data available with respect to a particular site. Over an extended period (e.g.,
10 to 15 years) water flows would be expected to be average, whereas for shorter
periods (e.g., three months to three years) variation from average is likely.
Each of the regions in which the Company operates has distinctive precipitation
and water flow characteristics, including the degree of deviation from average.
Geographic diversity helps to minimize short-term variations.
During 1995 and 1994, the Company has experienced low water flow
relative to long-term indications at many of its facilities. The effect on
revenues of the lower than average flows was most adverse in the Northeast, a
region in which a majority of the Company's projects are located and where the
Company's rates received for power sales are highest, on average.
Water Flow by Region (1)
Twelve months ended June 30,
1996 1995 1994
Northeast Above Average Below Average Below Average
Southeast Average Above Average Below Average
West Above Average Above Average Below Average
Northwest Above Average Below Average Average
- ---------
(1) These determinations were made by management based upon water flow in areas
where the Company's projects are located and may not be applicable to the
entire region.
Production of energy by the Company is typically greatest in its third
and fourth fiscal quarters (January through June), when water flow is at its
highest at most of the Company's projects, and lowest in the first fiscal
quarter (July through September). The amount of water flow in any given period
will have a direct effect on the Company's production, revenues and cash flow.
The following tables, which show revenues from power sales and kilowatt
hour production by fiscal quarter, respectively, highlight the seasonality of
the Company's revenue stream. These tables should be reviewed in conjunction
with the water flow information included above.
-33-
<PAGE>
Power Generation Revenues (1)
<TABLE>
<CAPTION>
Fiscal 1996(2) Fiscal 1995 (2) Fiscal 1994(2)
$ % $ % $ %
<S> <C> <C> <C> <C> <C> <C>
First Fiscal Quarter $ 5,489(4) 11.0 $ 7,471 19.0 $ 4,833 13.4
Second Fiscal Quarter 12,229(4) 24.6 7,503 19.0 8,668 23.9
Third Fiscal Quarter 15,744(4) 31.6 13,437(3) 34.1 10,455 28.9
Fourth Fiscal Quarter 16,299(4) 32.8 10,976(3) 27.9 12,228 33.8
------- ---- ------- ---- ------ ----
Total $ 49,761 100.0 $39,387 100.0 $36,184 100.0
======== ===== ======= ===== ======= =====
- -----------
(1) Limited to projects included in consolidated revenues.
(2) Includes business interruption revenue representing claims for lost
generation, recoverable from an insurance company.
(3) Includes $789 and $1,164 resulting from the acquisition of HDG in the third
and fourth fiscal quarters, respectively.
(4) Includes $442, $1,409, $1,452 and $1,828 resulting from the acquisition of
HDG, in the first, second, third and fourth fiscal quarters, respectively.
Kilowatt Hours Produced (1)
Fiscal 1996(2) Fiscal 1995(2) Fiscal 1994(2)
kWh % kWh % kWh %
First Fiscal Quarter 83,069(4) 12.8 105,456 19.8 67,351 14.5
Second Fiscal Quarter 157,615(4) 24.3 103,428 19.4 107,049 22.9
Third Fiscal Quarter 195,540(4) 30.3 171,280(3) 32.2 131,342 28.1
Fourth Fiscal Quarter 211,440(4) 32.6 151,899(3) 28.6 161,024 34.5
-------- ---- ------- ---- ------- ----
Total 647,664 100.0 532,063 100.0 466,766 100.0
======== ===== ======= ===== ======= =====
- -------------
(1) Limited to projects included in consolidated revenues.
(2) Includes the production equivalent of the business interruption revenue
recoverable as a result of insurance claims.
(3) Includes 12,302 and 18,254 kWh resulting from the acquisition of HDG, in
the third and fourth fiscal quarters, respectively.
(4) Includes 7,396, 22,415, 22,915 and 28,157 kWh resulting from
the acquisition of HDG in the first, second, third and fourth fiscal
quarters, respectively.
Year Ended June 30, 1996 Compared to Year Ended June 30, 1995
Operating Revenues
Power Generation Revenue. Power generation revenue increased by $10.4
million (26.4%), from $39.4 million to $49.8 million for fiscal 1995 and 1996,
respectively. Excluding the results of HDG, acquired on February 16, 1995, power
generation revenue increased $7.2 million (19.3%) from $37.4 million to $44.6
million.
-34-
<PAGE>
The Northeast region experienced increased revenues of $6.6 million,
due to above average water flows and precipitation in the current fiscal year as
compared to below average water flows and precipitation in the prior fiscal
year.
The Southeast region experienced decreased revenues of $0.1 million,
due primarily to flood damage and continued repairs at certain of its
facilities.
The West and Northwest regions combined experienced increase revenues
of $0.7 million, primarily as a result of above average water flow and
precipitation in the Northwest region, an area which contributes significantly
to total revenues of the combined regions, in the current fiscal year as
compared to the prior fiscal year.
The Company as a whole experienced increased revenue per kilowatt hour
of 4.1%, from 7.4(cent) to 7.7(cent) in the 1996 fiscal period versus the 1995
fiscal period, respectively. Excluding the results of HDG, revenue per kilowatt
hour increased by 5.3%, from 7.5(cent) to 7.9(cent), primarily as a result of
variations in the production mix and contract rates among the various projects.
Management Fees and Operation & Maintenance Revenues. Management fees
and O&M contract revenue increased by $0.7 million (16.3%), from $4.3 million to
$5.0 million for fiscal 1995 and 1996, respectively. Excluding the results of
HDG, management fees and O&M contract revenue increased by $0.3 million (7.1%)
from $4.2 million to $4.5 million. The increase was primarily due to revenue
generated from an increase in project management base fees coupled with an
increase in rebillable capital expenditures at a Northeast O&M facility.
Costs and Expenses
Operating Expenses. Operating expenses increased by $1.9 million
(11.9%), from $15.9 million to $17.8 million for fiscal 1995 and 1996,
respectively. Excluding the results of HDG, operating expenses increased $0.8
million (5.4%) from $14.9 million to $15.7 million. The increase was primarily
due to time spent by certain management personnel (who previously charged their
time to general and administrative and other activities) on operating
activities; partially offset by (i) an overall decrease in insurance premiums
due to a change in carriers effective July 1, 1995; and (ii) a reduction in
expenditures related to regulatory requirements in the Northeast region.
General and Administrative Expenses. General and Administrative
expenses decreased by $0.3 million (4.4%), from $6.8 million to $6.5 million for
fiscal 1995 and 1996, respectively. Excluding the results of HDG, general and
administrative expenses decreased $0.5 million (7.4%) from $6.8 million to $6.3
million. The decrease was primarily due to (i) a decrease in third party
acquisition costs related to a cessation or decline in acquisitions prospects
which were actively pursued during the prior year, partially offset by
acquisition related activity of the Company's newly formed subsidiary (CHI
Power, Inc.), coupled with the expensing of pumped storage development costs
which were previously capitalized; (ii) a decrease in travel, meetings, and
seminars as part of an overall cost reduction effort made by the Company; and
(iii) a reduction in time spent by certain management personnel on general and
administrative activities offset by an increase in administrative salaries and
benefits due to costs associated with CHI Power, Inc., coupled with a severance
accrual for the Company's former President.
Depreciation and Amortization. Depreciation and amortization increased
by $0.2 million (2.1%), from $9.6 million to $9.8 million for fiscal 1995 and
1996, respectively. Excluding the results of HDG, depreciation and amortization
decreased $0.6 million (6.7%), from $9.0 million to $8.4 million. The decrease
was primarily due to a write-down of impaired assets in fiscal 1996 as a result
of the implementation of SFAS 121 (see "-- SFAS 121 - - Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and
Note 4 of the Notes to Consolidated Financial Statements).
Interest Expense
-35-
<PAGE>
Interest expense increased by $5.1 million (23.4%), from $21.8 million
to $26.9 million for fiscal 1995 and 1996, respectively. Excluding the results
of HDG, interest expense increased $2.9 million (14.2%) from $20.4 million to
$23.3 million. The increase was primarily due to the increasing principal
balance of the Company's 12% Senior Discount Notes due 2003, Series B (the
"Senior Discount Notes") which results in a corresponding increase in interest
expense (see Note 11 of the Notes to Consolidated Financial Statements) and the
effect of expensing interest (for the second half of fiscal 1996), that had
previously been capitalized during the prior fiscal year.
Issuance of Series F and G Preferred Stock
In February 1996, Ms. Carol H. Cunningham, the Company's Executive
Vice-President and Chief Development Officer, exercised her option under an
existing agreement with the Company to have the Company issue 1,279 shares of
its 8% Senior Convertible Voting Preferred Stock (the "Series F Preferred
Stock") and 1,279 shares of its 9.85% Junior Convertible Voting Preferred Stock
(the "Series G Preferred Stock") in exchange for shares of Summit Energy Storage
Inc. ("SES") stock (or vested options therefor) owned by Ms. Cunningham. The
Company plans to issue such shares of Series F Preferred Stock and Series G
Preferred Stock during the first quarter of fiscal year 1997 and will record the
Series F Preferred Stock and the Series G Preferred Stock, when issued, at the
nominal fair value of the SES stock received.
SFAS 121 - Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of
The Company implemented Statement of Financial Accounting Standards No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of ("SFAS 121") in the second quarter of fiscal 1996. This
statement establishes accounting standards for determining impairment of
long-lived assets and long-lived assets to be disposed of. The Company
periodically assesses the realizability of its long-lived assets and evaluates
such assets for impairment whenever events or changes in circumstances indicate
that the carrying amount of such assets (or group of assets) may not be
recoverable. For assets in use or under development, impairment is determined to
exist if the estimated future cash flow associated with the asset, undiscounted
and without interest charges, is less than the carrying amount of the asset.
When the estimated future cash flow indicates that the carrying amount of the
asset will not be recovered, the asset is written down to its fair value.
The Company has reached an agreement to sell 20 of its smaller projects
in Maine and New Hampshire, aggregating approximately 16.75 megawatts of
capacity, to a purchaser for a price of approximately $16.0 million including
working capital. The Company anticipates that it will receive half of the sale
proceeds in cash at closing and the balance within 90 days of closing. The sale
is subject to customary conditions precedent for transactions of this nature. It
is expected that Maine projects, representing 75% of the transaction value, will
close by October 31, 1996. The closing of the New Hampshire projects will occur
subsequent to the Maine closing due to the timing of required regulatory
approvals. Under the terms of the agreement, the Company will continue to
operate and maintain the projects for a period of 15 years pursuant to an O&M
contract. The total operating revenue and income from operations from the 20
projects during the years ended June 30, 1996, 1995 and 1994 was $6.8 million,
$5.6 million and $6.1 million, and $4.5 million, $3.9 million and $3.9 million,
respectively. Although the transactions if completed will provide greater
liquidity to the Company, there can be no assurance that they will be
consummated, on the terms currently anticipated. These assets to be disposed of
are stated at the lower of their carrying amount or fair value less estimated
costs to sell.
In light of the Company's planned sale of certain of its conventional
hydroelectric projects (as mentioned above), recent industry trends (including
the continued decline in electricity prices and other factors stemming from the
deregulation of the electric power industry), the timing of the expiration of
the fixed rate period of some of its long-term power sales contracts and other
indications of a decline in the fair value of certain of its conventional
hydroelectric projects, the Company determined that certain of these projects
(including properties which are not included among those to be sold) were
impaired pursuant to the criteria established under SFAS 121. The Company also
determined that due to the factors noted above, as well as its current financial
position, it is highly unlikely that the Company will successfully develop its
pumped storage projects.
-36-
<PAGE>
As a result of the factors noted above, in fiscal 1996 the Company
recorded an impairment charge of $87.2 million as a component of its loss from
operations. In addition, a deferred tax benefit and a benefit for minority
interests in loss of consolidated subsidiaries of $7.9 million and $2.1 million,
respectively, were recorded as of that date. Of the total charges, $38.5 million
was attributable to pumped storage development assets, resulting in an aggregate
remaining carrying value of such assets of $0.1 million, $44.9 million was
attributable to certain conventional hydroelectric assets, resulting in an
aggregate remaining carrying value for such written down assets of $26.0
million, and $3.8 million was attributable to an other than temporary decline in
the value of certain investments in partnerships which own hydroelectric
facilities, resulting in an aggregate remaining carrying value of such assets of
$0.8 million. In accordance with SFAS 121, the carrying value of these written
down assets now reflects management's best estimate as to their fair value,
although there can be no assurance that future events or changes in
circumstances will not require that such assets, or other of the Company's
assets, be written down in the future.
In conjunction with the adoption of SFAS 121, during the third quarter
the Company re-evaluated the useful lives of certain property, plant and
equipment and intangible assets. This resulted in a reduction of the estimated
useful lives of these fixed and intangible assets. This change had the effect of
increasing the loss from operations and the loss net of tax benefit by
approximately $0.5 million (39(cent) per share) for the year ended June 30,
1996.
Minority Interests in Loss of Consolidated Subsidiaries
The Company recognized a benefit of approximately $2.1 million for the
year ended June 30, 1996 resulting from the minority shareholders' interest in
the loss of certain consolidated subsidiaries related to the write-down of
pumped storage development assets in accordance with SFAS 121 (discussed above).
Benefit for Income Taxes
The Company recognized a deferred tax benefit of approximately $7.9
million for the year ended June 30, 1996. The benefit relates to the write-down
of certain long-lived assets in accordance with SFAS 121 (discussed above). The
effective tax rate of the deferred benefit recognized from the write-down
differs from the federal statutory rate due to the reduction of deferred tax
liabilities offset by the increase in the valuation allowance attributable to
tax assets related to net operating loss carryforwards. The valuation allowance
increased due to the reduction of taxable temporary differences for book
depreciation and amortization previously projected to be recognized during the
net operating loss carryforward period.
SFAS 123 - Accounting for Stock-Based Compensation
In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based
Compensation ("SFAS 123"), which requires expanded disclosures of stock-based
compensation arrangements with employees and non-employees and encourages (but
does not require) application of the "fair value" recognition provisions in the
new statement. The Company is required to adopt SFAS 123 beginning in fiscal
1997 and is currently assessing the impact, if any, SFAS 123 will have on its
financial position and results of operations.
Year Ended June 30, 1995 Compared to Year Ended June 30, 1994
Operating Revenues
Power Generation Revenue. Power generation revenue increased $3.2
million (8.8%), from $36.2 million to $39.4 million for fiscal 1994 and 1995,
respectively . Excluding the 1995 results of HDG, acquired on February 16, 1995,
power generation revenue increased $1.2 million (3.3%) from $36.2 million to
$37.4 million.
-37-
<PAGE>
The Northeast region experienced decreased revenues of $0.8 million
primarily attributable to unusually low water flow in the fourth quarter of
1995. The Southeast region had a $1.5 million increase in revenues, primarily
attributable to the effects of above average water flow in 1995 versus below
average in 1994. The West and Northwest regions combined, experienced increased
revenues of $0.5 million, primarily resulting from the full year effect of the
acquisition of two projects aggregating 2.4 megawatts in June 1994, coupled with
above average water flows for the West region in 1995 versus below average in
1994.
The Company as a whole experienced decreased revenue per kilowatt hour
of 5.1%, from 7.8(cent) to 7.4(cent) in the 1995 fiscal period versus the 1994
fiscal period, respectively. Excluding the results of HDG, revenue per kilowatt
hour decreased 3.8%, from 7.8(cent) to 7.5(cent), primarily as a result of
variations in the production mix and contract rates among the various projects.
Management Fees and Operations & Maintenance Revenues. Management fees
and O&M contract revenue decreased by $1.4 million (24.6%), from $5.7 million to
$4.3 million for fiscal 1994 and 1995, respectively. Excluding the 1995 results
of HDG, management fees and O&M revenues decreased $1.5 million (26.3%) from
$5.7 million to $4.2 million, primarily due to higher than normal revenues
earned in 1994, relating to significant special work performed at a Northeast
O&M facility, offset slightly by the full-year addition of a Northeast O&M which
realized base fees plus an additional incentive fee.
Costs and Expenses
Operating Expenses. Operating expenses decreased by $0.6 million
(3.6%), from $16.5 million to $15.9 million for fiscal 1994 and 1995,
respectively. Excluding the 1995 results of HDG, operating expenses decreased
$1.6 million (9.7%) from $16.5 million to $14.9 million, primarily due to a
reduction in the rebillable expenses incurred relating to the significant
special work performed in 1994 at a Northeast O&M facility, as discussed above,
offset by: (i) a significant increase in insurance premiums; (ii) an increase in
necessary repairs needed to maintain operations at several Southeast projects;
and (iii) the recognition of self-insurance deductibles associated with
insurance claims.
General and Administrative Expenses. General and Administrative
expenses decreased by $0.5 million (6.8%), from $7.3 million to $6.8 million for
fiscal 1994 and 1995, respectively. There was no material impact on general and
administrative expenses resulting from the acquisition of HDG. The decrease was
primarily related to the write-off of acquisition costs in 1994 as a result of a
change in Company policy regarding the treatment of such costs (see Note 2 of
the Notes to Consolidated Financial Statements for additional information).
Depreciation and Amortization. Depreciation and amortization increased
by $0.9 million (10.3%), from $8.7 million to $9.6 million for fiscal 1994 and
1995, respectively. Excluding the 1995 results of HDG, depreciation and
amortization increased $0.2 million (2.3%) from $8.7 million to $8.9 million,
primarily due to the full-year effect of the acquisition of three projects in
the fourth quarter of fiscal 1994, coupled with the completion of capital
projects related to the Company's existing facilities.
Charge for Impairment of Long-Lived Assets. The Company wrote off
approximately $1.3 million of its investment in two pumped storage projects
during fiscal 1995 as compared to no write-offs in fiscal 1994.
Interest Expense
Interest expense increased by $2.8 million (14.7%), from $19.0 million
to $21.8 million for fiscal 1994 and 1995 respectively. Excluding the 1995
results of HDG, interest expense increased $1.3 million (6.8%) from $19.0
million to $20.3 million primarily due to the increasing principal balance of
the Senior Discount Notes which results in a corresponding increase in interest
expense (see Note 11 of the Notes to Consolidated Financial Statements).
-38-
<PAGE>
Cumulative Effect of Accounting Change
Effective July 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109 "Accounting for Income Taxes" ("SFAS 109") on a
prospective basis. The adoption of SFAS 109 resulted in the recognition of a
deferred credit of $27.6 million, an increase to fixed and intangible assets of
$7.0 million and $1.4 million, respectively, and a charge in 1994 reflecting the
cumulative effect of a change in accounting principle of $19.2 million or $15.17
per share (see Note 2 of the Notes to Consolidated Financial Statements).
Liquidity and Capital Resources
As more fully described in the Consolidated Financial Statements and
related Notes thereto, the cash flow of the Company was comprised of the
following:
</TABLE>
<TABLE>
<CAPTION>
Fiscal Year Ended
June 30, 1996 June 30, 1995 June 30, 1994
<S> <C> <C> <C>
Cash provided by/(used
in):
Operating activities $ 16,642 $ 14,634 $ 3,397
Investing activities (5,624) (43,935) (22,933)
Financing activities (3,866) 31,828 (8,926)
------------ ------------ ------------
Net increase/(decrease) in cash $ 7,152 $ 2,527 $ (28,462)
============ =========== ===========
</TABLE>
The Company has historically financed its capital needs and
acquisitions through long-term debt and limited partner capital contributions
and, to a lesser extent, through cash provided from operating activities. The
Company's principal capital requirements are those associated with acquiring and
developing new projects, as well as upgrading existing projects. The Company is
currently limiting its pumped storage activities to the minimum necessary to
maintain the viability of the Summit project and the monitoring of market
conditions relevant to the project with the intention of pursuing commitments
for the balance of the project's capacity. Consequently, the Company does not
expect its capital requirements in connection with the development of pumped
storage projects to be material in the near term. Capital expenditures for the
year ended June 30, 1997 relating to upgrading existing projects or regulatory
compliance related work are expected to be approximately $3.7 million.
For the year ended June 30, 1996, the cash flow provided by operating
activities was principally the result of the $88.3 million net loss for such
period, adjusted for an $87.2 million non-cash charge for impairment of
long-lived assets, and benefits of $7.9 million and $2.1 million for deferred
tax and minority shareholders' interest in loss of consolidated subsidiaries,
respectively, resulting from such impairment charge and a $1.4 million increase
in accounts receivable offset by $9.8 million of depreciation and amortization,
a $17.6 million charge for non-cash interest and a $1.4 million increase in
accounts payable and accrued expenses. The cash flow used in investing
activities was primarily attributable to $2.2 million of capital expenditures, a
$2.0 million investment in conventional and pumped storage development and a
$1.5 million increase in investments and other long-term assets during fiscal
1996. Of these expenditures, approximately $1.2 million was attributable to
capitalized interest costs, and $1.0 million was attributable to the funding of
committed development capital for the Summit and other pumped storage projects.
The cash flow used in financing activities was due primarily to repayment of
$4.3 million of project debt. (See also "--Summary of Indebtedness".)
Cash provided by operating activities increased by $2.0 million for the
year ended June 30, 1996 as compared to the year ended June 30, 1995. The
increase resulted from a $6.0 million increase in income before depreciation and
amortization, a charge for non-cash interest, a charge for impairment of
long-lived assets, the tax
-39-
<PAGE>
benefit resulting from a charge for impairment of long-lived assets, minority
shareholders' interest in loss of consolidated subsidiaries, write-off of
certain facilities under development and employee and director equity programs,
offset by a $4.0 million decrease in other operating items (receivables, prepaid
expenses, accounts payable and accrued expenses).
The Company has undertaken a number of measures to reduce costs,
including salary reductions (ranging from 5% to 15% for the Company's
senior-most managers effective July 1, 1995), the relocation of its executive
office to lower cost office space in December 1995, changes in its travel and
expense policies and the reduction of insurance premiums through a change to a
lower cost carrier. The Company continues to manage its administrative and
operating costs with the goal of continued cost containment.
For the year ended June 30, 1995, the cash flow provided by operating
activities was principally the result of the $16.3 million net loss for such
year offset by $9.6 million of depreciation and amortization, $15.7 million from
a charge for non-cash interest, $1.3 million of a write-off of certain
facilities under development, $2.4 million of a decrease in accounts receivable
and $1.7 million of an increase in amounts payable and accrued expenses. The
cash flow used in investing activities was primarily attributable to $35.5
million utilized for the acquisitions of the HDG projects and the $6.4 million
investment in pumped storage and conventional development during fiscal 1995. Of
these expenditures, approximately $2.0 million was attributable to capitalized
interest costs, $0.6 million was financed through non-recourse debt and
approximately $2.9 million was attributable to the funding of committed
development capital for the Summit project. The cash flow provided by financing
activities was largely due to the $35.9 million of additional debt incurred in
connection with the HDG acquisition offset by repayment of $4.4 million of
project debt.
Cash provided by operating activities increased by $11.2 million for
the year ended June 30, 1995 as compared to the year ended June 30, 1994. The
increase resulted from a $1.7 million increase in income before depreciation and
amortization, non-cash interest, employee and director equity programs, the
cumulative effect of an accounting change and the write-off of certain
facilities under development, in addition to a $9.5 million increase in other
operating items (receivables, prepaid expenses, accounts payable and accrued
expenses).
For the year ended June 30, 1994, the cash flow provided by operating
activities was principally the result of the $33.6 million net loss for such
year offset by $8.7 million of depreciation and amortization, $19.2 million
resulting from the cumulative effect of accounting change and $14.0 million from
a charge for non-cash interest. The cash flow used in investing activities was
primarily attributable to $15.2 million utilized for the acquisitions of certain
hydroelectric projects and the minority partnership interests in another
hydroelectric project. The cash flow used in financing activities was largely
due to the retirement of the then outstanding $9.5 million of the Company's 13%
Debentures in July 1993 with proceeds from the Refinancing offset by $1.0
million of additional debt incurred in connection with a hydroelectric
acquisition and the financing activities associated with the Summit and other
pumped storage projects.
Summary of Indebtedness
<TABLE>
<CAPTION>
Principal Amount Outstanding as of
(Dollar in Thousands)
June 30, 1996 June 30, 1995 June 30, 1994
<S> <C> <C> <C>
Company debt, excluding non-recourse subsidiaries
debt of subsidiaries $ 151,131 $ 134,506 $ 119,892
Non-recourse debt of subsidiaries 115,489 119,372 84,941
Current portion of long-term debt (6,462) (4,991) (3,213)
----------- ----------- ------------
Total long-term debt obligations $ 260,158 $ 248,887 $ 201,620
=========== =========== ============
</TABLE>
-40-
<PAGE>
In October 1993, one of the Company's former senior lenders, Den norske
Bank AS ("DnB"), provided the Company with a $20 million unsecured working
capital facility (the "DnB Facility"), which has an initial expiration date of
June 30, 1997. The DnB Facility is pari passu with the Senior Discount Notes.
Under certain limited circumstances, pursuant to the terms of the agreement, DnB
has the right, upon notice to the Company, to limit any further borrowings under
the DnB Facility and require the Company to repay any and all outstanding
indebtedness thereunder within one year from the date DnB provides such notice
to the Company.
As of June 30, 1996, the Company was in compliance with its covenants
under the DnB Facility. However, as of March 31, 1996 based on the Company's
financial performance for the twelve month period then ended, the Company
continued to be unable to meet one of the financial covenants as required under
the DnB Facility. In response to an earlier request from the Company, the bank
had waived compliance with respect to the covenant for the twelve month period
ended September 30, 1995 and, pending a further review of the Company's
performance and opportunities, had limited availability under the DnB Facility
to $6.1 million, the amount outstanding to provide letters of credit at
September 27, 1995. Due to the extremely low water flow in the Northeast region
during the fourth quarter of fiscal 1995 and the first quarter of fiscal 1996,
and because the measurement contained in the financial covenant is applied at
the end of each fiscal quarter on the basis of the four most recently completed
quarters, the Company was unable to meet the covenant for the twelve months
ended December 31, 1995.
DnB has not waived the previous defaults by the Company, but has
offered to do so in conjunction with the execution by the Company of an
amendment which will, among other things, change the final expiration date of
the DnB Facility to June 30, 1998 from June 30, 1997, reduce (in steps) the
total commitment under the DnB Facility from approximately $6.0 million at
September 30, 1996 to zero at June 30, 1998, limit the use of the facility to
letters of credit and modify certain financial covenants. The Company is
currently negotiating the amendment and waiver with DnB. There can be no
assurance that the Company and DnB will reach agreement on the terms of such an
amendment. If the additional waiver is not granted, the Company may need to
replace some or all of the outstanding letters of credit with cash deposits or
other letters of credit which could be more expensive, if available. If the
Company fails to reach agreement with DnB and the outstanding letters of credit
are not replaced, it is likely that the letters of credit under the DnB Facility
will be drawn upon. If the indebtedness created by such drawn letters of credit
is not paid when due, a default under the DnB Facility would occur and all
amounts outstanding thereunder would become due and payable after the passage of
applicable notice and grace periods. The Company does not currently expect that
it will require a revolving credit facility such as the DnB Facility for
additional working capital purposes during fiscal 1997.
The DnB Facility contains certain affirmative and restrictive covenants
which are generally consistent with the terms of the Notes and the Preferred
Stock. As of June 30, 1996, no borrowings were outstanding under the DnB
Facility, approximately $5.9 million of the DnB Facility was employed to provide
letters of credit as of June 30, 1996 and 1995, respectively.
Interest on the DnB Facility borrowings is at the London Interbank
Offered Rate, as defined in the DnB Facility, plus an escalating margin of 2.5%
or the Prime Rate, as defined in the DnB Facility, plus an escalating margin of
1.5%. A fee on the unused balance is charged at a rate of 1/2 of 1% per annum.
The electric power industry in the United States is undergoing
significant structural changes, evolving from a highly regulated industry
dominated by monopoly utilities to a deregulated, competitive industry providing
energy customers with an increasing degree of choice among sources of electric
power supply. The Company will seek to become a provider of reliable, low-cost
energy and related products and services to industrial and utility customers, by
taking advantage of its existing technical and financial expertise and using its
geographic presence to realize economies of scale in administration, operation,
maintenance and insurance of facilities.
-41-
<PAGE>
Nevertheless, the performance of the Company in the future will be
affected by a number of factors, in addition to the structural changes to the
electric power industry described above. First, the Company competes for
hydroelectric and industrial energy projects with a broad range of electric
power producers including other independent power producers of various sizes and
many well-capitalized domestic and foreign industry participants such as
utilities, equipment manufacturers and affiliates of industrial companies, many
of whom are aggressively pursuing power development programs and have relatively
low return-on-capital objectives. Opportunities to acquire or develop power
generation assets on favorable economic terms in such an environment are
increasingly limited, particularly with regard to hydroelectric facilities.
Second, the Company is highly leveraged and its debt service obligations, the
cash portion of which commence in January 1999, along with its preferred stock
obligations, the cash portion of which commence in September 1998, make it
difficult to source capital on favorable terms that would allow the Company to
successfully pursue significant acquisition and development opportunities and,
in some cases, difficult to establish the creditworthiness necessary to develop
the project or to obtain contracts to develop products and services for its
industrial and utility customers.
Federal regulators and a number of states, including some in which the
Company operates, are exploring ways in which to increase competition in
electricity markets, most notably by opening access to the transmission grid.
Although the character and extent of this deregulation are as yet unclear, the
Company expects that these efforts will increase uncertainty with respect to
future power prices and make it more difficult to obtain long-term power
purchase contracts.
The Company expects that, through calendar 1998, it will generate
sufficient cash flows from existing operations to meet its capital expenditure
and working capital requirements. Commencing on September 30, 1998, however,
cash dividends become payable on the Company's 13 1/2% Cumulative Redeemable
Exchangeable Preferred Stock (the "Series H Preferred Stock") and on January 15,
1999, cash interest becomes payable on the Company's 12% Senior Discount Notes
due 2003, Series B (the "Senior Discount Notes"). In order to meet such
obligations, the Company currently anticipates that it will have to rely on
proceeds from asset sales, additional debt or equity offerings or other sources.
However, the Company also currently anticipates that it may not be able to
obtain the necessary additional debt or equity financing or sufficient proceeds
from asset sales or other sources in order to satisfy such dividend and interest
payment obligations on a timely basis as well as meet the Company's other
obligations, including accrued and unpaid dividends since issuance under the
Series F Preferred Stock, and its capital expenditure and working capital
requirements at such time. As a result, it may be necessary to restructure the
Company's debt and equity structure either before or at such time. In addition,
the Company anticipates that it would need to obtain financing for the principal
payments on its Senior Discount Notes at their maturity in 2003 and to redeem
the Series H Preferred Stock at its 2003 redemption date. There can be no
assurance that any such additional financing will be available to the Company.
Also, the Company may consider from time to time, either prior to 1998 or
thereafter, the use of available cash, if any, to engage in repurchases of the
Senior Discount Notes, subject to applicable contractual restrictions and other
appropriate uses, in negotiated transactions or at market prices. There can be
no assurance that, if the Company decides to engage in repurchases of the Senior
Discount Notes, any Senior Discount Notes will be available for repurchase by
the Company on terms that would be favorable or acceptable to the Company.
Certain statements contained herein that are not related to historical
facts may contain "forward looking" information, as that term is defined in the
Private Securities Litigation Reform Act of 1995. Such statements are based on
the Company's current beliefs as to the outcome and timing of future events, and
actual results may differ materially from those projected or implied in the
forward looking statements. Further, certain forward looking statements are
based upon assumptions of future events which may not prove to be accurate. The
forward looking statements involve risks and uncertainties including, but not
limited to, the uncertainties relating to the Company's existing debt, industry
trends and financing needs and opportunities; risks related to hydroelectric,
industrial energy, pumped storage and other acquisition and development
projects; risks related to the Company's power purchase contracts; risks and
uncertainties related to weather conditions; and other risk factors detailed
herein and in other of the Company's Securities and Exchange Commission filings.
See Part I, Item 1 -- "Certain Risk Factors".
-42-
<PAGE>
Item 8. FINANCIAL STATEMENTS
Report of Independent Accountants
To the Board of Directors
and Stockholders of
Consolidated Hydro, Inc.
In our opinion, the accompanying consolidated balance sheet and
the related consolidated statements of operations, of stock-
holders' equity and of cash flows present fairly, in all mate-
rial respects, the financial position of Consolidated Hydro,
Inc. and its subsidiaries at June 30, 1996 and 1995, and the
results of their operations and their cash flows for each of
the three years in the period ended June 30, 1996, in confor-
mity with generally accepted accounting principles. 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 conducted
our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and per-
form 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,
assessing the accounting principles used and significant esti-
mates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
As discussed in Note 2 to the consolidated financial state-
ments, effective July 1, 1993, the Company changed its method
of accounting for income taxes. Also, as discussed in Note 4
to the consolidated financial statements, the Company changed
its method of accounting for the impairment of long-lived
assets and long-lived assets to be disposed of in the second
quarter of fiscal 1996.
PRICE WATERHOUSE LLP
New York, NY
September 26, 1996
-43-
<PAGE>
CONSOLIDATED HYDRO, INC.
CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1996, 1995 and
1994 (Amounts in thousands except share and per share amounts)
<TABLE>
<CAPTION>
1 9 9 6 1 9 9 5 1 9 9 4
------- ------- -------
<S> <C> <C> <C>
Operating revenues:
Power generation revenue $ 49,761 $ 39,387 $ 36,184
Management fees and operations & maintenance revenues 4,986 4,326 5,677
Equity income in partnership interests and other 635 245 335
partnership income -------- ------- --------
55,382 43,958 42,196
-------- ------- --------
Costs and expenses:
Operating 17,815 15,895 16,466
General and administrative 6,487 6,799 7,285
Charge for employee and director equity participation programs 259 339 670
Depreciation and amortization 9,846 9,625 8,679
Lease expense to a related party 3,532 3,495 3,430
Lease expense to unrelated parties 2,540 2,258 1,956
Charge for impairment of long-lived assets 87,202 1,272 ---
-------- ------- --------
127,681 39,683 38,486
-------- ------- --------
(Loss)/income from operations (72,299) 4,275 3,710
Interest income 1,032 1,416 1,052
Other income 368 185 107
Interest expense on indebtedness to related parties (9,927) (7,001) (1,416)
Interest expense on indebtedness to unrelated parties (16,949) (14,777) (17,564)
Minority interests in loss/(income) of consolidated subsidiaries 2,063 3 (15)
-------- -------- ---------
Loss before benefit/(provision) for income taxes (95,712) (15,899) (14,126)
Benefit/(provision) for income taxes 7,381 (377) (264)
-------- -------- --------
Loss before cumulative effect of accounting change (88,331) (16,276) (14,390)
Cumulative effect of accounting change --- --- (19,204)
-------- -------- --------
$ (88,331) $ (16,276) $ (33,594)
========= ========= =========
Net loss applicable to common stock:
Net loss $ (88,331) $ (16,276) $ (33,594)
Dividends declared on preferred stock (13,057) (11,433) (10,012)
Accretion of preferred stock (857) (857) (857)
Undeclared dividends on cumulative preferred stock (9,818) (9,818) (9,818)
--------- --------- ---------
$(112,063) $ (38,384) $ (54,281)
========= ========= =========
Net loss per common share:
Loss before cumulative effect of accounting change $ (87.45) $ (30.21) $ (27.70)
Cumulative effect of accounting change --- --- (15.17)
-------- -------- --------
$ (87.45) $ (30.21) $ (42.87)
======== ======== ========
Weighted average number of common shares 1,281,516 1,270,614 1,266,298
========= ========= =========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE>
CONSOLIDATED HYDRO, INC.
CONSOLIDATED BALANCE SHEET
As of June 30, 1996 and 1995
(Amounts in thousands except share and per
share amounts)
1 9 9 6 1 9 9 5
-------- --------
Assets
Current assets:
Cash and cash equivalents unrestricted $ 10,598 $ 6,577
Cash and cash equivalents restricted 13,236 10,105
Accounts receivable, net 7,854 6,455
Current portion of notes receivable --- 1,004
Prepaid expenses 1,353 1,313
-------- -------
Total current assets 33,041 25,454
Property, plant and equipment, net 126,133 175,191
Facilities under development 1,217 40,974
Intangible assets, net 50,746 69,174
Assets to be disposed of 15,066 ---
Investments and other assets 18,454 19,824
-------- -------
$ 244,657 $330,617
========= ========
Current liabilities:
Accounts payable and accrued expenses $ 10,496 $ 8,917
Current portion of long-term debt payable to 2,305 1,074
a related party
Current portion of long-term debt and 4,157 3,917
obligations under capital leases payable to -------- -------
unrelated parties
Total current liabilities 16,958 13,908
Long-term debt payable to related parties 87,406 82,903
Long-term debt and obligations under capital 172,752 165,984
leases payable to unrelated parties
Deferred credit, state income taxes and other 37,564 47,710
long-term liabilities
Minority interests in consolidated subsidiaries --- 2,063
Commitments --- ---
Mandatorily redeemable preferred stock, $.01
par value, at redemption
value of $1,000 per share, junior in
liquidation preference to Series F Preferred
Stock:
Series H, 136,950 shares authorized,
issued and outstanding ($105,012 and $91,955
liquidation preference in 1996 and 1995,
respectively) 98,604 84,690
------- -------
Total liabilities and mandatorily 413,284 397,258
redeemable preferred stock ------- -------
Stockholders' deficit:
Preferred stock, $.01 par value, at
redemption value of $1,000 per share:
Series F, 55,000 shares authorized issued 49,356 49,356
and outstanding ($55,000 liquidation
preference)
Series G, 55,000 shares authorized issued 49,356 49,356
and outstanding ($55,000 liquidation
preference)
Class A common stock, $.001 par value, 9,000,000
shares authorized, 4,576,925 unissued shares
reserved, 1,814,771 shares issued and 1,285,762
and 1,278,698 shares outstanding at 1996 and
1995, respectively 2 2
Class B common stock, $.001 par value, 1,000,000
shares authorized, 246,510 unissued shares
reserved, no shares issued and outstanding --- ---
Additional paid-in capital, including $5,966 13,497 13,497
related to warrants
Accumulated deficit (259,427) (157,182)
-------- --------
(147,216) (44,971)
Less: Deferred compensation (350) (609)
Treasury stock (common: 548,473 (21,061) (21,061)
shares), at cost -------- -------
Total stockholders' deficit (168,627) (66,641)
-------- -------
$ 244,657 $330,617
========= ========
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE>
CONSOLIDATED HYDRO, INC.
CONSOLIDATED STATEMENT OF
STOCKHOLDERS' EQUITY/(DEFICIT)
FOR THE YEARS ENDED ENDED JUNE 30,
1994, 1995 and 1996
(Amounts in thousands except shares
and per share amounts)
<TABLE>
<CAPTION>
Preferred Stock Common Stock
--------------- ------------
Number Number Additional
of Shares Reported of Shares Par Paid-in
Outstanding Amount Outstanding Value Capital
----------- ------ ----------- ----- -------
<S> <C> <C> <C> <C> <C>
Balance June 30, 1993 110,000 $ 98,712 1,266,298 $ 2 $ 12,970
Annual dividend of $73.11 per share,
mandatorily redeemable
Series H Preferred
Accretion of Series H Preferred
Deferred compensation and
compensation expense related to
conversion of Performance Unit (93)
Plan to Stock Option Plan in 1993
Net loss
---------- ---------- --------- ----- --------
Balance June 30, 1994 110,000 98,712 1,266,298 2 12,877
Annual dividend of $83.48 per share,
mandatorily redeemable
Series H Preferred
Accretion of Series H Preferred
Issuance of common stock and related 12,400 620
deferred compensation
Recognition of board of directors
and employee compensation
expense related to the issuance of
common stock
Compensation expense related to
conversion of Performance Unit Plan
to Stock Option Plan in 1993
Net loss
---------- --------- -------- ----- --------
Balance June 30, 1995 110,000 98,712 1,278,698 2 13,497
Annual dividend of $95.34 per share,
mandatorily redeemable
Series H Preferred
Accretion of Series H Preferred
Issuance of Class A common stock, 7,064 0
$.001 par value
Recognition of board of directors
and employee compensation
expense related to the issuance of
common stock
Compensation expense related to
conversion
of Performance Unit Plan to Stock
Option Plan in 1993
Net loss
---------- ---------- --------- ------ ----------
Balance June 30, 1996 110,000 $ 98,712 1,285,762 $ 2 $ 13,497
========== ========== ========= ====== ==========
(continued)
<PAGE>
CONSOLIDATED HYDRO, INC.
CONSOLIDATED STATEMENT OF
STOCKHOLDERS' EQUITY/(DEFICIT)
FOR THE YEARS ENDED ENDED JUNE 30,
1994, 1995 and 1996
(Amounts in thousands except shares
and per share amounts)
(continued)
</TABLE>
<TABLE>
<CAPTION>
Total
Stockholders'
Accumulated Deferred Treasury Equity
Deficit Compensation Stock (Deficit)
------- ------------ ----- ---------
<S> <C> <C> <C> <C>
Balance June 30, 1993 $ (84,153) $ (998) $ (21,061) $ 5,472
Annual dividend of $73.11 per share,
mandatorily redeemable
Series H Preferred (10,012) (10,012)
Accretion of Series H Preferred (857) (857)
Deferred compensation and
compensation expense related to
conversion of Performance Unit 670 577
Plan to Stock Option Plan in 1993
Net loss (33,594) (33,594)
---------- ---------- ---------- ----------
Balance June 30, 1994 (128,616) (328) (21,061) (38,414)
Annual dividend of $83.48 per share,
mandatorily redeemable
Series H Preferred (11,433) (11,433)
Accretion of Series H Preferred (857) (857)
Issuance of common stock and related (620) --
deferred compensation
Recognition of board of directors
and employee compensation
expense related to the issuance of 110 110
common stock
Compensation expense related to
conversion of Performance Unit Plan
to Stock Option Plan in 1993 229 229
Net loss (16,276) (16,276)
---------- ---------- ---------- ----------
Balance June 30, 1995 (157,182) (609) (21,061) (66,641)
Annual dividend of $95.34 per share,
mandatorily redeemable
Series H Preferred (13,057) (13,057)
Accretion of Series H Preferred (857) (857)
Issuance of Class A common stock, 0
$.001 par value
Recognition of board of directors
and employee compensation
expense related to the issuance of 160 160
common stock
Compensation expense related to
conversion
of Performance Unit Plan to Stock 99 99
Option Plan in 1993
Net loss (88,331) (88,331)
---------- ---------- ---------- ----------
Balance June 30, 1996 $(259,427) $ (350) $ (21,061) $(168,627)
========== ========== ========= =========
</TABLE>
The accompanying notes are an integral
part of the consolidated financial
statements.
<PAGE>
CONSOLIDATED HYDRO, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED JUNE 30, 1996, 1995 and
1994 (Amounts in thousands except share and per share amounts)
<TABLE>
<CAPTION>
1 9 9 6 1 9 9 5 1 9 9 4
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss $(88,331) $(16,276) $(33,594)
Adjustments to reconcile net loss to
net cash provided by operating
activities:
Charge for non-cash interest 17,644 15,660 13,951
Charge for employee and director 259 339 670
equity participation programs
Non-cash charge for impairment of 87,202 1,272 --
long-lived assets
Benefit relating to deferred tax (7,905) -- --
liabilities
Cumulative effect of accounting -- -- 19,204
change
Depreciation and amortization 9,846 9,625 8,679
Minority interests in (loss)/income (2,063) (3) 15
of consolidated subsidiaries
(Increase)/decrease in accounts (1,399) 2,366 (3,497)
receivable
(Increase)/decrease in prepaid (40) (5) 85
expenses
Increase/(decrease) in accounts 1,429 1,656 (2,116)
payable and accrued expenses
-------- -------- --------
Net cash provided by operating 16,642 14,634 3,397
activities
-------- -------- --------
Cash flows from investing activities:
Cost of acquisitions -- (35,503) (9,959)
Cost of partnership interests -- -- (5,271)
Cost of development expenditures (1,968) (6,392) (8,319)
Decrease in long-term notes 179 567 511
receivable
Increase in long-term notes (58) (319) (227)
receivable
Capital expenditures (2,230) (2,905) (2,260)
(Increase)/decrease in investments (1,547) 617 2,592
and other long-term assets
-------- -------- --------
Net cash used in investing (5,624) (43,935) (22,933)
activities
-------- -------- --------
Cash flows from financing activities:
Long-term borrowings from related -- 35,900 --
parties
Long-term borrowings from unrelated 120 1,168 5,292
parties
Payments to a related party on (269) (488) --
long-term borrowings
Payments to unrelated parties on (4,018) (4,402) (13,044)
long-term borrowings
Decrease in other long-term 301 (350) (1,174)
liabilities
-------- -------- --------
Net cash (used in)/provided by (3,866) 31,828 (8,926)
financing activities
-------- -------- --------
Net increase/(decrease) in cash and cash 7,152 2,527 (28,462)
equivalents
Cash and cash equivalents, at beginning of 16,682 14,155 42,617
the year
-------- -------- --------
Cash and cash equivalents, at end of the $ 23,834 $ 16,682 $ 14,155
year
======== ======== ========
</TABLE>
(continued)
<PAGE>
CONSOLIDATED HYDRO, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED JUNE 30, 1996, 1995 and
1994 (Amounts in thousands except share and per share amounts) (continued)
<TABLE>
<CAPTION>
1 9 9 6 1 9 9 5 1 9 9 4
<S> <C> <C> <C>
Supplemental disclosures of cash flow
information:
Cash paid during the year for:
$ 2,720 $ 1,406 $ ---
======== ======== =======
$ 6,865 $ 6,309 $ 6,702
======== ======== =======
$ 622 $ 349 $ 15
======== ======== =======
Schedules of noncash investing and
financing activities:
$ --- $ 49,165 $12,287
--- 35,503 9,959
-------- -------- -------
$ --- $ 13,662 $ 2,328
======== ======== =======
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 1 - ORGANIZATION
Consolidated Hydro, Inc., (together with its consolidated subsidiaries
the "Company"), organized in July 1985, is principally engaged in the
development, acquisition, operation, and management of hydroelectric power
plants . As of June 30, 1996, 1995 and 1994, it had ownership interests in,
leased and/or operated projects with a total operating capacity of 344, 379 and
329 megawatts ("MW"), respectively. In November 1995, the Company established a
subsidiary for the purpose of developing, acquiring, operating and managing
industrial energy facilities and related industrial assets. Currently, all of
the Company's revenue is derived from the ownership and operation of
hydroelectric facilities.
In 1992, the Company entered into an agreement (the "Purchase
Agreement") with The Morgan Stanley Leveraged Equity Fund II, L.P. and Madison
Group, L.P. (collectively, the "Investor Group") that provided for, among other
things, the sale to the Investor Group of $110.0 million of newly issued
convertible preferred stock and certain warrants (the "Recapitalization") (Note
13). Among other terms and conditions of the Purchase Agreement and in
conjunction with the Recapitalization, approximately $34.3 million of the
Company's outstanding indebtedness and related accrued interest, including
approximately $2.9 million of project debt, was retired and approximately 36% of
the Company's outstanding common stock and all issued warrants were redeemed.
In 1993, the Company completed the sale of senior discount notes and
preferred stock with attached warrants for an aggregate sale price of $182.4
million and retired approximately $138.7 million of existing debt and preferred
stock with an additional $9.5 million of debt called pursuant to a minimum 30
day redemption notification in June 1993 and repaid in July 1993 (the
"Refinancing") (Note 10).
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Consolidated
Hydro, Inc., its subsidiaries, the majority of which are wholy owned, and
partnership interests. All significant intercompany accounts and transactions
have been eliminated in consolidation. Certain amounts have been reclassified
in 1995 and 1994 to be in conformity with 1996 presentation.
USE OF MANAGEMENT'S ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles 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. Actual results could differ from those estimates.
REVENUE
Power generation revenue is recognized based on power delivered at rates
stipulated in the respective power contracts. Emerging Issues Task Force (EITF)
Issue 91-6, "Revenue Recognition of Long-Term Power Sales Contracts" addressed
and reached consensus on certain revenue recognition questions raised by the
terms and pricing arrangements of long-term power sales contracts between
non-utility power generators and rate-regulated utilities. The company is in
compliance with the accounting treatments discussed and the consensus reached.
Management fees and operations and maintenance revenues are earned in
conjunction with operation and maintenance services provided to third parties
under contractual agreements. costs associated with rendering these services are
included in operating expenses.
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
EQUITY INCOME FROM PARTNERSHIPS AND OTHER PARTNERSHIP INCOME
In accordance with generally accepted accounting principles, certain of the
company's partnership interests are accounted for under the equity method and
the cost method of accounting.
STOCK-BASED COMPENSATION
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, Accounting for Stock-Based
Compensation ("SFAS 123"), which requires expanded disclosures of stock-based
compensation arrangements with employees and non-employees and encourages (but
does not require) application of the "fair value" recognition provisions in the
new statement. The Company is required to adopt SFAS 123 beginning in fiscal
1997 and is currently assessing the impact, if any, SFAS 123 will have on its
financial position and results of operations.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid debt instruments purchased with
original maturities of three months or less to be cash equivalents. A portion of
cash is restricted by specific project-related agreements, which generally
mandate that cash must first be utilized solely for funding operations and/or
the payment of debt associated with the project. As a result, restricted cash is
generally not available to the Company for general corporate purposes.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at cost (Note 7). Renewals
and betterments that increase the useful lives of the assets are capitalized.
Repair and maintenance expenditures that increase the efficiency of the assets
are expensed as incurred.
Plant and equipment are depreciated on the straight-line method over
the estimated useful lives of the respective assets (50 years for dam and
appurtenant structures and 30 years for mechanical and electrical equipment).
Depreciation expense was $6,042, $5,872 and $5,303 in 1996, 1995 and 1994,
respectively.
-45-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
ASSETS TO BE DISPOSED OF
The Company has reached an agreement to sell 20 small projects in Maine
and New Hampshire and classifies these assets as Assets to be disposed of. These
assets are stated at the lower of their carrying amount or fair value less
estimated costs to sell.
FACILITIES UNDER DEVELOPMENT
Costs associated with facilities under development, including
acquisition costs of property, plant and equipment and intangible assets, are
transferred to construction in progress as appropriate, upon the commencement of
construction. Facilities under development are those that have not yet commenced
the construction phase primarily because all the requisite permits and contracts
have not yet been obtained and generally represent a higher level of risk than
those projects under construction.
INTEREST CAPITALIZATION
The Company capitalizes interest costs associated with the development
and construction of its facilities. Interest capitalized in 1996, 1995 and 1994
is disclosed in Note 11.
INTANGIBLE ASSETS
Intangible assets principally include costs incurred in connection with
power purchase agreements, FERC licenses and goodwill, all of which are
capitalized and amortized on a straight-line basis over the periods to be
benefited by such costs, ranging from 1 to 40 years (Note 8). Amortization
expense was $3,804, $3,753 and $3,376 in 1996, 1995 and 1994, respectively.
Legal, compliance and other related expenditures incurred in connection with the
maintenance of power purchase agreements and FERC licenses are capitalized and
amortized over the remaining term of the applicable contract or license.
Management periodically reviews intangibles, including goodwill, for potential
impairments.
ACQUISITION COSTS
Acquisition costs generally represent cash down payments or option
payments, due diligence and other related expenses. The Company expenses all
acquisition related costs as incurred. Once a viable purchase and sale agreement
is signed in respect of a prospective acquisition, from thereon all third party
acquisition related costs are capitalized.
TREASURY STOCK
The Company accounts for treasury stock under the cost method.
-46-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
INCOME TAXES
The Company provides for deferred income taxes based on differences in
reporting certain income and expense items for federal income tax and financial
reporting purposes. The Company accounts for energy and investment tax credits
using the flow-through method as a reduction of the provision for federal income
taxes in the year in which such credits are utilized. Effective July 1, 1993,
the Company changed its method of accounting for income taxes from the deferred
method, under Accounting Principles Board Opinion No. 11 ("APB 11"), to the
liability method, required by Statement of Financial Accounting Standards No.
109, Accounting for Income Taxes ("SFAS 109").
The cumulative effect on fiscal years prior to 1994, as a result of
adopting SFAS 109, was a non-cash charge of $19.2 million, which is reflected in
the net loss for the year ended June 30, 1994, as the Cumulative Effect of
Accounting Change. This expense primarily represents the impact of recognizing a
deferred tax liability (for the expected reversal of the excess of financial
statement bases of property, plant and equipment and intangible assets over the
tax bases of these assets), offset by the recognition of a deferred tax asset
(for the anticipated benefit of certain net operating loss and tax credit
carryforwards). In addition, property, plant and equipment and intangible assets
were increased by approximately $7.0 million and $1.4 million, respectively, as
a result of this accounting change.
NET LOSS PER COMMON SHARE
Net loss per common share is computed by dividing the net loss for the
year, adjusted for accretion of preferred stock and preferred dividends, by the
weighted average number of common shares. Common stock equivalents are not
included in the computation of net loss per common share as they would be
antidilutive to the computation.
NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS
In accordance with Statement of Financial Accounting Standards No. 107,
Disclosures about Fair Value of Financial Instruments ("SFAS 107"), the Company
has used the following methods and assumptions to estimate the fair value of
each class of financial instruments for which it is practicable to estimate
values:
Cash and cash equivalents
Cash and cash equivalents consist principally of investments in short
term interest bearing instruments and because of the short maturity of these
items, the carrying amount approximates fair value.
Long-term debt and redeemable preferred stock
Certain of the Company's subsidiaries have project-finance obligations
that are non-recourse to CHI. Variable rate project-finance obligations
(excluding pumped storage related obligations and project term loans to be
acquired), with carrying amounts aggregating $34.9 million, approximate their
fair value because the interest
-47-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
rates on these instruments change with market rates. Fixed rate project-finance
obligations (excluding pumped storage related obligations), with carrying
amounts aggregating $24.0 million have a fair value of $24.7 million, based on
discounted future cash flows using rates currently available to the Company for
non-recourse project- finance loans with similar terms and average maturities.
The variable and fixed-rate non-recourse loans related to the Company's pumped
storage development assets, with carrying amounts aggregating $14.4 million,
have a fair value of $0.1 million based on the prospects for the development of
and fair value of such assets. Certain variable rate non-recourse loans which
the Company has an agreement to acquire, with carrying amounts aggregating $14.5
million, have a fair value of $4.6 million based on the agreed upon purchase
price of these loans (see Note 20).
As of June 30, 1996, there are no quoted market prices for the
Company's Senior Discount Notes or Series H Preferred Stock (see Note 10). Based
upon information available to management, in management's view the fair value of
the Senior Discount Notes and Series H Preferred Stock is materially below their
respective accreted values as of June 30, 1996. Due to the absence of market
quotations and comparable obligations in the market and the inability to
determine the rate, if any, at which the Company could obtain financing today on
similar terms, the determination of fair value estimates of these securities
would be subjective in nature and involve uncertainties and matters of
significant judgment. Therefore, the fair market value of these instruments
cannot in this case be reasonably estimated. Changes in the Company's business
prospects could significantly affect the fair value of the Company's Senior
Discount Notes and Series H Preferred Stock.
NOTE 4 - ADOPTION OF SFAS 121
The Company implemented SFAS 121 in the second quarter of fiscal 1996.
This statement establishes accounting standards for determining impairment of
long-lived assets and long-lived assets to be disposed of. The Company
periodically assesses the realizability of its long-lived assets and evaluates
such assets for impairment whenever events or changes in circumstances indicate
that the carrying amount of such assets (or group of assets) may not be
recoverable. For assets in use or under development, impairment is determined to
exist if the estimated future cash flow associated with the asset, undiscounted
and without interest charges, is less than the carrying amount of the asset.
When the estimated future cash flow indicates that the carrying amount of the
asset will not be recovered, the asset is written down to its fair value.
The Company has reached an agreement to sell 20 of its smaller projects
in Maine and New Hampshire, aggregating approximately 16.75 megawatts of
capacity, to a purchaser for a price of approximately $16.0 million including
working capital. The Company anticipates that it will receive half of the sale
proceeds in cash at closing and the balance within 90 days of closing. The sale
is subject to customary conditions precedent for transactions of this nature. It
is expected that the Maine projects, representing 75% of the transaction value,
will close by October 31, 1996. The closing of the New Hampshire projects will
occur subsequent to the Maine closing due to the timing of required regulatory
approvals. Under the terms of the agreement, the Company will continue to
operate and maintain the projects for a period of 15 years pursuant to an O&M
contract. The total operating revenue and income from operations from the 20
projects during the years ended June 30, 1996, 1995 and 1994 was $6.8 million,
$5.6 million and $6.1 million, and $4.5 million, $3.9 million and $3.9 million,
respectively. Although the transactions if completed will provide greater
liquidity to the Company, there can be no assurance that they will be
consummated, on the terms currently anticipated. These assets to be disposed of
are stated at the lower of their carrying amount or fair value less estimated
costs to sell.
-48-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
In light of the Company's planned sale of certain of its conventional
hydroelectric projects (as mentioned above), recent industry trends (including
the continued decline in electricity prices and other factors stemming from the
deregulation of the electric power industry), the timing of the expiration of
the fixed rate period of some of its long-term power sales contracts and other
indications of a decline in the fair value of certain of its conventional
hydroelectric projects, the Company determined pursuant to SFAS 121 that certain
of these projects (including properties which are not included among those to be
sold) were impaired pursuant to the criteria established under SFAS 121. The
Company also determined that due to the factors noted above, as well as its
current financial position, it is highly unlikely that the Company will
successfully develop its pumped storage projects.
As a result of the factors noted above, in fiscal 1996 the Company
recorded an impairment charge of $87.2 million as a component of its loss from
operations. In addition, a deferred tax benefit and a benefit for minority
interests in loss of consolidated subsidiaries of $7.9 million and $2.1 million,
respectively, was recorded as of that date. Of the total charges, $38.5 million
was attributable to pumped storage development assets, resulting in an aggregate
remaining carrying value of such assets of $0.1 million, $44.9 million was
attributable to certain conventional hydroelectric assets, resulting in an
aggregate remaining carrying value for such written down assets of $26.0
million, and $3.8 million was attributable to an other than temporary decline in
the value of certain investments in partnerships which own hydroelectric
facilities, resulting in an aggregate remaining carrying value of such assets of
$0.8 million. The carrying value of these written down assets now reflects
management's best estimate as to their fair value although there can be no
assurance that future events or changes in circumstances will not require that
such assets, or other of the Company's assets, be written down in the future.
In conjunction with the adoption of SFAS 121, during the third quarter
the Company re-evaluated the useful lives of certain property, plant and
equipment and intangible assets. This resulted in a reduction of the estimated
useful lives of these fixed and intangible assets. This change had the effect of
increasing the loss from operations and the net loss, net of tax benefit, by
approximately $0.5 million (.39(cent) per share) for the year ended June 30,
1996.
NOTE 5 - ACQUISITIONS
As disclosed in the Consolidated Statement of Cash Flows, during fiscal
1995 and 1994, the Company acquired the common stock, assets or a partnership
interest related to certain hydroelectric projects. In 1995, the acquisitions
were financed substantially through non-recourse project debt. In 1994, the
acquisitions were principally financed with funds provided by the Refinancing
(Note 10). The Company accounts for acquisitions in accordance with the purchase
accounting method. The results of operations for these acquired hydroelectric
projects are included in the accompanying Consolidated Statement of Operations
commencing with the acquisition date.
On February 16, 1995, the Company, through a wholly owned subsidiary,
CHI Acquisitions II, Inc., a Delaware corporation formerly known as HDG
Acquisitions, Inc. ("CHI Acquisitions II"), purchased 100% of the issued and
outstanding capital stock of Hydro Development Group, Inc., a New York
corporation ("HDG"). The stock of HDG was purchased pursuant to a Stock Purchase
Agreement, dated as of December 19, 1994 (the "HDG Purchase Agreement") among
CHI Acquisitions II, HDG and the holders of 100% of the issued and outstanding
capital stock of HDG (the "Sellers") for a total cost of $49.2 million,
comprised of a net cash payment of approximately $35.5 million including CHI's
closing costs, plus certain assumed debt and other liabilities of approximately
$2.7 million and $11.0 million, respectively. HDG's assets include certain
general partnership interests in operating hydroelectric projects.
-49-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 5 -- ACQUISITIONS (continued)
HDG owns either directly, through subsidiaries or through general
partnerships, interests in a total of 16 operating hydroelectric projects with
an aggregate capacity of approximately 33 MW's (the "HDG Projects"). The HDG
Projects are located in the states of New York, Massachusetts and Pennsylvania
and, except for 5 projects aggregating approximately 16.9 MW's owned through
partnerships, are 100% owned by HDG or its 100% owned subsidiaries. Of the 16.9
MW's owned through partnerships, approximately 11.5 MW's are owned through
partnerships in which HDG owns a 50% interest, and the balance is owned through
a partnership in which HDG effectively owns a 12.5% interest. HDG's and the
partnerships' assets include equipment, furniture, machinery, tools, vehicles,
buildings and other improvements, and all rights to federal, state and local
permits and licenses necessary to operate and maintain the HDG Projects. All 16
HDG Projects have power purchase agreements in place that extend for terms
ranging from approximately 5 to 30 years. CHI intends to continue to operate the
HDG Projects according to the terms of their licenses, contracts and permits.
CHI Acquisitions II financed this acquisition through existing cash and
two term loans aggregating $35.9 million provided by Global Projects and
Structured Finance Corporation ("GPSF"), a unit of General Electric Capital
Corporation ("GECC"). These two loans are comprised of the "A Loan" in aggregate
principal amount of $29.0 million which is a variable rate loan for a term of 8
years, and the "B Loan" in the aggregate principal amount of $6.9 million which
is a fixed rate loan for a term of 18 years (Note 11).
The following unaudited pro forma financial information for the twelve
months ended June 30, 1995 has been prepared assuming the acquisition of HDG
occurred at the beginning of the period presented:
Twelve Months Ended June30,
1996 1995
(As reported) (Unaudited Pro forma)
Operating Revenue $ 55,382 $ 47,403
======= ========
Net loss $(88,331) $(17,420)
======= ========
Net loss per common share $ (87.45) $ (31.11)
======= ========
Weighted average number of common shares 1,281,516 1,270,614
========= =========
The pro forma financial information does not purport to be indicative
of the financial performance which would have resulted had the acquisition
occurred at the beginning of the periods presented.
-50-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
Pro forma results of operations for the Company's acquisition during
fiscal 1994, as if retroactively combined with the Company's Consolidated
Statement of Operations, are not presented as the effect is not material.
In 1988, the Company entered into a $240 million acquisition facility
agreement (the "Acquisition Facility") with GECC to provide funds for future
acquisitions. Under the Acquisition Facility, GECC is committed to make
available, subject to specific project financing approvals, the remaining
balance of approximately $85.0 million to fund future acquisitions of the
Company. GECC has the first right to finance the Company's acquisitions pursuant
to the terms of the Acquisition Facility, subject to meeting specified
conditions including timing requirements as to their commitment and specific
terms related to pricing. Such rights for GECC terminate on March 25, 1997.
NOTE 6 - POWER GENERATION CONTRACTS
The Company operates facilities which qualify as small power production
facilities under the Public Utility Regulatory Policies Act ("PURPA"). PURPA
requires that each electric utility company, operating at the location of a
small power production facility, as defined, purchase the electricity generated
by such facility at a specified or negotiated price.
The Company sells substantially all of its electrical output to public
utility companies pursuant to long-term power purchase agreements of which the
remaining terms generally range between 1 and 30 years. Consolidated power
generation revenues, by major customer, for the years ended June 30, 1996, 1995
and 1994 were as follows:
1996 1995 1994
Commonwealth Electric Co. $ 9,528 $ 8,509 $ 8,329
Niagara Mohawk Power Corporation 9,139 4,865 3,781
Central Maine Power Co. 8,341 6,312 7,696
New England Power Co. 5,133 4,942 4,920
Duke Power Co. 3,581 3,701 2,369
All other customers 14,039 11,058 9,089
------ ------ -----
$ 49,761 $ 39,387 $ 36,184
============ ======== ===========
During 1996, 1995 and 1994, the amount shown for Commonwealth Electric
Co. includes approximately $78, $290 and $2,440, respectively, of business
interruption revenue representing lost generation recoverable from an insurance
company as a result of an insurance claim (Note 17). During 1996 the amount
shown for Duke Power also includes approximately $767 of business interruption
revenue from an insurance company as a result of an insurance claim.
-51-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
On October 6, 1995, Niagara Mohawk Power Corporation ("NIMO"), a
customer of the Company which accounted for approximately 18.4% of consolidated
power sales revenues in fiscal 1996, submitted a proposal to the New York State
Public Service Commission in which, among other items, NIMO proposed that it be
relieved of its obligations under contracts with IPPs that NIMO considers
uneconomic. While offering to renegotiate such contracts, NIMO proposed that,
should negotiations fail and NIMO be unable to gain alternative economic relief,
NIMO would seek to take possession of associated projects through the power of
eminent domain. In its press release announcing this proposal, NIMO indicated
that it would consider the possibility of restructuring under Chapter 11 of the
U.S. bankruptcy code should its proposal prove unachievable. During the summer
of 1996, NIMO offered to buy out forty-four of its power sales contracts with
IPPs in exchange for an undisclosed combination of cash and NIMO stock. NIMO has
not offered to buy out any of the Company's power sales contracts in conjunction
with the group buy out offer and, as of September 20, 1996, has not indicated
whether any of the IPPs are willing to accept the terms of the proposed buy out.
Increased competition in the electricity industry might cause certain
utilities to become higher credit risks. Although the ratings of the debt
securities of most of the utilities which purchase power from the Company are
currently investment grade, there can be no assurance of the long-term
creditworthiness of any of the Company's customers. Should any customer fail, it
might be difficult for the Company to replace an existing long-term contract
with such a customer with a new contract with another customer on similar
economic terms in the current environment.
NOTE 7 - PROPERTY, PLANT & EQUIPMENT
Property, plant and equipment includes assets acquired or refinanced
under capitalized lease obligations of $27,525 and $29,299 at June 30, 1996 and
1995, respectively (Note 11).
Property, plant and equipment comprise the following at June 30, 1996
and 1995:
1996 1995
------------ ----------
Land $ 3,610 $ 5,222
Dam and appurtenant structures 68,953 93,574
Mechanical and electrical equipment 69,785 100,413
Buildings and other 4,381 4,524
Construction in progress 534 1,706
--- -----
147,263 205,439
Less - accumulated depreciation (21,130) (30,248)
------- -------
$ 126,133 $ 175,191
================ =============
-52-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 8 - INTANGIBLE ASSETS
Intangible assets comprise the following at June 30, 1996 and 1995
1996 1995 Range of
Asset Lives
Power purchase contracts $ 24,243 $ 31,364 3 - 32 years
FERC licenses 16,066 19,625 12 - 40 years
Goodwill 17,740 27,533 40 years
Other intangibles 7,933 8,473 3 - 40 years
----- -----
65,982 86,995
Less - accumulated amortization (15,236) (17,821)
------- --------
$ 50,746 $ 69,174
======== ========
The majority of the Company's projects have been issued FERC licenses
(extending through years ranging from 2002 to 2037) or have qualified for
exemption from FERC licensing. Additionally, certain of the Company's projects
aggregating 2.3 megawatts are not subject to licensing or exemption. An
exemption exists for the duration of the life of the facility. FERC has
successfully asserted jurisdiction over six previously unlicensed projects,
requiring the Company to license these projects. In 1996, the Company incurred
$129 in costs associated with the licensing process, and such costs are deferred
until licensing is obtained or denied. The licensing process is not anticipated
to be completed until fiscal 1997, although no assurance can be provided as to
such timing or license issuance. No material adverse effect on the Company as a
whole is anticipated; however, potential costs and operational changes
associated with new licensing could adversely affect cash flows of these
projects and there is a possibility (which in management's view is limited) of
such licenses being denied. The projects which are currently due for relicensing
are included in the group of assets held for sale by the Company (see Note 20).
NOTE 9 - ACCOUNTS RECEIVABLE, ACCOUNTS PAYABLE AND ACCRUED EXPENSES
The Company reviews its accounts receivable for future collectability.
As of June 30, 1996 and 1995, allowance for doubtful accounts on certain O&M
receivables was approximately $170 and $0, respectively.
Accounts receivable comprise the following at June 30, 1996 and 1995:
-53-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 9 -- ACCOUNTS RECEIVABLE, ACCOUNTS PAYABLE AND ACCRUED EXPENSES (continued)
1996 1995
Accounts receivable trade $ 6,512 $ 3,963
Accounts receivable O&M contracts, net 739 1,296
Accounts receivable insurance claims 198 838
Accounts receivable other 405 358
--------- ----------
$ 7,854 $ 6,455
======= =======
Accounts payable and accrued expenses, inclusive of related party
payments due to GECC, comprise the following at June 30, 1996 and 1995:
1996 1995
-------------------------------
Accrued interest $ 3,149 $ 2,619
Accounts payable 1,074 1,382
Accrued lease expense payable to
a related party 1,746 1,831
Accrued compensation 998 575
Accrued severance (Note 19) 1,141 --
Other accrued expenses 2,388 2,510
----- -----
$ 10,496 $ 8,917
======= =======
-54-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 10 - REFINANCING OF DEBT AND CAPITAL
In June 1993, the Company raised $182.4 million through an offering in
reliance on Rule 144A under the Securities Act of 1933, comprised of $112.1
million from the sale of 12% senior discount notes due 2003 (the "Old Notes")
and $70.3 million from the sale of 13,695 units. Each unit consisted of 10
shares of 13.5% cumulative redeemable exchangeable Series H preferred stock (the
"Series H Preferred") and 18 warrants (the "Class B Warrants") to purchase Class
B common stock (the "Class B Common") of the Company. Each Class B Warrant
entitles the holder to purchase one share of Class B Common at an exercise price
of $40 per share. The Class B Warrants detached and became separately
transferable from the Series H Preferred at the close of business on November
22, 1993. The issue price of the notes represents a yield to maturity of 12%
computed on the basis of semi-annual compounding until reaching the $202.3
million aggregate principal amount in July 1998, after which the interest will
become payable semi-annually.
In February 1994, the Company consummated its offer to exchange (the
"Offer to Exchange"): (i) its 12% Senior Discount Notes Due 2003, Series B (the
"New Notes"), for an equal principal amount of its outstanding $202.3 million
aggregate amount Old Notes (together with the New Notes, the "Notes"); and (ii)
new shares of the Series H Preferred Stock (the "New Preferred Stock") for
136,950 outstanding shares of the Series H Preferred Stock, (together with the
New Preferred Stock, the "Preferred Stock"). In conjunction with the Offer to
Exchange, the Company also solicited consents (the "Consent Solicitation") from
holders of Old Notes to amend the indenture relating the Old Notes to allow for
the issuance of the New Notes (the "Amendments"). Holders who tendered Old Notes
for exchange were deemed to consent to the Amendments. The form and terms in
each of the New Notes and the New Preferred Stock are the same as the form and
terms of each of the Old Notes and the Old Preferred Stock, respectively, except
that: (i) each of the New Notes and the New Preferred Stock are registered under
the Securities Act and hence do not bear the legend restricting the transfer
thereof; and (ii) holders of each of the New Notes and the New Preferred Stock
are not entitled to certain rights of holders of the Old Notes and Old Preferred
Stock, respectively, under a Registration Rights Agreement.
-55-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 - LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES
Long-term debt and capitalized lease obligations comprise the following
at June 30, 1996 and 1995:
1996 1995
Parent Company Debt:
Debt guaranteed or issued by the Parent
Company directly - 12% Senior Discount
Notes due 2003, non-cash interest
computed on the basis of semi-annual
compounding through July 15, 1998, after
which interest, computed on the face
value, becomes payable semi-annually in
cash. $151,131 $ 134,506
-------- ------------
151,131 134,506
-------- ------------
Non-Recourse
Debt of Subsidiaries secured by project
assets unless otherwise noted:
Capitalized lease obligations maturing
at various dates through 2008. 27,525 29,299
Term loan agreement with an investor due
in quarterly payments through 2003,
interest payable at the CP Rate, as
defined, plus a margin of 4.0%, (9.42%
and 10.05% at June 30, 1996 and 1995,
respectively.) 28,522 28,665
Term loan agreement with an investor due
in quarterly payments through 2013,
interest payable at a fixed rate of
11.59%. 6,621 6,747
Term loan agreement with a bank,
principal due in semi-annual payments
through 2007, interest due quarterly on
current loan balance at the London
Interbank Offered Rate, as defined, plus
a margin of 1.25% (interest at 6.69% and
7.56% at June 30, 1996 and 1995,
respectively). Interest due quarterly on
overdue principal
-56-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 -- LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES (continued)
payments of $1,624 and $1,275 at June
30, 1996 and 1995, respectively, at the
prime rate, as defined, plus a margin of
2.0% (interest at 10.25% and 11.00% at
June 30, 1996 and 1995, respectively). 14,500 14,784
Note payable to an insurance company,
due in monthly payments through 2007,
interest at 12.7%. 7,619 8,380
Note payable to an insurance company,
due in quarterly payments through 2003,
interest at 11.25%. 6,795 7,024
Term loan agreement with a bank, due in
quarterly payments through 2006,
interest at the London Interbank Offered
Rate, as defined, plus a margin of 2.0%
in 1996 and 1995 (interest at 7.47% and
8.31%, at June 30, 1996 and 1995,
respectively). 2,700 3,339
-57-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 -- LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES (continued)
Unsecured notes payable to investors
(Note 16), interest payable annually at
various rates. 4,972 4,277
Term loan agreement with a bank, due in
quarterly payments through 2006,
interest at the London Interbank Offered
Rate, as defined, plus a margin of 2.0%
in 1996 and 1995, (interest at 7.47% and
8.31% at June 30, 1996 and 1995,
respectively). 1,801 1,836
Unsecured notes payable to investors
(Note 16), interest payable annually at
the prime rate, as defined (8.25% and
9.0% at June 30, 1996 and 1995,
respectively). 3,968 3,600
Security deed held by the previous
owners of a hydroelectric facility, due
June 18, 1999. Interest payable monthly
at a fixed rate of 11.5%. 1,000 1,000
Notes payable to an insurance company,
due in quarterly payments through 2005,
interest rate at 8.5%. 850 909
Term loan agreement with a bank, due in
quarterly payments through 2006,
interest at the London Interbank Offered
Rate, as defined, plus a margin of 2.0%
(interest at 7.47% and 8.31% at June 30,
1996 and 1995, respectively). 1,470 1,581
-58-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 -- LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES (continued)
Term loan agreement with a bank due in
quarterly payments through 2006,
interest at the London Interbank Offered
Rate, as defined, plus a margin of 2.0%
(7.47% and 8.31% at June 30, 1996 and
1995, respectively). 396 448
Unsecured notes payable to private
investors, due December 31, 1999 and
2003, including accrued interest.
Interest accrues annually at 12% with a
minimum of 3.6% of such interest being
paid in cash each December 31. 730 674
Other long-term liabilities with various
rates and maturities.
6,020 6,809
------- ------
115,489 119,372
------- -------
Total debt and obligations under
capital leases 266,620 253,878
Less current portion (6,462) (4,991
------- -------
Total long-term debt and obligations
under capital leases $ 260,158 $ 248,887
======= =======
-59-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 -- LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES (continued)
Total interest charges associated with the above obligations were
$28,581, $24,729, and $21,283, of which $1,705, $2,951, and $2,303 was
capitalized in conjunction with the development and construction of
hydroelectric facilities in 1996, 1995 and 1994, respectively. The aggregate
long-term debt payments due each fiscal year ending June 30, including
capitalized lease obligations, net of amounts representing interest totaling
$13,170, are as follows:
1997 $ 6,462
1998 5,082
1999 5,987
2000 5,252
2001 2,890
Thereafter 240,947
--------
$266,620
========
The Old Notes were issued as part of the Refinancing (Note 10), at a
substantial discount from their principal amount and provide for cash payment of
interest commencing January 15, 1999. The issue price represents a yield to
maturity of 12% computed on a basis of semi-annual compounding until reaching
face value in 1998, after which interest becomes payable semi-annually at the
stated 12% rate. The Notes are due July 15, 2003 but may be redeemed at any time
on or after July 15, 1998 at the Company's option, in whole or in part, at 100%
of their principal amount plus accrued interest. In addition, at any time prior
to July 15, 1996, an amount of Notes representing an aggregate of up to 35% of
their principal amount at maturity may be redeemed at the option of CHI in
connection with the use of proceeds from a public offering of its common stock
at a redemption price of 110% of their then current accreted value plus accrued
interest. The Notes contain restrictive covenants providing for limitations on
indebtedness and restrictions on payments of dividends or distributions of
capital stock, among other restrictions.
In October 1993, one of the Company's former senior lenders, Den norske
Bank AS ("DnB"), provided the Company with a $20 million unsecured working
capital facility (the "DnB Facility"), which has an initial expiration date of
June 30, 1997. The DnB Facility is pari passu with the Notes. Under certain
limited circumstances, pursuant to the terms of the agreement, DnB has the
right, upon notice to the Company, to limit any further borrowings under the DnB
Facility and require the Company to repay any and all outstanding indebtedness
thereunder within one year from the date DnB provides such notice to the
Company.
As of June 30, 1996, the Company was in compliance with its covenants
under the DnB Facility. However, as of March 31, 1996 based on the Company's
financial performance for the twelve month period then ended, the Company
continued to be unable to meet one of the financial covenants as required under
the DnB Facility. In response to an earlier request from the Company, the bank
had waived compliance with respect to the covenant for the twelve month period
ended September 30, 1995 and, pending a further review of the Company's
performance and opportunities, has limited availability under the DnB Facility
to $6.1 million, the amount outstanding to provide letters of credit at
September 27, 1995. Due to the extremely low water flow in the Northeast region
during the fourth quarter of fiscal 1995 and the first quarter of fiscal 1996,
and because the measurement contained in the financial covenant is applied at
the end of each fiscal quarter on the basis of the four
-60-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 -- LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES (continued)
most recently completed quarters, the Company was unable to meet the covenant
for the twelve months ended December 31, 1995.
DnB has not waived the previous defaults by the Company, but has
offered to do so in conjunction with the execution by the Company of an
amendment which will, among other things, change the final expiration date of
the DnB Facility to June 30, 1998 from June 30, 1997, reduce (in steps) the
total commitment under the facility from approximately $6.0 million at September
30, 1996 to zero at June 30, 1998, limit the use of the DnB Facility to letters
of credit and modify certain financial covenants. The Company is currently
negotiating the amendment and waiver with DnB. There can be no assurance that
the Company and DnB will reach agreement on the terms of such an amendment. If
the additional waiver is not granted, the Company may need to replace some or
all of the outstanding letters of credit with cash deposits or other letters of
credit which could be more expensive, if available. If the Company fails to
reach agreement with DnB and the outstanding letters of credit are not replaced,
it is likely that the letters of credit under the DnB Facility will be drawn
upon. If the indebtedness created by such drawn letters of credit is not paid
when due, a default under the DnB Facility would occur and all amounts
outstanding thereunder would become due and payable after the passage of
applicable notice and grace periods. The Company does not currently expect that
it will require a revolving credit facility such as the DnB Facility for
additional working capital purposes during fiscal 1997.
The DnB Facility contains certain affirmative and restrictive covenants
which are generally consistent with the terms of the Notes and the Preferred
Stock. As of June 30, 1996, no borrowings were outstanding under the DnB
Facility, and $5,941 and $5,916 of the DnB Facility was employed to provide
letters of credit as of June 30, 1996 and 1995, respectively.
Interest on the DnB Facility borrowings is at the London Interbank
Offered Rate, as defined in the DnB Facility, plus an escalating margin of 2.5%
or the Prime Rate, as defined in the DnB Facility, plus an escalating margin of
1.5%. A fee on the unused balance is charged at a rate of 1/2 of 1% per annum.
Capitalized lease obligations consist primarily of three lease
financing transactions on four of the Company's projects. As a result of these
transactions, $22,917 in dam and appurtenant structures and $13,152 of
mechanical and electrical equipment, in the aggregate, were capitalized. The
leases have initial terms which extend through 2000, 2002 and 2008, with renewal
options in minimum one and five year increments. Two of these leases require
that lease payment reserves, with provisions for escalations in the event
certain power sales rates are not attained, be maintained for the respective
terms of the leases. In both cases, certain of these reserves must be in cash
with the balance in either cash or letters of credit from an acceptable issuer.
To the extent that it is anticipated that the minimum cash components
will not be used to fund operation expenses or lease payments in the next fiscal
year, these minimum cash components have been included in Investments and other
assets in the accompanying Consolidated Balance Sheet. Further, in connection
with one of the leases, the Company has provided a tax indemnity of an amount
not to exceed $2,750 to the extent certain specified tax benefits, as defined,
are not available to one of the owner participants, as defined. Minimum rental
commitments under these leases for the five years following June 30, 1996 are
included in the table above.
In conjunction with the acquisition of HDG, the Company entered into a
Credit and Reimbursement Agreement dated February 15, 1995, with GECC (Note 5).
The agreement provides for two term loans, the A Loan
-61-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 -- LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES (continued)
and B Loan, a revolving credit facility, and two letters of credit in support of
HDG project obligations. The A Loan, with an outstanding principal balance at
June 30, 1996 of $28,522, is secured by the stock and assets of the HDG
projects. The B Loan, with an outstanding principal balance at June 30, 1996 of
$6,621, is secured by certain other projects owned by the Company. Each of these
loans is non-recourse to the Company. The agreement also provides for a $3,000
revolving credit facility through 2013, to be drawn as necessary to pay
principal and interest due on the term loans in the case of insufficient funds
resulting from unusually low water flow. The $3,000 revolving credit facility
shall bear interest at a rate equal to the CP Rate, as defined, plus a margin of
5%. GECC has also provided two letters of credit totaling $350 in support of
certain HDG projects.
As of June 30, 1996, non-recourse project loans, aggregating $14,500,
remain in default. The $14,500 term loan agreement with a bank was assumed in
conjunction with the acquisition of certain hydroelectric assets. Pursuant to
the terms of the agreement, the loan is secured by the aggregate assets of the
project of $14,557 and $14,855 at June 30,1996 and 1995, respectively. In
September 1996, the Company received a letter of intent from the bank to allow
the Company to purchase the note from the bank at a substantial discount (see
Note 20). No assurance can be provided that the Company will successfully
acquire the note or otherwise address the existing default and, in the unlikely
event of loan acceleration, the Company is likely to abandon substantially all
of these projects due to the immateriality of its investment and the
non-recourse nature of the applicable loans. The Company believes that any such
abandonment will have no material adverse effect on the business of the Company,
its financial condition or its results of operations.
The $7,619 note payable to an insurance company was assumed in
connection with an acquisition by the Company. Pursuant to the terms of the
note, substantially all of the acquired hydroelectric assets (approximately
$19,300 at June 30, 1996 and 1995, respectively) have been pledged as security.
The $6,795 note payable to an insurance company was assumed in
connection with another acquisition by the Company. Pursuant to the terms of the
note, substantially all of the acquired hydroelectric assets (approximately
$9,526 and $11,271 at June 30, 1996 and 1995, respectively) have been pledged as
security.
The $2,700 term loan agreement (the "Loan Agreement") with a bank was
entered in connection with the acquisition of certain hydroelectric facilities.
The Loan Agreement is secured by the stock of the Company's subsidiary which
acquired the hydroelectric facilities and the subsidiary's interest in certain
limited partnerships as well as certain notes payable, by these limited
partnerships, to the Company.
The $4,972 notes payable to investors relates to the financing for the
Company's majority-owned subsidiary, Summit Energy Storage Inc. ("Summit") (Note
16). Certain warrants were also issued by Summit as part of the terms of these
notes. Interest is payable annually at December 31 at the prime rate of
interest, as defined (8.25% and 9.0% at June 30, 1996 and 1995, respectively)
for certain notes and 10% for other notes. Unpaid interest balances are added to
the outstanding principal at each December 31 and accrue interest at the
applicable note interest rate.
The $1,801 term loan agreement was originally assumed by the Company as
an interim loan in conjunction with the acquisition of a hydroelectric facility.
-62-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 11 -- LONG-TERM DEBT AND OBLIGATIONS UNDER CAPITAL LEASES (continued)
The $3,968 notes payable to investors relates to the financing for one
of the Company's pumped storage development projects, River Mountain (Note 16).
Interest is payable annually on December 31, at the prime rate of interest, as
defined. Unpaid interest balances are added to the outstanding principal at each
December 31, and accrue interest at the applicable interest rate.
The $1,000 security deed is secured by substantially all of the related
hydroelectric facility's assets (approximately $1,400 and $3,800 at June 30,
1996 and 1995).
The $850 note payable to an insurance company was assumed in connection
with an acquisition by the Company. Pursuant to the terms of the note,
substantially all of the acquired hydroelectric assets (approximately $1,400 and
$2,500 at June 30, 1996 and 1995) have been pledged as security.
The $1,470 term loan agreement was originally assumed by the Company as
an interim loan in conjunction with the acquisition of a hydroelectric facility.
Pursuant to the terms of the agreement, substantially all of the acquired
hydroelectric assets (approximately $5,500 and $5,200 at June 30, 1996 and 1995)
have been pledged as security.
The $396 term loan agreement was undertaken by the Company in
connection with the acquisition of a hydroelectric facility. Pursuant to the
terms of the note, substantially all of the acquired hydroelectric assets
(approximately $1,100 at June 30, 1996 and 1995) have been pledged as security.
The $730 notes payable to private investors relates to the financing
for CPS (Note 16) for which warrants were also issued to the holder for the
purchase of 10% of CPS common stock.
The Company has acquired a number of projects in the past that included
non-recourse project debt as part of the liabilities assumed. In certain
instances, the Company believed that some of these projects would be incapable
of servicing such non-recourse debt due to excessive debt levels, high interest
rates, and/or principal amortization schedules that exceeded available project
cash flow. The Company also continues to believe that by acquiring these
projects for little or no equity investment, it will be able to renegotiate the
non-recourse loans involved and enhance the equity value of the underlying
projects.
NOTE 12 - MANDATORILY REDEEMABLE PREFERRED STOCK
Series H Preferred, issued under the Refinancing (Note 10) for $70,299,
is recorded net of issuance costs of $3,083 and the value attributed to the
detached warrants of $5,916. The recorded value of the Series H Preferred at
June 30, 1996 and 1995 was adjusted to reflect non-cash dividends declared of
$13,057 and $11,433, respectively. In addition, the recorded value in each year
was also adjusted by $857, representing accretion of the issuance costs and
attached warrant value in 1996 and 1995, which is being accreted over 10.5 years
to the redemption date.
-63-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 13- CAPITAL STOCK
RECAPITALIZATION / INVESTOR GROUP PREFERRED STOCK
In fiscal 1992, the Company consummated the Recapitalization pursuant
to the terms of the Purchase Agreement dated March 25, 1992 between the Company
and the Investor Group.
Immediately prior to the closing date of the Purchase Agreement, the
Company exchanged Class A Common for all shares of the then existing Class B
common stock on a one-for-one basis and accelerated the issuance of 451,202
warrants deemed effective and earned by GECC pursuant to the Acquisition
Facility.
Under the terms of the Purchase Agreement, the Investor Group purchased
55,000 shares of 8% Senior convertible voting preferred stock ("Series F
Preferred"), 55,000 shares of 9.85% Junior convertible voting preferred stock
("Series G Preferred") and certain warrants as disclosed herein for an aggregate
purchase price of $110,000. Concurrent with the issuance of the Series F
Preferred and Series G Preferred, the Company approved and issued warrants to
the Investors (the "Investor Warrants") to purchase 809,192 shares of its Class
A Common at a purchase price of $0.001 per share. The Investor Warrants are
exercisable through March 25, 1997, at such time when the current market price,
as defined, of the Company's Class A Common is first valued in excess of $135
per share, on a fully diluted basis, as defined. In addition, warrants for
issuance to certain members of management (the "Management Warrants") were
approved concurrent with the issuance of the preferred stock, but were not
formally issued as of June 30, 1996. See Note 14 for further discussion.
The Investor Group's $110,000 was allocated $54,975 to the Series F
Preferred, $54,975 to the Series G Preferred and $50 to the Investor Warrants.
The carrying value of the stock was reduced by $11,242 representing costs
associated with the issuance, allocated evenly between the two series. The
Series F Preferred and Series G Preferred are convertible into the Company's
Class A Common, subject to certain specified conditions, at the option of the
holder, through March 25, 2007 at a per share rate equivalent to the liquidation
preference ($1,000) divided by the conversion price (initially $40 per share,
subject to adjustment, as defined).
Dividends on the Series F Preferred and Series G Preferred are
cumulative (amounting to $40,906 and $31,089 at June 30, 1996 and 1995,
respectively) and are payable annually in arrears upon declaration by the
Company's Board of Directors. The cumulative undeclared dividends in arrears per
share as of June 30, 1996 and 1995 were $333.33 and $253.33 for the Series F
Preferred and $410.42 and $311.92 for the Series G Preferred, respectively.
Under certain specified conditions constituting a "Trigger Date", as defined in
the Restated Certificate of Incorporation of the Company, the holders will be
entitled to convert any or all accrued and unpaid dividends into shares of Class
A Common by dividing such dividends by 85% of the Market Price, as defined, of
the Class A Common. The Company may redeem the Series F Preferred and Series G
Preferred, at its option: (i) anytime subsequent to March 25, 2000; or earlier
(ii) if a public trading market for the Company's common stock exists, the
market value exceeds $60 per share, and the Investor Group, upon redemption,
will receive a minimum internal rate of return on their investment of 30%. The
redemption price will be equal to $1,000 per share plus all accumulated and
unpaid dividends. A public trading market for the Class A Common is deemed to
exist only if 30% of the fully diluted common stock, owned by other than certain
related parties, is freely tradable without further registration.
-64-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 13 --CAPITAL STOCK (continued)
ISSUANCE OF SERIES F AND G PREFERRED STOCK
In February 1996, Ms. Carol H. Cunningham, the Company's Executive
Vice-President and Chief Development Officer, exercised her option under an
existing agreement with the Company to have the Company issue 1,279 shares of
Series F Preferred Stock and 1,279 shares of Series G Preferred Stock in
exchange for shares of Summit stock (or vested options therefor) owned by Ms.
Cunningham. The Company plans to issue such shares of Series F Preferred Stock
and Series G Preferred Stock during the first quarter of fiscal 1997 and will
record the Series F Preferred Stock and the Series G Preferred Stock, when
issued, at the nominal fair value of the Summit stock received.
LIMITATIONS ON DIVIDENDS AND STOCK PURCHASES
As a result of the Refinancing, 246,510 shares of Class B Common must
be reserved for issuance upon exercise of the Class B Warrants. The Purchase
Agreement requires that shares of unissued Class A Common be reserved in the
amount necessary to satisfy all of the obligations of issuance in the event of a
conversion of the Series F Preferred and Series G Preferred and/or the
redemption of any outstanding warrants, or a total of 4,576,925 shares at June
30, 1996 and 1995. It further provides for certain limitations including limits
on indebtedness, capital expenditures, investments, loans and advances and
further equity transactions.
REFINANCING / SERIES H PREFERRED STOCK
In fiscal 1993, the Company completed the Refinancing under which
136,950 shares of Series H Preferred were issued (Note 10). The Series H
Preferred ranks senior to all classes of common stock and the Series G Preferred
stock and junior to the Series F Preferred. The Series H Preferred is
mandatorily redeemable on December 31, 2003 at $1,000 per share, plus accrued
interest and unpaid dividends. However, it may be redeemed, at the Company's
option, any time after June 30, 1998, in whole or in part, at the then current
liquidation preference plus all accrued and unpaid dividends. Also, at any time
prior to June 30, 1996, an amount of Series H Preferred representing an
aggregate of up to 35% of its liquidation preference at the mandatory redemption
date may be redeemed at the option of CHI in connection with the use of proceeds
from a public offering of its common stock at a redemption price of 111% of its
then current liquidation preference plus accrued and unpaid dividends.
The initial liquidation preference of the Series H Preferred was
$513.32 per share at issuance on June 22, 1993 and current liquidation
preference was $766.79 per share on June 30, 1996. The liquidation preference
will be increased as form of payment for declared dividends required quarterly
in arrears, computed based on the then current liquidation preference, until
increasing the liquidation preference to $1,000 per share on June 30, 1998,
after such time the dividends will become payable in cash from legally available
funds, when, and if declared by the Board of Directors.
The Company may, at its option, on any scheduled dividend payment date
occurring on or after June 30, 1998, exchange the Series H Preferred, in whole,
for debentures with a principal amount of $1,000, bearing interest at 13.5%,
payable quarterly. The debentures would be general unsecured liabilities of the
Company and would rank junior to the Notes. The exchange debentures would be
issued in $1,000 principal amounts for each $1,000 of liquidation preference of
the Series H Preferred and a cash sum will be paid for all accrued but unpaid
dividends.
-65-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
In the event the Company fails to make the required dividend payments,
the dividend rate rises 0.25% per quarter, to a maximum of 16.5%, until paid in
full. Among other restrictions and covenants, the Series H Preferred provides
for limitations on the payment of dividends or distribution of capital stock of
any of its Restricted Subsidiaries, as defined. After June 30, 1998 in the event
that cash dividends on the Series H Preferred are in arrears and unpaid for more
than six quarters, whether or not consecutive, the Board of Directors of the
Company will be increased by two directors and the holders of the majority of
the Series H Preferred, voting separately as a class, will be entitled to elect
two directors of the expanded Board of Directors. Such voting rights and Board
membership will continue until such time as all dividends in arrears on the
Series H Preferred are paid in full.
NOTE 14 - EMPLOYEE EQUITY PROGRAMS, DIRECTOR COMPENSATION AND 401(K) PLANS
EMPLOYEE EQUITY PROGRAMS
In conjunction with the Recapitalization (Note 13) the Board of
Directors authorized the adoption of a Stock Option Plan (the "SOP"). The SOP,
which was approved by the Company's stockholders on September 30, 1992, replaced
the prior Performance Unit Plan ("PUP") as a result of 100% participation in the
Exchange Program, discussed below.
The SOP provides for a maximum number of 350,000 options, each to
purchase one share of Class A Common. Options are at the discretion of the Board
of Directors on the basis of exercise prices equal to Fair Market Value, as
defined, at the time of the grant. Options granted prior to December 31, 1992
ratably vest daily over 5 years, however, options granted on December 31, 1992,
and after, ratably vest annually over 5 years. Vesting for certain options,
under certain defined circumstances, may be accelerated.
Pursuant to a plan approved by the Company's Board of Directors, PUP
participants were offered the right to exchange all, but not less than all, of
their PUP units to stock options under the SOP (the "Exchange Program"). PUP
vesting as of the date of the exchange and unit pricing was carried over to the
SOP grants. As an inducement to PUP participants to participate in the Exchange
Program, each SOP participant was given the right, but not the obligation, to
sell to the Company 19.53% of their vested SOP options as of December 31, 1992
(the "Tranche A Sale") and incrementally vested SOP options as of March 25, 1994
(the "Tranche B Sale"). The repurchase of such options by the Company was based
upon a common stock price of $38.40 per share for each of the Tranche A and B
Sales. In December 1992, there was 100% participation in the Exchange Program,
with a 96% redemption rate in the Tranche A Sale, at a total purchase price of
$721. In December 1993, there was a 72% redemption rate in the Tranche B sale,
at a total price of $171.
At June 30, 1996, 1995 and 1994, unvested SOP grants at less than Fair
Market Value, as defined, and converted under the Exchange Program at the same
prices as granted under the PUP, amounted to $0, $99, and $328, respectively.
During fiscal 1996, 1995 and 1994, options to purchase 0, 47,000, and
56,900 shares, respectively, of the Company's Class A Common, exercisable at $50
per share were granted to employees pursuant to the SOP. Included in the charge
for employee and director equity participation programs were vested SOP grants
valued at $99, $229 and $670 in 1996, 1995 and 1994, respectively. Since the
exercise price is equivalent to the Fair Market
-66-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 14 -- EMPLOYEE EQUITY PROGRAMS, DIRECTOR COMPENSATION AND 401(K) PLANS
(continued)
Value, as defined, at the time of issuance, no related compensation expense has
been recorded. Transactions for 1996, 1995 and 1994 are summarized as follows:
1996 1995 1994
Outstanding, beginning of year 323,286 279,805 246,611
Granted during the year -- 47,000 56,900
Repurchased during the year
(at prices ranging from $13.50 to
$25.00) -- -- (7,247)
Forfeitures (54,505) (3,519) (16,459)
------- ------- -------
Outstanding, end of year 268,781 323,286 279,805
======= ======= =======
Options eligible for exercise,
end of year (at prices ranging
from $13.50 to $50.00 per share) 184,973 207,147 171,414
======= ======= =======
Options available for grant,
end of year 81,219 26,714 70,195
======= ======= =======
The Company has a management stock option plan (the "Special Stock
Option Plan" and "Special Stock Options," issued thereunder), the terms of which
are not finalized, which is intended to provide certain management with stock
rights previously authorized as Management Warrants under the terms of the
Recapitalization (see Note 13). These Special Stock Options will be exercisable
through March 25, 1997, at such time when the current market price, as defined,
of the Company's Class A Common is first valued in excess of $135 per share, on
a fully diluted basis, as defined. Although none of the Special Stock Options
were formally issued as of September 1, 1996, the Company has notified certain
selected members of management that they will receive Special Stock Options.
Pursuant to an employment agreement dated November 1, 1994 between the
Company and an executive member of management, the Company granted 10,000 shares
of Class A Common at a purchase price of $.001 per share. The Company has the
right to repurchase these shares at a nominal price under certain defined
circumstances. As discussed below, deferred compensation related to this
issuance was recorded in 1995 and is being recognized ratably over a five-year
vesting period, per the terms of the agreement.
-67-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
DIRECTOR COMPENSATION
Effective January 1, 1995, the board of directors approved a calendar
year 1995 compensation package for all non-management board members entitling
them to receive $20 annual compensation in one of the following forms selected
at their discretion: (i) a $20 grant of Class A Common based upon $50 per share
or (ii) a $10 grant of Class A Common based upon $50 per share plus an annual
retainer of $10 paid quarterly. Director compensation in the form of 0 and 2,400
shares of Class A Common was issued and $18 and $20 was paid as of June 30, 1996
and 1995, respectively. Certain board members have elected to have their stock
entitlements issued to the employer or partnership with which they are
affiliated. In conjunction with this stock issuance, deferred compensation was
recorded and is being recognized over a calendar year. Effective January 1,
1996, compensation for non-management board members was suspended.
In 1996 and 1995, $0 and $620, respectively, was recorded as deferred
compensation relating to the above mentioned stock issuances to the board of
directors and a member of executive management. Included in the charge for
employee and director equity participation programs were vested board of
directors and executive employee stock grants valued at $160 and $110 in 1996
and 1995, respectively.
401(k) PLAN
The Company provides a defined contribution 401(k) plan which covers
substantially all of its domestic employees subject to certain prequalification
requirements. Eligible participants are allowed to make voluntary contributions
to the plan up to a specified portion of their compensation, as defined, of
which the Company will match 40% of the first 5% of compensation contributed.
Effective January 1, 1996, the Company has increased its match to 60% of the
first 5% of compensation contributed. Costs of the plan were charged to
operations as compensation expense in 1996, 1995 and 1994.
-68-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 15 - TAXES
The benefit/(provision) for income and franchise taxes consists of the
following for the years ended June 30:
1996 1995 1994
---- ---- ----
Federal income taxes $ (283) $ (220) $ --
State income and franchise
taxes (287) (157) (264)
Deferred tax benefits 7,951 -- --
------ ------- -------
$ 7,381 $ (377) $ (264)
======= ======= ========
The benefit/(provision) for income and franchise taxes differs from an
amount computed by applying the statutory income tax rate to pre-tax income, as
follows, for the years ended June 30:
1996 1995 1994
---- ---- ----
Tax benefit at US statutory rate $ 32,542 $ 5,405 $ 4,802
State income tax expense (156) (57) (155)
State franchise tax expense (131) (100) (109)
Losses without current tax benefit (24,591) (5,405) (4,802)
Alternative minimum tax (283) (220) --
--------- ------- -------
$ 7,381 $ (377) $ (264)
======== ======== ========
Significant components of the Company's deferred tax assets and
liabilities as of June 30, 1996 and 1995 are as follows:
1996 1995
Deferred tax assets:
Net operating loss $22,865 $23,013
Tax credits 5,851 6,445
Lease payment obligations 10,480 11,230
Original issue discount 15,598 10,033
Pumped storage development costs 15,785 --
Valuation reserve (49,266) (22,637)
------- -------
-69-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 15 -- TAXES (continued)
Total deferred tax assets, net 21,313 28,084
-------- -------
Deferred tax liabilities:
Tangible asset basis difference $38,235 $51,806
Intangible asset basis difference 11,097 11,796
Land 628 628
------- -------
Total deferred tax liabilities 49,960 64,230
------- -------
Net deferred tax liability $28,647 $36,146
======= =======
The deferred tax benefit of approximately $7.9 million for the year
ended June 30, 1996 relates to the write-down of certain long-lived assets in
accordance with SFAS 121 (see Note 4). The effective tax rate of the deferred
benefit recognized from the write-down differs from the federal statutory rate
due to the reduction of deferred tax liabilities offset by an increase in the
valuation allowance attributable to net operating loss carryforwards.
The valuation allowance increased by $26,629 primarily due to the
reduction of taxable temporary differences for book depreciation and
amortization previously projected to be recognized during the net operating loss
carryforward period and an overall increase in other gross deferred tax assets,
the future benefits of which are not more likely than not to be realized.
At June 30, 1996, 1995 and 1994, the Company had net operating loss
("NOL") carryforwards for federal income tax purposes ("Tax NOL") of
approximately $67,300, $72,900, and $73,900, respectively, expiring through
fiscal 2011. Of the amounts at June 30, 1996, the Company has available acquired
federal income tax net operating loss ("Acquisition NOL") carryforwards in the
amount of approximately $5,700 representing unused losses accumulated by certain
entities prior to their acquisition by the Company. These NOLs, which expire in
varying amounts beginning with fiscal 1998, are restricted in terms of
utilization. Also included in the Tax NOL at June 30, 1996 are available Federal
income tax carryforwards from an unconsolidated subsidiary. These NOLs, which
total approximately $7.2 million, expire through the year 2011 and are
restricted in terms of utilization.
At June 30, 1996, the Company has approximately $2,400 of investment,
energy and AMT credits available to reduce future income taxes for federal
income tax reporting purposes expiring during fiscal 2001 through 2003.
Additionally, the Company has available investment, energy and AMT credits in
the amount of approximately
-70-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
$3,400, representing unused credits accumulated by certain entities prior to
their acquisition by the Company. These credits, which are restricted in terms
of utilization, will begin to expire in fiscal year 1998.
The utilization of $20,400 of the Company's Tax NOL carryforwards is
limited under current law to a maximum annual amount of approximately $3,400
plus the portion of this annual limitation not utilized in any prior year. As of
June 30, 1996, the aggregate amount of these NOLs which have accumulated under
this calculation and are available to be utilized currently is approximately
$11,400. The amount of the above noted tax credits which can be utilized in any
one future fiscal year is also restricted in the same manner as the restricted
Tax NOL carryforwards. Any future utilization of the Acquisition NOL or tax
credit carryforwards noted above would be reflected as a retroactive reduction
of goodwill, to the extent thereof, in accordance with the purchase method of
accounting.
NOTE 16 - COMMITMENTS
OPERATING LEASE COMMITMENTS
The Company has several non-cancelable operating leases expiring
through 2078. The majority of these leases require annual lease payments based
upon a percentage of gross or net revenues, as defined in the respective lease
agreements, and provide for minimum annual payments to the lessor.
Minimum rental commitments under non-cancelable operating leases for
the five fiscal years following June 30, 1996 are approximately $5,000 per year.
SUMMIT ENERGY STORAGE INC.
On March 30, 1988, the Company acquired a substantial majority interest
in Summit, which is included in the consolidated financial statements of the
Company. As of June 30, 1996 and 1995, the Company's interest in Summit is
approximately 72% and 69%, respectively, after giving effect to issued (and to
be issued), but unexercised, warrants held by certain parties. The Company's
interest in Summit increased in 1994 and 1995 due to equity entitlements
attached to loans the Company had made to Summit. The Company has funded, in
accordance with its various commitments to Summit, approximately $18,000 and
$17,000 at June 30, 1996 and 1995, respectively.
Certain manufacturers of hydroelectric equipment have purchased certain
preferred stock in Summit in the amount of $2,050. In addition, $4,972 and
$4,277 has been funded through non-recourse loans with other investors at June
30, 1996 and 1995, respectively (Note 11). The Company has certain contingent
obligations, primarily in the pumped storage areas and particularly in Summit,
payable only upon the successful occurrence of certain events which would
generate sufficient cash flow to fully satisfy such obligations.
Summit holds a FERC license for a proposed 1500 MW pumped storage
hydroelectric plant planned for Norton, Ohio. The project is the first
independently sponsored pumped storage project ever to receive a FERC license,
which was issued in April 1991. While the license required that construction of
the project was to have
-71-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
NOTE 16 -- COMMITMENTS (continued)
begun by April 1, 1993, FERC extended this deadline, under its legal authority,
until April 1995. The Company is currently pursuing extension of the date of
start of construction.
The continued restructuring and other events which have created a
climate of uncertainty regarding the future structure of the U.S. utility
industry have made it increasingly difficult to secure long-term contracts with
utilities and have, therefore, significantly impaired the development of the
Company's pumped storage projects. In addition, recent enhancements to the
efficiency of combustion turbines, which offer peaking capacity in competition
to pumped storage, coupled with the lowered capital costs of such turbines and
the current low costs of natural gas have combined to put additional competitive
pressure on the Company's pumped storage projects. As a result, the Company has
concluded that the prospects for successfully developing its pumped storage
prospects are remote, and is currently limiting its pumped storage activities to
the minimum necessary to maintain the viability of the Summit project and the
monitoring of market conditions relevant to the project with the intention of
pursing commitments from area utilities for the balance of the project's
capacity.
CONSOLIDATED PUMPED STORAGE
In July 1989, the Company formed CPS for the purpose of pursuing pumped
storage hydroelectric opportunities throughout the United States. CPS focuses
its efforts on development of specific projects as well as providing certain
consulting services.
Since inception, certain outside investors have funded an aggregate of
$550 for CPS preferred stock with warrants. An additional $500 was obtained in
exchange for a Subordinated Promissory Note (Note 11). On June 30, 1992, the
Company purchased 18 shares of the preferred stock and attached warrants from
one of the outside investors for a total purchase price of $750. As a result of
these transactions, on a fully diluted basis, the Company's ownership of CPS is
80% of the issued and outstanding CPS common stock, assuming exercise of all
warrants and employee equity entitlements. In August 1996, the Company entered
into a letter agreement, subject to final documentation, and other conditions
with Carol H. Cunningham to sell its equity interests in CPS and each of its
subsidiaries. (See Note 20).
CONSOLIDATED PUMPED STORAGE ARKANSAS, INC.
In July 1990, the Company formed a new subsidiary of CPS, Consolidated
Pumped Storage Arkansas, Inc. ("CPS Arkansas"), and as of June 30, 1996 and
1995, CPS owns approximately an 85% equity interest, on a fully diluted basis.
Under a development agreement, CPS Arkansas acquired the exclusive rights to
develop, construct and operate the proposed 715 MW River Mountain pumped storage
project ("River Mountain") near Russellville, Arkansas. The license for this
project was granted by the FERC in October 1994.
CPS Arkansas secured a $1,500 investment in River Mountain from a major
manufacturer of hydroelectric equipment in the form of a non-recourse loan (the
"1991 Loan"), which had balances of $2,037 and $1,872 including accrued interest
on June 30, 1996 and 1995, respectively (Note 11). The loan agreement also
provides that, subject to certain conditions precedent if River Mountain is
constructed, such lender will have the right to supply certain equipment to this
project.
In December 1991, CPS Arkansas also secured an additional $1,500
investment from another manufacturer of hydroelectric equipment (the "1992
Loan"). The non-recourse loan commitment, which had balances of $1,881 and
$1,728 also including accrued interest on June 30, 1996 and 1995, respectively,
(Note 11) has terms similar to the 1991 Loan but also included certain minor
equity entitlements.
-72-
<PAGE>
CONSOLIDATED HYDRO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as
otherwise noted)
PUMPED STORAGE DEVELOPMENT
The Company has concluded that the prospects for successfully
developing its pumped storage prospects are remote, and is currently limiting
its pumped storage activities to the minimum necessary to maintain the viability
of the Summit project and the monitoring of market conditions relevant to the
project with the intention of pursing commitments from area utilities for the
balance of the project's capacity.
INDEMNIFICATIONS
In connection with the financing of certain projects, it has been
assumed that certain tax benefits will be available. In the event that all or
part of certain tax benefits are subsequently determined to be unavailable, the
related project subsidiary and, in limited circumstances, the Company and/or
intermediate subsidiary thereof have agreed to indemnify for such lost tax
benefits. As of June 30, 1996, no claims have been made. It is management's
opinion that future material claims are unlikely.
NOTE 17 - INSURANCE CLAIM
In March 1994, the Company experienced a property damage claim at the
Boott Project located in Lowell, Massachusetts. The incident was covered under
the Company's umbrella property and business interruption insurance policy. The
total claim as of June 30, 1996 was $4,088 of which approximately $72, $290 and
$2,440 were recorded as business interruption revenue and $457, $329 and $500
were related to recoverable property damage at June 30, 1996 and 1995 and 1994,
respectively. In full payment of the claim, the Company has received $4,384 as
of June 30, 1996, of which $2,802 related to business interruption revenue
earned in fiscal 1994 through fiscal 1996 and $212 of business interruption
revenue to be earned during the first quarter of fiscal 1997 and $1,286 related
to recoverable property damages (net of a self-insurance deductible charge of
$100) incurred in fiscal 1994 through fiscal 1996 and approximately $84 related
to property damages to be incurred in fiscal 1997.
NOTE 18 - RELATED PARTY TRANSACTIONS
The Company has agreed to purchase certain specific and nonspecific
project related equipment, aggregating $3,000, from Asea Brown Boveri AS
(formerly known as EB Corporation), a related party company and/or an affiliate
thereof, if and when such equipment is required. Management believes that the
prices to be paid for the aforementioned equipment will be at prices
substantially equal to those which would be paid to an independent third party
vendor.
The Company maintained various financing arrangements with GECC, a
minority stockholder of and significant lender and provider of partnership
equity to the Company and/or its projects, during substantially all of 1993. The
Refinancing effectively eliminated GECC as a preferred equity participant and
creditor of the Company, however, GECC remains a creditor through project
financings, including the HDG transaction, and the Acquisition Facility, which
remains in place. An officer of GECC was also a member of the Company's Board of
Directors until December 15, 1993, when he resigned. Transactions indicated on
the face of the financial statements as related party transactions include those
with GECC.
In conjunction with the Recapitalization of 1992 (Note 13), the
Company sold an equity interest to Madison Group, L. P. ("Madison"), a member of
the Investor Group, and paid associated fees to Davenport Management, Inc.
("DMI"), a former affiliate of Madison. Two of the stockholders of DMI, one of
which is the president of
-73-
<PAGE>
CONSOLIDATED HYDRO, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(amounts in thousands except shares and per share amounts or as otherwise noted)
DMI and the other of which is the former President of the Company, are also
former members of the Company's Board of Directors. These two individuals are
also beneficiaries to equity interests held by the general partner of Madison.
The equity interest sold to Madison amounted to $20,000.
Transactions indicated on the face of the financial statements as
related party also include transactions with Morgan Stanley & Co. Incorporated
("Morgan Stanley"), affiliates of which are investors in the Company through The
Morgan Stanley Leveraged Equity Fund II, L.P.
On October 13, 1994, the Company engaged Morgan Stanley to provide the
Company with financial advice and assistance. In connection with that
assignment, Morgan Stanley has explored various options to increase shareholder
value including a possible sale of the Company or interests therein. The Company
has paid approximately $300 of fees to Morgan Stanley as of June 30, 1996 with
respect to the above agreement.
NOTE 19 - EXECUTIVE EMPLOYEES
Effective June 30, 1996, Olof S. Nelson resigned as Chairman of the
Board of Directors, Director, President and Chief Executive Officer of the
Company as well as each of the executive and director positions Mr. Nelson held
with any of the Company's subsidiaries and affiliates. As a result of Mr.
Nelson's resignation, a severance accrual has been established as of June 30,
1996 in the amount of approximately $1.1 million.
In addition, the Company has entered into an employment agreement,
commencing July 1, 1996 and expiring June 30, 1999 (unless renewed), with James
T. Stewart who will serve as Chief Executive Officer and Director of the
Company. Subsequent to June 30, 1996, Mr. Stewart and Edward M. Stern were
appointed Chairman of the Board of Directors and President of the Company,
respectively.
NOTE 20 - SUBSEQUENT EVENTS
AGREEMENT TO SELL CONVENTIONAL HYDROELECTRIC ASSETS
The Company has reached an agreement to sell 20 of its smaller projects
in Maine and New Hampshire, aggregating approximately 16.75 megawatts of
capacity, to a purchaser for a price of approximately $16.0 million including
working capital. The Company anticipates that it will receive half of the sale
proceeds in cash at closing and the balance within 90 days of closing. The sale
is subject to customary conditions precedent for transactions of this nature. It
is expected that Maine projects, representing 75% of the transaction value, will
close by October 31, 1996. The closing of the New Hampshire projects will occur
subsequent to the Maine closing due to the timing of required regulatory
approvals. Under the terms of the agreement, the Company will continue to
operate and maintain the projects for a period of 15 years pursuant to an O&M
contract. The total operating revenue and income from operations from the 20
projects during the years ended June 30, 1996, 1995 and 1994 was $6.8 million,
$5.6 million and $6.1 million, and $4.5 million, $3.9 million and $3.9 million,
respectively. Although the transactions if completed will provide greater
liquidity to the Company, there can be no assurance that they will be
consummated, on the terms currently anticipated. These assets to be disposed of
are stated at the lower of their carrying amount or fair value less estimated
costs to sell.
-74-
<PAGE>
SALE OF EQUITY INTERESTS
In August 1996 the Company entered into a letter agreement, subject to
final documentation, and other conditions, with Carol Cunningham, an executive
vice president of the Company and chief executive officer of CPS, pursuant to
which Ms. Cunningham has agreed to acquire CPS and each of its subsidiaries in
exchange for an early termination of her employment contract and certain other
considerations (see Part III, Item 11 - "Employment Contracts and Special
Employment Arrangements"). Upon consummation, the Company's current pumped
storage interests will be limited to the Summit project.
AGREEMENT TO ACQUIRE NON-RECOURSE PROJECT TERM LOAN
The Company has reached an agreement to acquire non-recourse project
loans aggregating $14,500 for approximately $4,600. In addition, the Company has
received a financing proposal for such loan purchase, which proposal, net of
required debt service reserves, is approximately $4,400. The financing proposal
is subject to customary due diligence and therefore, no assurance can be
provided that the Company will successfully acquire the loans.
-75-
<PAGE>
Item 9 Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
The names of the executive officers ("Executive Officers") of CHI and
its Principal subsidiaries and the directors of CHI, their ages as of June 30,
1996, and positions with CHI are as follows:
Name Age Position
James T. Stewart 48 Chairman and Chief Executive Officer
Edward M. Stern 37 President, Chief Operating Officer and
Secretary
Michael I. Storch 44 Executive Vice President -- Strategy and
Development
Pascal J. Brun 47 Senior Vice President -- Canadian
Development
Daniel S. Pease 41 Senior Vice President -- Operations
Patrick J. Danna 37 Vice President, Treasurer, and Controller
J. Christopher Hocker 45 Vice President -- Corporate Affairs
Neil A. Manna 33 Vice President -- Financial Planning
Mary C. Raynard 48 Vice President -- Human Resources
Frank T. Giacalone 45 Senior Vice President -- Development,
CHI Power, Inc.
Rickey J. Cashatt 44 Senior Vice President and General Manager,
CHI Power, Inc.
Mary V. Gilbert 34 Senior Vice President -- Finance,
CHI Power, Inc.
Frode Botnevik 49 Director
Charles J. Micoleau 54 Director
David R. Ramsay 32 Director
Frank V. Sica 45 Director
Michael H. Walkup 44 Director
- ---------------
-76-
<PAGE>
The Executive Officers of the Company are elected by the Board of
Directors and serve at their discretion with no fixed term of office, except for
Mr. James T. Stewart, Mr. Michael I. Storch, and Mr. Edward M. Stern who serve
under certain employment contracts, the terms of which are discussed in Item 11.
James T. Stewart, Chairman and Chief Executive Officer -- Mr. Stewart
joined CHI in November 1995 as President and Chief Executive Officer of CHI
Power, Inc., a newly-formed CHI subsidiary. He was elected Chairman and Chief
Executive Officer of the Company effective July 1, 1996. Prior to joining CHI,
Mr. Stewart had more than 25 years of experience in the energy industry. He
joined the engineering and construction firm of CRS Sirrine in 1985 as senior
vice president, responsible for creating its power division. In 1988 he became
president and chief executive officer of CRSS Capital, its independent power
subsidiary, and was responsible for developing more than $800 million in energy
assets at seven sites, with more than 1,300 equivalent megawatts. He became
president of CRSS, Inc., the parent company, in 1994. Mr. Stewart holds a
bachelor's degree in chemical engineering from Penn State University, a master's
degree in chemical engineering from the University of Pittsburgh, and is a
registered Professional Engineer.
Edward M. Stern, President, Chief Operating Officer and Secretary --
Mr. Stern was named to his current position with the Company in September 1996.
He previously served as Executive Vice President, Secretary and General Counsel
of CHI with primary responsibility for the company's legal, human resources,
communications, financial, acquisitions, risk management and environmental and
regulatory compliance functions. Prior to joining CHI in April 1991, Mr. Stern
was a Vice President with BayBank, Inc., a northeastern financial services
organization, where for six years he specialized in energy project finance,
foreclosures, debt restructurings and asset management. He received JD and MBA
degrees from Boston University. Mr. Stern is a member of the Massachusetts Bar
and the Federal Energy Bar.
Michael I. Storch, Executive Vice President -- Strategy and Development
- -- Mr. Storch began his employment with CHI in June 1987. He is responsible for
strategic planning relative to the future development and growth of the Company.
Previously, he was responsible for operations of hydroelectric facilities owned
by CHI and its affiliates, and for financial matters related to the Company,
including its existing operations, acquisitions, and development. Before joining
CHI he served as Vice President -- Corporate Development for G.O. Holdings
Management, Inc., a management company controlled by Anglo-French financier Sir
James Goldsmith. For the preceding ten years, he was employed by the accounting
firm of Price Waterhouse in various capacities, last serving as Senior Audit
Manager. Mr. Storch holds a Bachelor of Business Administration degree from
Baruch College. He is a member of the American Institute of Certified Public
Accountants and the New York State Society of Certified Public Accountants.
Pascal J. Brun, Senior Vice President of CHI; President, CHI Canada
Inc. -- Mr. Brun joined CHI in June 1988. He is currently responsible for
acquisition, development and operation of hydroelectric facilities in Canada.
Previously, he served as CHI's Vice President for Corporate Development,
responsible for acquisition of operating projects in the United States and
Canada. Prior to joining CHI, he was a Vice President for the SNC Group, Ltd., a
large Canadian engineering and construction company, and a Project Manager for
T. Pringer & Sons, Engineers. He holds Bachelors and Masters degrees in Applied
Sciences from Laval University and an MBA degree from the University of
Montreal.
Daniel S. Pease, Senior Vice President -- Operations -- Mr. Pease
joined CHI as a Construction Manager in 1986, and was made Vice President of
Construction in 1988 before advancing to his current position in 1992. In his
previous capacity, he was responsible for planning and managing construction
related to Company-owned facilities, and for advising on engineering and
construction aspects of development and acquisition opportunities. Currently, he
is responsible for management of all of the Company's operating hydroelectric
facilities, as well as for engineering and construction activities of the
Company. Prior to joining CHI, he was a construction supervisor for Walsh
Construction Company of Connecticut, serving on several major hydroelectric and
nuclear construction projects. He holds a BS degree from the University of
Connecticut.
Patrick J. Danna, Vice President, Treasurer and Controller -- Mr. Danna
is responsible for day-to-day financial control of the Company, including
accounting, treasury and tax, and is also responsible for integrating the
financial aspects of acquired hydroelectric facilities into the Company's system
of financial controls. He joined CHI in April 1990. Previously, from 1983 he was
employed with an accounting firm in New York City in various
-77-
<PAGE>
capacities and became a principal of that firm in 1988; prior to that, he worked
as a staff accountant for a privately held group of enterprises. He has served
as a consultant to CHI and predecessor companies in the accounting and MIS areas
since 1983. Mr. Danna received a BS degree in Accounting from Seton Hall
University in 1980. He is a Certified Public Accountant and is a member of the
American Institute of Certified Public Accountants and New York State and New
Jersey Societies of Certified Public Accountants.
J. Christopher Hocker, Vice President -- Corporate Affairs -- Mr.
Hocker joined CHI in November 1990 as Director of Communications. Currently, he
coordinates CHI's business development efforts and also is responsible for
internal and external communications relating to the Company and its major
projects in development and for public affairs related to the Company's
involvement in national industry associations. He currently is Vice President of
the National Hydropower Association. Prior to joining CHI, he was an independent
consultant specializing in communications related to the energy and
environmental industries. Previous experience also includes Marketing Manager
for Morrison-Knudsen Engineers, Inc., related to hydroelectric, environmental,
and transportation projects. Mr. Hocker received a BA degree from Stanford
University in 1973.
Neil A. Manna, Vice President -- Financial Planning -- Mr. Manna joined
CHI in 1990 as Assistant Controller. He is currently responsible for the
Company's budgeting and planning as well as providing a variety of financial
support functions. He is also responsible for the Company's risk management
functions. Prior to joining CHI he served as controller for the sales promotion
division of Marketing Corporation of America, and also served as an audit senior
for the accounting firm of Price Waterhouse. Mr. Manna received a bachelor's
degree in accounting from the University of Connecticut in 1985 and an MBA
degree with a concentration in finance from Fairfield University in 1996. He is
a Certified Public Accountant and a member of the American Institute of
Certified Public Accountants.
Mary C. Raynard, Vice President -- Human Resources -- Ms. Raynard
joined CHI in December 1992. She is responsible for developing and implementing
policies and plans related to the compensation, benefits, rights, and
responsibilities of CHI personnel. She has a total of 14 years of human
resources experience, most recently as manager of human resource programs for
Wang Laboratories, Inc. a position she held for 8 years. Her experience also
includes management of human resources for the Division of Biology and Medicine
at Brown University. Ms.
Raynard holds a Bachelor of Arts degree from Smith College.
Frank T. Giacalone, Senior Vice President, Development, CHI Power, Inc.
- -- Mr. Giacalone began his employment with CHI in November 1995. He is
responsible for the marketing and business development functions of the Company
that include domestic and international opportunities of both hydro and
industrial energy projects. Prior to joining CHI, Mr. Giacalone most recently
served as a senior business developer for CRSS Inc. where he was responsible for
the development and negotiation of energy and industrial transactions. Prior to
that he held numerous senior development positions with other energy companies,
beginning his career with General Electric Company. Mr. Giacalone holds a degree
in mechanical engineering from Widener University, and is a registered
professional engineer.
Rickey J. Cashatt, Senior Vice President and General Manager, CHI
Power, Inc. -- Mr. Cashatt joined CHI in January 1996. He is currently
responsible for the construction and operation of industrial energy facilities
of the Company, as well as providing development support. Before joining CHI
Power, Mr. Cashatt was a senior project manager for Destec Engineering Inc.
responsible for directing the development and construction of simple cycle and
combined cycle plants in the United States and internationally. Mr. Cashatt also
served as a project manager with similar responsibilities for CRS Sirrine
Engineers, Inc. prior to that. He began his with International Paper Company,
responsible for hydroelectric and combustion power plant installation and
upgrades. Mr. Cashatt holds a degree in electrical engineering from North
Carolina State and is a registered professional engineer.
Mary V. Gilbert, Senior Vice President, Finance, CHI Power, Inc. --
Mrs. Gilbert joined CHI in July 1996 and is responsible for various development
and strategic planning functions of the Company. Prior to joining CHI, she
served in several capacities with CRSS Inc. most recently as Vice President,
Controller of the parent company responsible for the accounting, financial, tax
and human resource functions of the company. Previously she had served as Chief
Financial Officer of CRSS Capital, its independent power subsidiary. Prior to
joining CRSS Mrs. Gilbert was employed by Ernst and Young for six years, last
holding the position of audit manager. Mrs. Gilbert received a Bachelor of
Science degree in Accounting from the University of Colorado at Boulder. She is
a Certified
-78-
<PAGE>
Public Accountant and is a member of the American Institute of Certified Public
Accountants and the Texas Society of Certified Public Accountants.
Frode Botnevik, Director -- Mr. Botnevik has served as a Director of
CHI since 1985. He is Chairman of the Board of NERA AS, a Norwegian wireless
telecommunications company. Previously, he was employed for 24 years by Asea
Brown Boveri AS, a provider of generating and control equipment to the electric
power industry since 1901, most recently as Executive Vice President. Mr.
Botnevik is a graduate of the Oslo School of Business Administration and the
Advanced Management Program at Harvard Business School.
Charles J. Micoleau, Director -- Mr. Micoleau has been a Director of
CHI since 1985. He is a partner in the law firm of Curtis Thaxter Stevens Broder
& Micoleau of Portland, Maine. He has been associated with that firm since 1978,
and his practice has been primarily associated with energy, environmental, and
regulatory law. He has represented a broad range of alternative energy producers
and has been actively involved in the development of federal and state law
governing private energy sales. From 1970 to 1978, Mr. Micoleau was a member of
the staff of former Senator Edmund Muskie of Maine. He received his Bachelors
degree from Bowdoin College in 1963, his Masters degree in international finance
from The Johns Hopkins University in 1965, and his JD degree in 1977 from The
George Washington University.
David R. Ramsay, Director -- Mr. Ramsay has been a Director of CHI
since December 1994. He is a Vice President of Morgan Stanley, has worked in its
Merchant Banking Division since 1989, and is a Vice President of MSLEF II. He
serves on the Board of Directors of ARM Financial Group Inc., Integrity Life
Insurance Company, National Integrity Life Insurance Company, Jefferson Smurfit
Corporation, Hamilton Services Limited and Risk Management Solutions, Inc. Mr.
Ramsay received his B.A. from Princeton University in 1985 and his M.B.A.
from Stanford University in 1989.
Frank V. Sica, Director -- Mr. Sica has been a Director of CHI since
1992. He is currently a Managing Director of Morgan Stanley, and has been with
Morgan Stanley since 1981, originally in the Mergers and Acquisitions Department
and, since 1988, with the Merchant Banking Division. He is a director and a Vice
Chairman of MSLEF II and a director of numerous companies including Fort Howard
Corporation, Pagemart, Inc., Pagemart Wireless, Inc. and Kohl's Department
Stores, Inc. He is also President of Morgan Stanley Ventures. Prior to joining
Morgan Stanley, Mr. Sica was an officer in the U.S. Air Force. He received a
Bachelor's degree from Wesleyan University in 1973 and an MBA degree from the
Tuck School of Business at Dartmouth College in 1979.
Michael H. Walkup, Director -- Mr. Walkup has been a Director of CHI
since 1988. He has been portfolio manager of The Witt-Touchton Company, a
private investment partnership in Tampa, Florida, since 1985, and has been
employed by that firm since 1982. He is also President of The Witoco Venture
Corporation. Mr. Walkup has obtained a BS degree in Business Administration, MBA
degree, and Master's degree in Accountancy from the University of South
Carolina.
There are no family relationships among the directors and officers.
The Board of Directors has established an Executive Compensation
Committee comprised of Messrs. Sica and Walkup and an Audit Committee comprised
of Messrs. Walkup, Sica and Micoleau.
-79-
<PAGE>
Item 11. Executive Compensation
The following table sets forth the compensation of the named executive
officers for services rendered during the fiscal year ended June 30, 1996, 1995
and 1994 of the Company.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
Long-Term
Compensation
Fiscal Annual Other Annual All Other
Name and Year Compensation ($) Compensation Stock Option Compensation
Principal Position Salary Bonus ($) Grants(#) ($)
<S> <C> <C> <C> <C> <C> <C>
Olof S. Nelson(1) 1996 $ 292,631(2) -- $ 9,400 -- $1,118,218(3)
President, Chief Executive 1995 287,800 50,000 4,192 -- 21,020(4)
Officer and Chairman 1994 271,000 90,000 5,348 -- 21,020(4)
Michael I. Storch 1996 226,216(2) -- 12,150 -- 17,500(4)
Executive Vice President 1995 222,175 40,000 7,870 -- 17,500(4)
- -- Strategy and Development 1994 209,175 75,000 11,238 -- 17,500(4)
Carol H. Cunningham(5) 1996 222,177(2) -- 12,150 -- 27,245(4)
Executive Vice President 1995 222,175 30,000 8,123 -- 2,540(4)
1994 209,175 25,000 11,408 -- 54,330(6)
Edward M. Stern(7) 1996 188,846(2) -- 8,900 -- 20,221(4)
Executive Vice President 1995 165,000 40,000 7,920 10,214(4)
and General Counsel 1994 135,000 50,000 3,545 214(4)
James T. Stewart(8) 1996 156,365(9) -- -- -- 108,750(9)
President and Chief Executive Officer 1995 -- -- -- --
of CHI Power, Inc. 1994 -- -- -- --
</TABLE>
- ----------------------
(1) Mr. Nelson resigned his position as President, Chief Executive Officer and
Chairman as of June 30, 1996.
(2) As of January 1, 1996, the Company has added the value of all perquisites,
except for 401(k) matching contributions and life insurance premium
payments covered under the senior management benefits policy, into each
executives base salary. Through December 31, 1995, these perquisites were
either excluded by definition from this table, or included in Other Annual
Compensation or All Other Compensation.
(3) Comprised of termination amounts (paid and to be paid) and life insurance
premiums paid on behalf of Mr. Nelson of $1,100,000 and $18,218,
respectively, in 1996.
(4) Comprised of life insurance premiums paid by the Company on behalf of each
Executive Officer.
(5) Ms. Cunningham has reached an agreement with the Company to terminate her
employment with the Company effective August 10, 1996. (See -- "Employment
Contracts and Special Employment Arrangements".)
(6) Comprised of a deferred bonus and life insurance premiums paid by the
Company on behalf of Ms. Cunningham $50,000 and $4,330 in 1994.
(7) Mr. Stern has been elected President and Chief Operating Officer of the
Company in September 1996.
-80-
<PAGE>
(8) Mr. Stewart has been elected Chief Executive Officer and a Director of the
Company as of July 1, 1996.
(9) Annual Compensation represents salary from November 1, 1995, the
commencement of Mr. Stewart's employment with the Company. Further, All
Other Compensation is comprised of a $50,000 sign-on bonus paid to Mr.
Stewart pursuant to an employment agreement dated November 1, 1995 naming
Mr. Stewart President and Chief Executive Officer of CHI Power, Inc. and an
accrued bonus of $58,750 pursuant to an employment agreement naming Mr.
Stewart Chief Executive Officer of the Company as of July 1, 1996.
-81-
<PAGE>
The following table contains information concerning the grant of stock
options under the Company's stock option plans to the named executive officers
as of the end of fiscal year ended June 30, 1996.
OPTION/SAR GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
Potential Realized
Value at Assumed
Annual Rates of
Stock Price
Appreciation for
Individual Grants Option Term(1)
% of Total
Stock Stock Options Exercise Grant
Options Granted to or Base Date
Granted Employees Price Expiration Present
(#)(2) in Fical Yr. (S/Sh) Date 5%($) 10%($) Value($)
<S> <C> <C> <C> <C> <C> <C> <C>
Grant Date Present Value($)
Olof S. Nelson -- -- -- -- -- -- --
Michael I. Storch -- -- -- -- -- -- --
Carol H. Cunningham -- -- -- -- -- -- --
Edward M. Stern -- -- -- -- -- -- --
James T. Stewart -- -- -- -- -- -- --
</TABLE>
-82-
<PAGE>
- ---------------
(1) Based on actual option term (10 years) and annual compounding rates shown.
(2) There were no stock options granted in fiscal 1996
The following table sets forth information with respect to the named
executives concerning the exercise of options during the last fiscal year of the
Company and unexercised options held as of the end of the fiscal year.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR
VALUES
<TABLE>
<CAPTION>
Number of Unexercised Stock Value of Unexercised,
Options Held at FY-End In-the-Money Stock
Options at FY-End($)(1)
Shares
Acquired Value
Name Exercise Realized($) Exercisable Unexercisable Exercisable Unexercisable
<S> <C> <C> <C> <C> <C> <C>
Olof S. Nelson -- -- -- -- -- --
Michael I. Storch -- -- -- -- -- --
Carol H. Cunningham -- -- -- -- -- --
Edward M. Stern -- -- -- -- -- --
James T. Stewart -- -- -- -- -- --
</TABLE>
- ---------------
(1) Assumed Fair Market Value of underlying securities at fiscal year-end minus
the exercise price. For purposes hereof, Assumed Fair Market Value was $0
per share.
-83-
<PAGE>
Employment Contracts and Special Employment Arrangements
In March 1992, CHI entered into a five-year employment agreement
(subject to automatic one-year renewals absent notice of intent not to renew)
with Mr. Olof S. Nelson, its then President and Chief Executive Officer.
Pursuant to the employment agreement, Mr. Nelson received an annual salary of
$243,000, which was adjusted annually by the greater of 7 1/2% or the increase
in the Consumer Price Index from the preceding year. In addition, at the
discretion of the Board of Directors, Mr. Nelson received stock options, bonuses
(which customarily have been equal to 15% or more of base salary) and salary
increases. In the event Mr. Nelson's employment was terminated by CHI (other
than a termination by CHI as a result of certain circumstances specified in the
employment agreement) during the term of the employment agreement, Mr. Nelson
was to receive monthly severance payments for the remaining term of the
agreement equal to twice his highest monthly salary (excluding bonuses) at any
time under the agreement prior to the time of termination, or he could elect to
receive this amount in a lump sum payment.
In June 1996, Mr. Nelson resigned as Chairman of the Board of
Directors, Director, President and Chief Executive Officer of CHI as well as
executive and director of each of the Company's subsidiaries and affiliates. In
conjunction with such resignation CHI and Mr. Nelson entered into a termination
agreement which superseded Mr. Nelson's employment agreement. Pursuant to the
termination agreement, Mr. Nelson received a payment of $500,000 and in addition
to certain other customary benefits, he will receive an additional monthly
payment of approximately $24,000 for a period of twenty months commencing in
August, 1996.
In March 1992, CHI also entered into a five-year employment agreement
(subject to automatic one-year renewals absent notice of intent not to renew)
with Ms. Carol H. Cunningham, its then Executive Vice President and Chief
Development Officer, Chief Executive Officer of CPS and President of SES.
Pursuant to the employment agreement, Ms. Cunningham received an annual salary
of $187,500, adjusted annually by the greater of 7 1/2% or the increase in the
Consumer Price Index from the preceding year. In addition, Ms. Cunningham has
received certain equity entitlements in CHI, CPS and SES. In August 1996 CHI
entered into an agreement, subject to final documentation, with Ms. Cunningham
which provides, among other things, that Ms. Cunningham's employment with the
Company will terminate effective August 10, 1996 and Ms. Cunningham will acquire
all of the Company's interests in CPS and its wholly-owned subsidiaries for
nominal consideration upon completion of the aforementioned arrangements. Ms.
Cunningham will serve as a consultant to the Company focusing on the continued
development of the Summit project.
In March 1992, CHI also entered into a five-year employment agreement
(subject to automatic one-year renewals absent notice of intent not to renew)
with Mr. Michael I. Storch, its Executive Vice President, which agreement was
modified in June 1995 to provide Mr. Storch with an option to renew the
agreement for one year through February 1998 and with certain other contingent
benefits. Pursuant to the employment agreement, Mr. Storch received an annual
salary of $187,500, which is adjusted annually by the greater of 7 1/2% or the
increase in the Consumer Price Index from the preceding year. In addition, at
the discretion of the Board of Directors, Mr. Storch may receive stock options,
bonuses (which customarily have been equal to 15% or more of base salary) and
salary increases. In the event Mr. Storch's employment is terminated by CHI
(other than a termination by CHI as a result of certain circumstances specified
in the employment agreement) during the term of the employment agreement, Mr.
Storch will receive either monthly severance payments for the remaining term of
the agreement equal to the monthly salary (excluding bonuses) under the
agreement for such remaining term, or he may elect to receive a lump sum payment
equal to one-half of the total amount of salary and bonus paid in the calendar
year preceding the date employment was terminated plus the salary adjustment
amount applicable to the current year.
In November 1994, CHI entered into a three-year employment agreement
(subject to automatic one-year renewals absent notice of intent not to renew)
with Mr. Edward M. Stern, its then Executive Vice President and General Counsel,
now President and Chief Operating Officer. Pursuant to the employment agreement,
Mr. Stern received an annual salary of $150,000, which may be increased at the
discretion of the Board of Directors. In addition, at the discretion of the
Board of Directors, Mr. Stern may receive stock options and bonuses (which
customarily have been equal to 15% or more of base salary). Pursuant to the
employment agreement, Mr. Stern was awarded 10,000 shares of the CHI's Class A
Common Stock (the "Restricted Shares"). Subject to certain limited exceptions,
Mr. Stern may not transfer the Restricted Shares until the earlier of (x)
November 1, 1999 or (y) such time as a person or entity which at November 1,
1994 did not own 10% of the voting equity securities of
-84-
<PAGE>
CHI on a fully diluted basis acquires 80% or more of the total combined voting
power of all classes of capital stock of CHI (a "Corporate Transaction"). If Mr.
Stern ceases to be an employee of the Company prior to the earlier of November
1, 1999 or the occurrence of a Corporation Transaction, CHI has the right to
repurchase the Restricted Shares at a purchase price of $0.001 per share. In the
event Mr. Stern's employment is terminated by CHI during the term of the
employment agreement (other than in certain specified circumstances), Mr. Stern
will receive either monthly severance payments for the remaining term of the
agreement equal to the monthly salary (excluding bonuses) under the agreement
for such remaining term, or he may elect to receive a lump sum payment equal to
one-half the total amount of salary and bonus paid in the calendar year
preceding the date employment was terminated plus any salary increase applicable
to the current year.
In November 1995 the Company entered into an employment agreement with
Mr. James T. Stewart pursuant to which Mr. Stewart became President and Chief
Executive Officer of the Company's newly-formed, wholly-owned subsidiary, CHI
Power, Inc. In July 1996, the Company entered into a new three year employment
agreement (subject to automatic one year renewals absent notice of intent not to
renew) with Mr. Stewart which superseded the prior agreement. The new agreement
provides that Mr. Stewart will serve as the Company's Chief Executive Officer,
that the Company will use its best efforts to see that he is elected to the
Company's Board of Directors, and that he will receive an annual salary of
$300,000, which may be increased annually at the discretion of the Board. In
addition, upon execution of the new agreement Mr. Stewart received a bonus
payment of $58,750 and upon the achievement of certain targets to be agreed upon
by Mr. Stewart and the Board, Mr. Stewart will be eligible to receive annual
bonuses of up to 100% of his annual salary plus equity incentives to be
determined by the Board. In the event Mr. Stewart's employment is terminated by
CHI during the term of the employment agreement (other than in certain specified
circumstances) Mr. Stewart will receive monthly severance payments equal to the
monthly salary (excluding bonuses) under the agreement for a period equal to the
earlier of (A) the date Mr. Stewart obtains subsequent employment and (B) the
later of (i) the second anniversary of Mr. Stewart's date of termination and
(ii) the expiration of the term of the employment agreement.
Director Compensation
Compensation of Directors is discussed in Note 14 of the Notes to
Consolidated Financial Statements contained herein under Part II, Item 8.
Senior Management Benefits Policy
In 1992, CHI's Board of Directors adopted a Senior Management Benefits
Policy covering certain of the Company's executive officers listed herein (the
"Participants") (see Part III, Item 10) which offers severance, supplemental
life insurance and supplemental disability insurance benefits subject to
entering into a non-competition agreement. In 1996 the Company expanded the
eligibility under the policy to include officers of certain of its subsidiaries.
Each Participant is entitled to, under certain circumstances, between 12 and 26
weeks of severance pay. In addition, each Participant shall be provided with
$150,000 of supplemental term life insurance, or such other amount or type of
insurance as determined by the Board of Directors, and supplemental disability
benefits of up to one year subject to a maximum aggregate benefit of $200,000.
To the extent that benefits under the Senior Management Benefits Policy
duplicate benefits which a Participant is entitled to receive under any other
arrangement with the Company, such benefits will not be additive.
Stock Option Plan
Under CHI's Stock Option Plan, a committee composed of directors not
eligible to participate in the Stock Option Plan or other stock-based
compensation plans of CHI (the "Committee") is authorized to grant non-qualified
options to purchase shares of CHI's Common Stock to key employees (including
officers) as additional compensation for their services to the Company. In
addition, options qualifying as "incentive stock options" under Section 422 of
the Code may be granted to employees of the Company. Options for up to 350,000
shares of CHI's Common Stock in the aggregate may be granted prior to
termination of the Plan on May 31, 2002, subject to adjustment in the event of a
stock split, stock dividend or other change in the Common Stock or the capital
structure of the Company. Options that expire unexercised may again be issued
under the Stock Option Plan subject to the foregoing limitations.
-85-
<PAGE>
Options shall be exercisable over such period determined by the
Committee, but no option may remain exercisable more than ten years from the
date of grant. All options granted under the Stock Option Plan will be
nontransferable other than by will or the laws of descent and distribution, and
each option is exercisable, during the lifetime of the optionee, only by the
optionee. Options may be exercised for up to 12 months following termination of
service under those circumstances where such termination of service is due to
convenience of either the employee or the Company, retirement, permanent
disability or death, except where the employee has been terminated for cause, in
which event such options may be exercised for three months following such
termination of employment, subject in any case to the foregoing limitation on
the maximum term of options granted under the Stock Option Plan. The purchase
price of Common Stock in the case of an incentive stock option shall be such
amount as may be determined by the Committee, but in no event less than the fair
market value of such Common Stock on the date of grant, and in the case of a
non-qualified stock option, such amount as may be determined by the Committee,
but in no event less than the par value of such shares of Common Stock. The
purchase price of Common Stock subject to an option may be paid in cash, options
or stock of the Company, or a combination thereof, except where the employee has
been terminated for cause or such employee has terminated employment at such
employee's convenience, in which case a cashless exercise is subject to a
penalty.
The Stock Option Plan also permits the satisfaction of federal income
tax or other tax withholding obligations arising on the exercise of an option by
the withholding of shares of Common Stock acquired under such option.
The Committee has discretion to determine the key employees who shall
participate in the Stock Option Plan, the number of shares of Common Stock
subject to options to be awarded to each participant, the vesting schedules of
options, the terms and conditions, if any, upon which such options may be
awarded and all other matters arising in the administration of the Stock Option
Plan.
As of June 30, 1996, 268,781 options have been granted and remain
outstanding of which 184,973 options have been vested, at exercise prices
ranging from $13.50 to $50 per option.
1992 Warrants/Special Stock Option Plan
Under the terms of the Recapitalization, the Company approved and
issued warrants to MSLEF II and Madison (the "Investor Warrants") and approved
warrants for issuance to certain members of management (the "Management
Warrants") (collectively, the "1992 Warrants"), to purchase 809,192 and 448,222
shares of its Class A Common Stock, respectively. The 1992 Warrants allow for
the purchase of the Company's Class A Common Stock at a purchase price of $.001
per share. The 1992 Warrants are exercisable through March 25, 1997, at such
time when the current market price, as defined, of the Company's Class A Common
Stock is first valued in excess of $135 per share, on a fully diluted basis, as
defined.
-86-
<PAGE>
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table sets forth certain information regarding beneficial
ownership of CHI's Class A Common Stock as of September 15, 1996 (i) by each
person known by the Company to own beneficially more than 5% of the Common Stock
of CHI; (ii) by each person known by the Company to own beneficially more than
5% of the outstanding voting Preferred Stock of CHI; (iii) by each director and
certain executive officers of CHI; and (iv) by all executive officers and
directors of CHI as a group. Except as otherwise indicated, each named person
has voting and investment power over the listed shares, and such voting and
investment power is exercised solely by the named person or shared with a
spouse.
<TABLE>
<CAPTION>
Name of Title of Number Percent of Class as of
Stockholder or Director Class of Shares September 15, 1996
<S> <C> <C> <C>
(i) More than 5% of Voting Common Stock of CHI
The Fiduciary Company(A) Class A 595,306 14.52% (H)
Madison Group, L.P. Class A (B) 500,000 12.20% (H)
The Morgan Stanley Leveraged Equity
Fund II, L.P. Class A (C) 2,250,000 54.88% (H)
Name of Title of Number Percent of Series as of
Stockholder or Director Class of Shares September 15, 1996
(ii) More than 5% of Voting Preferred Stock
of CHI
Madison Group, L.P. Series F 10,000 17.77%
Series G 10,000 17.77%
The Morgan Stanley Leveraged Equity
Fund II, L.P. Series F 45,000 79.96%
Series G 45,000 79.96%
Number
of Shares Percent of Common
Name of Title of or Share Stock as of
Stockholder or Director Class Equivalents September 15, 1996
(iii) Common Stock held by each director and certain executive officers of CHI and related parties (G)
Michael I. Storch Class A 109,185 2.66%
Edward M. Stern (D)(F) Class A 30,997 .75%
Frode Botnevik Class A 21,723 .53%
Charles J. Micoleau(E) Class A 2,438 .06%
Michael H. Walkup Class A 400 .01%
(iv) All executive officers and directors
of CHI and
related parties as a Group 219,422 5.26%
- ---------------
(A) The Fiduciary Company beneficially owns 595,306 shares of Class A Common
Stock by virtue of its power to vote and dispose of such shares. The
economic interest in (i) 313,505 of such shares is owned by a trust for the
benefit of the descendants of Olof S. Nelson, (ii) 146,969 of such shares
is owned by a trust for the benefit of descendants of Robert B. Milligan,
Jr. a former director of the Company and former affiliate at Madison Group,
L.P. and (iii) the remainder
</TABLE>
-87-
<PAGE>
of such shares is owned by certain other trusts. Mr. Nelson and
Mr. Milligan disclaim beneficial ownership of these shares.
Mr. Milligan is an affiliate of the Fiduciary Company.
(B) Represents the number of Class A Common shares which Madison Group, L.P.
has beneficial ownership based upon the exercise of its conversion right
attached to its ownership of Series F and G Preferred stock.
(C) Represents the number of Class A Common shares of which MSLEF II has
beneficial ownership based upon the exercise of its conversion rights
attached to its ownership of Series F and G Preferred stock.
(D) Except as noted in footnotes (E) and (F), all shares are represented by
vested, exercisable stock options.
(E) 1,550 of Mr. Micoleau's shares are held by an IRA in trust for his benefit.
(F) Includes 10,000 shares of Class A Common Stock which may be repurchased by
the Company for a nominal price, under certain defined circumstances.
(G) Excludes certain stock entitlements earned as director compensation which
certain directors have relinquished all beneficial interests in. See Note
14 of the Notes to Consolidated Financial Statements.
(H) Ownership percentages are calculated in accordance with SEC Rule 13d -
3(d)(1) and, therefore, exclude the dilutive effects of outstanding
warrants and stock options. Consequently, these percentages do not
represent ownership on a fully diluted basis as disclosed in Part I Item 1
"Business".
-88-
<PAGE>
Item 13. Certain Relationships and Related Transactions
Recapitalization and the MSLEF II and Madison Relationships
In early 1992, CHI sold to Madison and MSLEF II $55.0 million aggregate
liquidation value of the Series F Preferred Stock and $55.0 million aggregate
liquidation value of the Series G Preferred Stock and, together with the Series
F Preferred Stock, the "Investor Preferred Stock"). The terms of the Investor
Preferred Stock provide that, upon the occurrence of certain events (beyond
applicable cure periods, if any), including the failure by CHI to pay, when due,
a dividend or redemption payment on the Investor Preferred Stock, the breach by
CHI of any material covenant set forth in the purchase agreement relating to the
sale of the Investor Preferred Stock, the breach by CHI, in any material
respect, of any representation or warranty made in the purchase agreement
relating to the sale of the Investor Preferred Stock, the bankruptcy of CHI or
any of its significant subsidiaries, unsatisfied judgments (not covered by
insurance) in excess of $0.5 million against CHI or any of its subsidiaries,
failure by CHI to meet certain performance criteria and default by CHI or any of
its subsidiaries on any indebtedness of CHI (including the Notes) or any such
subsidiary other than any default on subsidiary indebtedness that is not
material to CHI and causes no cross default to other CHI or subsidiary
indebtedness (each an "Investor Event of NonCompliance"), the Investors will
have the right to designate a majority of CHI's Board of Directors. As a result
of the failure of the Company to meet certain of the aforementioned performance
criteria, the Investors are entitled to declare an Investor Event of
Non-Compliance.
In connection with the Recapitalization, CHI and all of its
stockholders, optionholders and warrantholders entered into the Stockholders
Agreement. After giving effect to the use of proceeds of the Refinancing and an
amendment to the Stockholders Agreement to be executed in connection with such
use of proceeds to delete the provisions thereof relating to rights granted to
GECC as a preferred stockholder, the Stockholders Agreement includes
restrictions on CHI's ability to submit to a vote of stockholders matters
customarily decided by a board of directors; provisions requiring that the Board
initially consist of eight directors, five of which shall be unaffiliated with
the Investors; provisions entitling the Investors to appoint two representatives
to the Board so long as they hold an aggregate of 10% of CHI's fully-diluted
voting equity, excluding the 1992 Warrants and any unexercisable or
out-of-the-money options, warrants or convertible securities (the Investors
having separately agreed that if either of them ceases to hold $2.0 million
aggregate liquidation preference of Investor Preferred Stock (or an equivalent
amount of converted Common Stock), then the other Investor will be entitled to
appoint both representatives); restrictions on transfers of shares held by other
stockholders; and "demand" and "piggyback" registration rights for the Investors
with respect to certain securities of CHI, including the shares of Class A
Common Stock issuable upon conversion of the Preferred Stock and the exercise of
the 1992 Warrants. The Stockholders Agreement, as so amended, further provides
for control of CHI by the Investors in those situations where there has occurred
an Investor Event of Non-Compliance pursuant to CHI's Restated Certificate of
Incorporation. In addition, the Stockholders Agreement provides that such
governance provisions would be binding on the holders of voting equity,
principally with respect to liquidation proposals.
Morgan Stanley, an affiliate of MSLEF II, received an investment
banking fee from CHI in connection with the Recapitalization. Frank V. Sica, a
Managing Director of Morgan Stanley, and David R. Ramsay, a Vice President of
Morgan Stanley, are members of the Board of Directors of CHI.
In March 1996, Robert B. Milligan, Jr., a principal of the former
general partner of Madison resigned as a member of the Board of Directors of CHI
and certain of the Company's affiliates for which he served as a board member.
Although Madison has the right to designate a replacement representative of the
CHI Board, as of September 28, 1996 it has not yet done so.
Morgan Stanley & Co. Incorporated
On October 13, 1994, the Company engaged Morgan Stanley to provide the
Company with financial advice and assistance. In connection with that
assignment, Morgan Stanley has explored various options to increase shareholder
value including a possible sale of the Company or interests therein. The Company
has paid approximately $0.3 million of fees to Morgan Stanley as of June 30,
1996 for such financial services. Morgan
-89-
<PAGE>
Stanley also acted as Placement Agent in the Refinancing and received placement
fees in connection therewith. As of June 30, 1996, the Placement Agent holds
44,303 shares of the Series H Preferred Stock for its own account.
GECC Relationship
As a result of a Management buyout financed by GECC in 1988, GECC was a
principal stockholder of CHI until consummation of the Refinancing (See Part
III, Item 12, "Security Ownership of Certain Beneficial Owners and Management").
As part of the Refinancing, the Company purchased substantially all of GECC's
equity position in CHI and terminated a $24.0 million working capital facility
previously provided by GECC.
GECC continues to make available the GECC Acquisition Facility, of
which approximately $85.0 million remained available as of September 1, 1996. In
addition to minor common stock ownership interest, GECC has, through original
investments and potential maximum investments (e.g. letters of credit, revolving
credit facilities), invested, loaned or committed approximately $231.0 million
to the Company, excluding the unused portion of the GECC Acquisition Facility.
Asea Brown Boveri
The Company has agreed to purchase certain specific and nonspecific
project related equipment, aggregating $3 million, from Asea Brown Boveri IS
("ABB", the parent company of Asea Brown Boveri AS), a stockholder of CHI (see
"Principal Stockholders"), if and when such equipment is acquired.
SES has a memorandum of understanding (a) to buy equipment and services
from an ABB subsidiary within its area of competency, other than civil
engineering and construction management, on customary arm's-length terms on a
cost-plus or other mutually agreed basis, (b) permitting such subsidiary to
designate an SES board member and (c) pursuant to which such subsidiary invested
approximately $1.4 million and received preferred stock with equivalent
liquidation value and attached warrants to purchase common stock held by CHI.
The same ABB subsidiary made aggregate bridge loans totaling approximately $0.9
million to SES and received additional warrants to purchase unissued SES common
stock. On a fully diluted basis, the warrants, if exercised, would give ABB
approximately 5% of SES common stock.
Curtis Thaxter Stevens Broder & Micoleau
Charles J. Micoleau, a member of CHI's Board of Directors, is a partner
in the law firm of Curtis Thaxter Stevens Broder & Micoleau ("Curtis Thaxter"),
which provides certain legal services to the Company. For the fiscal year ended
June 30, 1996, the Company paid such firm approximately $0.4 million for legal
fees and expenses. In addition, other partners of Curtis Thaxter, John W.
Bernotavicz and Michael B. Peisner, are Assistant Secretaries of the Company and
certain of its subsidiaries. Curtis Thaxter is entitled to preferred stock of
SES with a liquidation value of $0.2 million, plus accrued dividends on such
stock, plus warrants for less than one percent of the fully diluted common stock
of SES, as deferred compensation for work done in connection with the
development of the Summit project. Members of Curtis Thaxter, exclusive of Mr.
Micoleau, are the beneficial owners of an aggregate of 2,143 shares of the
Company's Common Stock for which they paid cash.
Others
CHI has entered into an agreement (the "Put and Call Agreement") with
SES Partners, L.P., a Delaware Limited Partnership (the "Partnership"). Pursuant
to the Put and Call Agreement, the Partnership has the right to sell to CHI in
certain circumstances (the "Put"), and CHI has the right to purchase from the
Partnership in certain circumstances (the "Call"), an option to purchase an
approximately 1.2% as of September 15, 1996 equity interest in SES (the
"Interest") from an existing shareholder of SES (the "Option"), which the
Partnership purchased from such shareholder. If the Put is exercised by the
Partnership (which it may do upon, among other things, initial funding of
construction financing of the Summit Project ("Project Financing"), abandonment
of Summit by SES or a sale by CHI of its equity interest in SES), then CHI would
issue approximately 6,000 shares of its Class A Common Stock in exchange for the
Option, which would have an exercise price of $0.7 million. If the Call is
exercised by CHI (which it may do upon Project Financing), then CHI would pay
the greater of 70.0% of the fair market value of the Interest or the purchase
price of the Option ($0.3 million) for the Interest. CHI has also
-90-
<PAGE>
acquired an option (the "Acres Option") to purchase from Acres approximately 115
shares representing 7.6%, as of September 15, 1996, of the outstanding equity of
SES. Additionally, CHI has entered into an agreement pursuant to which SES
Partners II, L.P., a Delaware limited partnership (the "Milligan Partnership")
acquired from CHI a warrant (the "Milligan Warrant") pursuant to which, upon the
happening of certain events, the Milligan Partnership has the right to purchase
approximately 37,600 shares of Class A Common Stock of CHI, subject to customary
antidilution protection. Additionally, the Milligan Partnership has granted to
CHI an option to require the Milligan Partnership to sell the Milligan Warrant
to CHI for cash. CHI has granted to the Milligan Partnership an option (the
"Acres Option Call"), pursuant to which, upon the happening of certain events,
the Milligan Partnership has the right to either (i) transfer the Acres Option
to the Milligan Partnership or (ii) convey 100% of the economic benefits of the
Acres Option (net of certain expenses) to the Milligan Partnership in cash
immediately upon the liquidation of the SES equity interests underlying the
Acres Option, which shall occur as soon as practicable after the exercise of the
Acres Option Call by the Milligan Partnership. Certain executive officers and
directors of CHI and certain of their affiliates are limited partners of the
Milligan Partnership.
Witoco Venture Corporation ("Witoco"), a stockholder of CHI loaned SES
$0.5 million in December 1991 and received a non-recourse note and attached
warrants in connection with the development of the Summit project. Michael
Walkup, President of Witoco, is also a member of CHI's Board of Directors.
The Company believes that all of the foregoing transactions are on
terms that are no less favorable to the Company than could have been obtained
from an unaffiliated third party in a similar transaction.
-91-
<PAGE>
PART IV
Item 14. Exhibits, Financial Statements Schedules and Page
Reports of Form 8-K
(a) 1. Financial Statements
Report of Independent Accountants 44
Consolidated Statements of Operations for the
three years ended June 30, 1996 45
Consolidated Balance Sheet at June 30, 1996 and 1995 46
Consolidated Statement of Stockholders' Equity for the
three years ended June 30, 1996 47
Consolidated Statement of Cash Flows for the three
years ended June 30, 1996 48-49
Notes to Consolidated Financial Statements 50-70
(a) 2. Financial Statement Schedules
All financial statement schedules are omitted because they are not
applicable or the required information is shown in the financial statements or
notes thereto.
Individual financial statements of the Registrant have been omitted
because consolidated financial statements of the Registrant and all its
subsidiaries are furnished.
(a) 3. Exhibits
Exhibit No. Description
+3.1 Restated Certificate of Incorporation and amendment thereto and
Bylaws, as amended, of Consolidated Hydro, Inc.
+3.2 Certificate of Designation of 13-1/2% Cumulative Redeemable
Exchangeable Preferred Stock, Series H, par value $0.01 per share, of
Consolidated Hydro, Inc.
+3.3 Certificate of Incorporation and Bylaws of Summit Energy Storage Inc.
+10.1 Power Purchase Agreement between Boott Hydropower, Inc. and
Commonwealth Electric Company, dated January 10, 1983 and amendment
dated March 6, 1985
+10.2 Participation Agreement dated as of December 1, 1985 among Boott
Hydropower, Inc., General Electric Credit Corporation, Corporation
Investments, Inc. and United States Trust Company of New York, as
Owner Trustee and amendment thereto dated as of February 26, 1988
+10.3 Lease Agreement dated as of December 1, 1985 between United States
Trust Company of New York, as Owner Trustee, and Boott Hydropower,
Inc. and amendments thereto dated as of December 12, 1986 and February
26, 1988
+10.4 Power Purchase Agreement between Lawrence Hydroelectric Associates,
Essex Company and New England Power Company (Lawrence Project,) dated
January 1, 1985
+10.5 Mortgage and Security Agreement from Lawrence Hydroelectric Associates
to New England Power Company, dated January 1, 1985
+10.6 Indenture of Mortgage, dated as of September 8, 1981, between Lawrence
Hydroelectric Associates and State Street Bank and Trust Company,
Trustee, and Supplemental Indentures dated as of January 1, 1985,
October 1, 1987 and July 1, 1988
-92-
<PAGE>
+10.7 Agreement between International Paper Company and Niagara Mohawk Power
Corporation (LaChute Lower Project), dated March 7, 1986
+10.8 Agreement between International Paper Company and Niagara Mohawk Power
Corporation (LaChute Upper Project), dated March 7, 1986
+10.9 Participation Agreement dated as of December 31, 1987 among LaChute
Hydro Company, Inc., Philip Morris Credit corporation, the Financial
Institutions listed on Schedule II thereto, The Connecticut Bank and
Trust Company, National Association, as Indenture Trustee, and The
Connecticut National Bank, as Owner Trustee
+10.10 Lease Agreement dated as of December 31, 1987 between LaChute Hydro
Company, Inc. and The Connecticut National Bank, as Owner Trustee
+10.11 Indenture and Amended and Restated Building Loan Mortgage and Security
Agreement dated as of December 31, 1987 between The Connecticut
National Bank, as Owner Trustee and The Connecticut Bank and Trust
Company, National Association, as Indenture Trustee
+10.12 Tax Indemnification Agreement dated as of December 31, 1987 between
LaChute Hydro Company, Inc. and Philip Morris Credit Corporation
+10.13 Tax Indemnification Agreement dated as of December 31, 1987 between
LaChute Hydro Company, Inc. and General Electric Capital Corporation
+10.14 Power Purchase Agreement between Androscoggin Reservoir Company and
Central Maine Power Company (Aziscohos Project), dated October 23,
1984
+10.15 Participation Agreement dated as of September 1, 1988 among Aziscohos
Hydro Company, Inc., NYNEX Credit Company, The CIT Group/Equipment
Financing, Inc., The Connecticut National Bank, as Indenture Trustee,
and Meridian Trust Company, as Owner Trustee
+10.16 Lease Agreement dated as of September 1, 1988 between Meridian Trust
Company, as Owner Trustee, and Aziscohos Hydro Company, Inc.
+10.17 Indenture, Mortgage and Security Agreement dated as of September 1,
1988 between Meridian Trust Company, as Owner Trustee and The
Connecticut National Bank, as Indenture Trustee
+10.18 Indenture of Lease dated as of January 15, 1986 between Aziscohos
Hydro Company, Inc. and Androscoggin Reservoir Company, and amendments
thereto dated March 13, 1986 and as of September 1, 1988
+10.19 Collateral Assignment of Lease dated September 1, 1988 between
Aziscohos Hydro Company, Inc. and Central Maine Power Company
+10.20 Tax Indemnification Agreement dated as of September 6, 1988 between
Aziscohos Hydro Company, Inc., Consolidated Hydro, Inc. and NYNEX
Credit Company
+10.21 Purchase Power Agreement dated December 29, 1987, between Duke Power
Company and Riegel Power Corporation as assigned to Aquenergy Systems,
Inc. by Assignment dated July 27, 1988
+10.22 Note Purchase Agreement between UNUM Life Insurance Company of America
and Aquenergy Systems, Inc. dated as of November 1, 1988
+10.22A Mortgage and Security Agreement dated as of November 1, 1988 from
Aquenergy Systems, Inc. to The Connecticut Bank and Trust Company,
National Association, as Trustee (Ware Shoals Project)
-93-
<PAGE>
+10.23 Loan Agreement dated June 18, 1991, between Fieldcrest Cannon, Inc. as
lender and Eagle & Phenix Hydro Company, Inc. as borrower setting
forth terms and conditions for the loan evidenced by the Promissory
Note described in item A above
+10.24 Security Deed dated June 18, 1991 from Eagle & Phenix Hydro Company,
Inc. to Fieldcrest Cannon, Inc. as security for the Promissory Note
described item A above
+10.25 Security Agreement dated June 18, 1991, between Eagle & Phenix Hydro
Company, Inc. as grantor and Fieldcrest Cannon Inc. as secured party
as security for the Promissory Note described in item A above
+10.26 Lease agreement dated January 18, 1991, between Eagle & Phenix Hydro
Company, Inc. as lessor and Fieldcrest Cannon, Inc. as lessee
+10.27 Agreement for the sale of electricity to Virginia Electric & Power
Company dated July 29, 1988, between Virginia Electric & Power Company
and Aquenergy Systems, Inc.
+10.28 Deed of Trust and Security Agreement dated as of November 1, 1988 from
Aquenergy Systems, Inc. to The Connecticut Bank and Trust Company,
National Association, as Trustee (Fries Project)
+10.29A Purchase Power Agreement between Duke Power Company and Pelzer Hydro
Company, Inc. dated February 15, 1991 (Upper Pelzer)
+10.29B Purchase Power Agreement between Duke Power Company and Pelzer Hydro
Company, Inc. dated February 15, 1991 (Lower Pelzer)
+10.30 Second Amended and Restated Certificate and Agreement of Limited
Partnership of Catalyst Slate Creek Hydroelectric Partnership, dated
as of July 18, 1989 and Amendment No. 1. dated as of May 9, 1990
thereto
+10.31 Restated and Amended Power Purchase Agreement between Catalyst Slate
Creek Hydroelectric Partnership and PacifiCorp, dba Pacific Power &
Light Company and Utah Power & Light Company, dated May 8, 1990
+10.32 Lease Agreement dated September 9, 1986, between Wallowa Hydro
Associates, Ltd. as lessee and Roy & Wilfred Daggett as lessors as
amended on April 13, 1988, as assigned to Joseph Hydro Company, Inc.
by Assignment and Assumption of Leases dated July 31, 1991
+10.33 Lease Agreement dated September 9, 1986, between Wallowa Hydro
Associates, Ltd. as lessee and Rex W. and Zela G. Ziegler as lessors
as amended on April 13, 1988, as assigned to Joseph Hydro Company,
Inc. by Assignment and Assumption of Leases dated July 31, 1991
+10.34 Lease Agreement dated August 8, 1986 between Wallow Hydro Associates,
Ltd. as lessee and Dale L. Potter as lessor, as assigned to Joseph
Hydro Company, Inc. by Assignment and Assumption of Leases dated July
31, 1991
+10.35 Amended and Restated Power Purchase Agreement dated July 31, 1991,
between Joseph Hydro Company, Inc. and PacifiCorp Electric Operations
+10.36 Agreement between Wallowa Valley Improvement District No. 1 and Cook
Electric, Inc. dated January 6, 1981, as amended on February 2, 1982,
December 13, 1982, December 27, 1982, September 13, 1983, and July 31,
1991, as assigned to Joseph Hydro Company, Inc. by Assignment and
Consent Agreement dated July 31, 1991
-94-
<PAGE>
+10.37 Agreement between Joseph Hydro Associates, Ltd. and the Little Sheep
Creek Property Owners Association as assigned to Joseph Hydro Company
Inc. by Assignment and Assumption of Contracts dated July 31, 1991
+10.38 American Arbitration Association Order No. 75 110 0110 85 dated
September 16, 1983, as assigned to Joseph Hydro Company, Inc. by
Assignment and Assumption of Contracts dated July 31, 1991
+10.39 Contract between the Connecticut Light and Power Company and
Kinneytown Hydro Company, Inc. (Kinneytown Project) dated December 2,
1986
+10.40 Open-End Electricity Purchase Agreement Mortgage and Security
Agreement between Kinneytown Hydro Company, Inc. and the Connecticut
Light and Power Company dated April 29, 1988
+10.41 Amended and Restated Agreement of Limited Partnership, dated as of
December 22, 1989, of Twin Falls Hydro Associates, L.P.
+10.42 Tax Indemnification Agreement, dated as of December 22, 1989, between
The Connecticut National Bank, as LP Trustee, and CHI Acquisitions,
Inc. (Exhibit G to item 10.41)
+10.43 Agreement between New York State Electric & Gas Corporation and Walden
Power Corporation dated as of August 2, 1982
+10.44 Lease between Barbara Gurman Lewis and Walden Power Corporation dated
as of August 24, 1982
+10.45 Lease between the Village of Walden and Walden Power Corporation dated
as of August 5, 1982
+10.46 Contract between the Connecticut Light and Power Company and Summit
Hydropower (Willimantic Project) dated December 24, 1987
+10.47 Open-End Electricity Purchase Agreements, Leasehold Mortgage and
Security Agreement between Willimantic Power Corporation and the
Connecticut Light and Power Company dated as of October 4, 1988
+10.48 Stock Subscription Agreement dated as of March 30, 1988 among
Consolidated Hydro, Inc., Summit Energy Storage Inc., Acres
International Corporation, Commonwealth Securities and Investments,
Inc. and seven individuals
+10.49 Memorandum of Understanding between Kvaerner Brug A/S, Boving & Co.,
Limited, EB Kraftgenerering a.s. (Powergeneration), and Consolidated
Hydro, Inc., dated April 12, 1988
+10.50 Agreement between Kvaerner Brug A/S, Boving & Co., Limited, EB
Kraftgenerering a.s. (Power generation), Summit Energy Storage Inc.,
dated April 12, 1988
+10.51 Agreement between Kvaerner Brug A/S, Boving & Co., Limited, EB
Kraftgenerering a.s. (Power generation), Consolidated Hydro Inc.,
Summit Energy Storage Inc., dated April 12, 1988
+10.52 Agreement for Energy Services for Summit Energy Storage Project
between Summit Energy Storage Inc. and Acres International Corporation
dated March 30, 1988
+10.53 Letter Agreement dated March 30, 1988 between Summit Energy Storage
Inc. and Acres International Corporation
+10.54 Mitigation Agreement between Summit Energy Storage Inc. and the City
of Norton, Ohio dated May 14, 1990
-95-
<PAGE>
+10.55 Memorandum of Understanding concerning commitment to lease between
Summit Energy Storage Inc. and Ohio Edison Company, dated October 8,
1991
+10.56 Agreement concerning specified facility transmission and dispatching
service between Summit Energy Storage Inc. and Ohio Edison Company,
dated October 8, 1991
+10.56A Technical Services Agreement dated June 5, 1992 between Summit Energy
Storage Inc. and Morrison Knudsen Corporation
+10.56B Promissory notes dated March 19, 1990 (a) in the principal amount of
$658,500 from Summit Energy Storage Inc. to EB Kraftgenerering a.s.
and (b) in the principal amount of $341,500 from Summit Energy Storage
Inc. to Kvaerner Hydro Power A/S
+10.57 Promissory note dated May 30, 1991 in the principal amount of $110,000
from Summit Energy Storage Inc. EB Kraftgenerering a.s.
(Powergeneration)
+10.58 Promissory note dated November 26, 1991 in the principal amount
$500,000 from Summit Energy Storage Inc. to Witoco Venture Corporation
+10.59 Promissory note dated October 31, 1991 in the principal amount of
$277,778 from Summit Energy Storage Inc. to Andrea Rich, in her
capacity as Trustee of the Howard Rich Trust for the benefit of Daniel
Rich
+10.60 Promissory note dated October 31, 1991 in the principal amount of
$222,222 from Summit Energy Storage Inc. to Andrea Rich, in her
capacity as Trustee of the Howard Rich Trust for the benefit of Joseph
Rich
+10.61A Letter agreements between Summit Energy Storage Inc. and Curtis
Thaxter Stevens Broder & Micoleau dated June 15, 1988, August 29, 1990
and June 21, 1991
+10.61B Kidder, Peabody & Co., Incorporated Fee Letter, dated September 5,
1989
+10.62 Letter Agreement dated September 26, 1989 between Consolidated Pumped
Storage, Inc. and JDJ Energy Company, Inc.
+10.63 Conveyance, Pledge, Security and Shareholders Agreement dated as of
September 15, 1990 among Consolidated Pumped Storage Arkansas, Inc.,
Consolidated Pumped Storage, Inc. and JDJ Energy Company, Inc.
+10.64 Loan Agreement and Supply Commitment dated as of September 28, 1990
among Consolidated Pumped Storage Arkansas, Inc., Consolidated Pumped
Storage, Inc. and Voith Hydro, Inc.
+10.65 Loan Agreement and Supply Commitment dated as of December 18, 1991
among Consolidated Pumped Storage Arkansas, Inc., Consolidated Pumped
Storage, Inc. and Siemens Power Ventures, Inc.
+10.66A Warrant to purchase up to 10 shares of common stock of Consolidated
Pumped Storage, Inc. issued to Andrea Rich
+10.66B Securities Purchase Agreement between Consolidated Hydro, Inc., and
BCC Brown Finance (Curacao) N.V., dated June 29, 1992
+10.67 Employment Agreement between Consolidated Hydro, Inc. and Olof S.
Nelson dated March 25, 1992
-96-
<PAGE>
+10.68 Employment Agreement between Consolidated Hydro, Inc. and Michael I.
Storch dated March 25, 1992
+10.69 Employment Agreement between Consolidated Hydro, Inc. and Carol H.
Cunningham dated March 25, 1992
+10.70A Side letter with Carol H. Cunningham dated March 25, 1992
+10.70B Incentive Compensation and Transition Employment Agreement for the
Eagle and Phenix projects, dated December 18, 1992
*10.70C Put and Call Letter Agreement dated June 30, 1993 between Consolidated
Hydro, Inc. and Carol H. Cunningham (Exhibit 10.70C to 1994 10-K)
+10.71 Stockholders, Optionholders and Warrantholders Agreement among
Consolidated Hydro, Inc. and its stockholders, optionholders and
warrantholders dated March 25, 1992
+10.72 Purchase Agreement dated March 25, 1992 among Consolidated Hydro,
Inc., Madison Group, L.P., and The Morgan Stanley Leveraged Equity
Fund II, L.P.
+10.73 Amended and Restated Acquisition Facility Agreement between
Consolidated Hydro, Inc. and General Electric Capital Corporation
dated March 25, 1992
+10.74 Note Pledge and Security Agreement between General Electric Capital
Corporation and CHI Acquisitions, Inc., dated June 22, 1993
+10.75 Amendment and Agreement among General Electric Capital Corporation,
and its subsidiaries, dated June 22, 1993
+10.76 Reimbursement Agreement between CHI Acquisitions, Inc., Consolidated
Hydro Southeast, Inc., Joseph Hydro Company, Inc., and General
Electric Capital Corporation, dated June 22, 1993
+10.77 Kidder, Peabody & Co. Letter Agreement, dated July 19, 1991
+10.78 Participation Agreement dated September 9, 1993 among CHI
Acquisitions, Inc., Sheldon Springs Power Company, Sheldon Vermont
Hydro Company, Inc., GECC and Aircraft Services Corporation
+10.79 Agreement of Limited Partnership of Sheldon Springs Hydro Associates,
L.P. dated September 9, 1993
+10.80 Loan Agreement dated September 10, 1993 among Missisquoi Associates,
Sheldon Springs Hydro Associates, L.P. and GECC
*10.80.1 Amended and Restated Joint Venture Agreement of Missisquoi Associates
dated as of September 10, 1993 (Exhibit 10.94 to 1994 10-K)
*10.80.2 Mortgage from Missisquoi Associates to General Electric Capital
Corporation, as agent, dated September 10, 1993 (Exhibit 10.96 to 1994
10-K)
+10.81 Long-Term, Firm Levelized and Non-Levelized Purchase Agreement,
executed on July 23, 1986, between Vermont Power Exchange, Inc. and
Missisquoi Associates
+10.82 Revolving Credit Agreement among Consolidated Hydro, Inc., as the
Borrower, the Banks Listed in Schedule I and Den norske Bank AS, as
Agent, dated as of October 14, 1993
-97-
<PAGE>
+10.83 Warrant Agreement dated as of November 1, 1993, between Consolidated
Hydro, Inc. and SES Partners II, L.P.
*10.83.1 Call Agreement, dated November 1, 1993, by and among Consolidated
Hydro, Inc., SES Partners II, L.P. and Summit Energy Storage, Inc.
(Exhibit 10.90 to 1994 10-K)
*10.83.2 Option Agreement dated November 1, 1993, between Consolidated Hydro,
Inc. and ACRES Corporation (Exhibit 10.91 to 1994 10-K)
+10.84 Stock Option Plan
+10.85 Form of Stock Option Agreement
+10.86 Form of Indemnification Agreement
+10.87 Form of Amended and Restated Indenture for the Notes between
Consolidated Hydro, Inc. and Shawmut Bank Connecticut, National
Association, as trustee (Exhibit 4.3 to Form S-1)
+10.88 Form of Exchange Debenture Indenture (including form of debenture)
(Exhibit 4.5 to Form S-1)
+10.89 Registration Rights Agreement, dated June 15, 1993, between
Consolidated Hydro, Inc. and Morgan Stanley (Exhibit 4.6 to Form S-1)
**10.90 Credit and Reimbursement Agreement dated as of February 15, 1995 among
CHI Acquisitions II, Inc., Hydro Development Group Inc., Beaver Valley
Power Company, Littleville Power Company, Inc., Consolidated Hydro
Southeast, Inc., Pelzer Hydro Company, Inc., Joseph Hydro Company,
Inc., Slate Creek Hydro Company, Inc., CHI Acquisitions, Inc., the
Lenders from time to time party thereto, and General Electric Capital
Corporation, as Agent for the Lenders.
**10.91 Deed of Trust, Assignment of rents and Fixture Filing dated as of May
10, 1990 between Slate Creek Hydro Associates, L.P. (f/k/a Catalyst
Slate Creek Hydroelectric Partnership), in favor of First American
Title Insurance Company, trustee, f/b/o General Electric Capital Corp.
("GECC"), recorded in Book 2595, Page 805, as assigned by GECC to CHI
Acquisitions, Inc. by Assignment of Beneficial Interest Under Deed of
Trust, dated February 15, 1995, recorded in Book 3260, Page 629, as
amended by Modification of Deed of Trust, dated February 15, 1995,
recorded in Book 3260, Page 635, as further assigned by CHI
Acquisitions, Inc. to Slate Creek Hydro Company, Inc., by Assignment
of Deed of Trust dated February 15, 1995, recorded in book 3260, Page
647, and as further assigned by CHI Acquisitions, Inc. to GECC by
Assignment of Beneficial Interest Under Deed of Trust dated February
15, 1995 and recorded in Book 3260, Page 651.
**10.92 Mortgage from Pelzer Hydro Company, Inc. to General Electric Capital
Corporation, dated as of February 15, 1995.
**10.93 Power Purchase Agreement by and between Niagara Mohawk Power
Corporation and Pyrites Associates, dated as of April 22, 1985, as
amended by First Amendment dated as of March 22, 1993.
**10.94 Lease Agreement between Pyrites Associates (lessee) and St. Lawrence
County Industrial Development Agency, dated June 1, 1985 and recorded
in Book 992, Page 742, as amended by First Amendment dated June 3,
1993 and recorded in book 1072, Page 921.
**10.95 Pyrites Project Agreement dated November 18, 1982 between Hydro
Development Group Inc. and Hydra-Co Enterprises, Inc.
**10.96 Cataldo Hydro Power Associates Partnership Agreement dated October 12,
1983.
-98-
<PAGE>
**10.97 Agreement of Limited Partnership of Black River Hydro Associates,
dated as of November 23, 1983, as amended by First Amendment dated as
of October 14, 1984 and undated, unexecuted Second Amendment.
**10.98 Amended and Restated Power Purchase Agreement - Port Leyden Plant by
and between Black River Hydro Associates and Niagara Mohawk Power
Corporation, dated as of October 15, 1984, as amended by amendments
dated October 15, 1984 and June 18, 1993, respectively.
**10.99 Lease by and between Lewis County Industrial Development Agency
(Lessor) and Black River Hydro Associates (Lessee), dated 02/01/85 and
recorded in Liber 454 of Deeds, Page 191, as amended by amendments
dated 04/01/86, 05/26/88 and 07/07/93, respectively, the latter being
recorded in Liber 565 of Deeds, Page 51.
**10.100 Indenture of Trust, Mortgage and Assignment given by Lewis County
Industrial Development Agency to Chase Manhattan Bank, N.A., dated
02/01/85, as supplemented by instruments dated 04/01/86, 10/31/91 and
07/07/93, the latter being recorded in Liber 393 of Mortgages, Page
165.
**10.101 Power Purchase Agreement by and between Hydro Development Group Inc.
and Niagara Mohawk Power Corporation, dated December 16, 1993 (Dexter,
Copenhagen and other Projects).
**10.102 Mortgage Restatement Agreement between Hydro Development Group Inc.
and General Electric Capital Corporation dated February 15, 1995 and
recorded in the Jefferson County Clerk's Office in Liber 1362, Page
033.
**10.103 Project Agreement by and between Hydro Development Group, Inc. and
Hydra-Co Enterprises, Inc., dated November 18, 1982.
**10.104 Agreement by and between Hydro Development Group, Inc., and Hydra-Co
Enterprises, Inc. dated as of May 23, 1994.
**10.105 Employment Agreement between Consolidated Hydro, Inc. and Edward M.
Stern dated November 1, 1994.
10.106 Termination Agreement between Consolidated Hydro, Inc. and Olof S.
Nelson dated June 27, 1996.
10.107 Employment Agreement between Consolidated Hydro, Inc. and James T.
Stewart dated July 1, 1996.
12.1 Statements regarding computation of ratios
**21.1 List of Subsidiaries of Registrant
+ Incorporated by reference to the similarly-numbered (or, as indicated,
a differently-numbered) exhibit to the Company's Registration
Statement on Form S-1 (File No. 33-69762) (the "Form S-1").
* Incorporated by reference to the indicated exhibit to the Company's
Annual Report on Form 10-K for the fiscal year ended June 30, 1994
(the "1994 10-K")
** Incorporated by reference to the similarly-numbered exhibit to the
Company's Annual Report on Form 10- K for the fiscal year ended June
30, 1995 (the "1995 10-K")
(b) Reports on Form 8-K: None
-99-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, this Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CONSOLIDATED HYDRO, INC.
(Registrant)
Date: September 30, 1996 By: /s/ James T. Stewart
--------------------------
James T. Stewart
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been duly signed below by the following persons on behalf of the Registrant
and in the capacities and on the date set forth above.
Signature Title Date
by:
/s/James T. Stewart
- ----------------------------
James T. Stewart Chairman and Chief
Executive Officer September 30, 1996
by:
/s/ Edward M. Stern
- ----------------------------
Edward M. Stern President, Chief
Operating Officer and
Secretary
(principal financial
officer) September 30, 1996
by:
/s/ Patrick J. Danna
- -----------------------------
Patrick J. Danna Vice President,
Treasurer and Controller
(principal accounting
officer) September 30, 1996
by:
/s/ Frode Botnevik
- ----------------------------
Frode Botnevik Director September 30, 1996
by:
/s/ Charles J. Micoleau
- --------------------------------
Charles J. Micoleau Director September 30, 1996
by:
/s/ David R. Ramsay
- --------------------------------
David R. Ramsay Director September 30, 1996
by:
/s/ Frank V. Sica
- -------------------------------
Frank V. Sica Director September 30, 1996
by:
/s/ Michael H. Walkup
- ------------------------------
Michael H. Walkup Director September 30, 1996
-100-
<PAGE>
Exhibit 12.1
CONSOLIDATED HYDRO, INC.
STATEMENT REGARDING COMPUTATIONS OF DEFICIENCY
OF EARNINGS TO FIXED CHARGES AND
OF DEFICIENCY OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(in thousands)
<TABLE>
<CAPTION>
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Loss before provision for income taxes, extraordinary
items and cumulative effect of accounting changes $(36,404) $(8,190) $(14,126) $(15,899) $(95,712)
Add: Interest expense 16,056 13,868 18,980 21,778 26,876
Amortization of debt 514 237 451 448 448
Imputed interest - operating lease (a) $ 1,860 $ 1,785 $ 1,705 $ 1,621 $ 1,533
-------- -------- -------- ------- --------
Total earnings/loss $(17,974) $ 7,700 $ 7,010 $ 7,948 $(66,855)
======== ======== ======== ======= ========
Fixed charges:
Interest expense $ 16,056 $13,368 $ 18,980 $ 21,778 $ 26,876
Capitalized interest 402 553 2,303 2,951 1,705
Amortization of debt 514 237 451 448 448
Imputed interest - operating lease (a) $ 1,860 $ 1,785 $ 1,705 $ 1,621 $ 1,533
-------- -------- -------- ------- --------
$ 18,832 $16,443 $ 23,439 $ 26,798 $ 30,562
======== ======== ======== ======== ========
Deficiency of earnings to fixed charges $ 36,806 $ 8,743 $ 16,429 $ 18,850 $ 97,417
======== ======== ======== ======== ========
Preferred dividend requirement $ 8,123 $18,229 $ 20,687 $ 22,108 $ 23,732
======== ======== ======== ======== ========
Deficiency of earnings to fixed charges and preferred
stock dividends $ 44,929 $26,972 $ 37,116 $ 40,958 $121,149
======== ======== ======== ======== ========
</TABLE>
(a) The percent of rent included above represents a reasonable
approximation of the interest factor.
-102-
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1996
<PERIOD-END> JUN-30-1996
<CASH> 23,834
<SECURITIES> 0
<RECEIVABLES> 7,854
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 33,041
<PP&E> 147,263
<DEPRECIATION> (21,130)
<TOTAL-ASSETS> 244,657
<CURRENT-LIABILITIES> 16,958
<BONDS> 266,620
98,604
98,712
<COMMON> 2
<OTHER-SE> (267,341)
<TOTAL-LIABILITY-AND-EQUITY> 244,657
<SALES> 0
<TOTAL-REVENUES> 55,382
<CGS> 0
<TOTAL-COSTS> 120,935
<OTHER-EXPENSES> 6,746
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 26,876
<INCOME-PRETAX> (95,712)
<INCOME-TAX> 7,381
<INCOME-CONTINUING> (88,331)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (88,331)
<EPS-PRIMARY> (87.45)
<EPS-DILUTED> 0
</TABLE>
