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
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
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.
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:
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.
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:
(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.
(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
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
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.
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.
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
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
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
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
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.
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
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.
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
(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
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.
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
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.
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.
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.
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.
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.
Item 6.
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":
(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:
Item 7.
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
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.
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
Continued
(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)
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(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.
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.
Power Generation Revenues (1)
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
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
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.
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".
Item 8.
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
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)
The accompanying notes are an integral part of the consolidated financial statements.
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.
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)
The accompanying notes are an integral part of the consolidated financial statements.
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)
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)
The accompanying notes are an integral part of the consolidated financial statements.
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.
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.
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
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.
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.
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.
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.
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 ================ =============
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:
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 ======= =======
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.
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
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
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
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 ======= =======
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
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
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.
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.
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.
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.
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
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.
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.
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) ------- -------
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
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
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.
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
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.
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.
Item 9
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10.
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
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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.
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
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(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.
(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.
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
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(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
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(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.
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
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.
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.
Item 12.
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.
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".
Item 13.
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
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
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.
PART IV
Item 14.
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
+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,
+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)
+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
+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,
+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
+10.55 Memorandum of Understanding concerning commitment to lease between Summit Energy Storage Inc. and Ohio Edison Company, dated October 8,
+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,
+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
+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
+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.
**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
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