ITEM 1. BUSINESS
INTRODUCTION
Cogentrix Energy, Inc., through its direct and indirect subsidiaries (the "Company") is principally engaged in the business of acquiring, developing, owning and operating independent (i.e., non-utility) electric power generation facilities and selling electricity and steam in the United States and selected international markets. The Company was one of the early participants in the market for independently generated electric power which developed in the United States as a result of the enactment of the Public Utility Regulatory Policies Act ("PURPA"). The Company currently has interests in eleven power generation facilities having an aggregate generating capacity of 1,120 megawatts. In March 1998, the Company acquired ownership interests in two separate 245 megawatt gas-fired power generation facilities in the Midwestern United States. In addition, the Company has a pending acquisition, subject to the fulfillment of all required conditions, of ownership interests in twelve domestic power generation facilities with an aggregate generating capacity of approximately 2,400 megawatts and a natural gas pipeline. Since its inception in 1983, the Company has capitalized on its expertise in engineering, construction management, operations, fuel management and financing capabilities to successfully expand its operations. Based on net ownership of total megawatts in operation, the Company is among the larger independent power producers in the United States.
Unless the context requires otherwise, references herein to the "Company" mean Cogentrix Energy, Inc. and its direct and indirect subsidiaries. The former parent company, Cogentrix, Inc., which as the result of a restructuring completed in December 1993 is now one of the Company's principal subsidiaries, is referred to herein as "Cogentrix." The Company's subsidiaries engaged in the development, ownership or operation of cogeneration facilities are sometimes referred to individually as a "project subsidiary" and collectively as the Company's "project subsidiaries."
POWER MARKET OUTLOOK
The restructuring of the electric market worldwide has created a trend away from government-owned electric generation toward a deregulated, competitive market, both domestically and internationally. In response to increasing customer demand for access to low cost electricity and enhanced services, new regulatory initiatives are currently being adopted or considered at both state and federal levels to increase competition in the domestic power generation industry. The Company believes that industry trends and such regulatory initiatives will lead to the transformation of the existing regulated market which sells to a captive customer base to a more competitive market in which end users may purchase electricity from a variety of suppliers including non-utility generators, power marketers, public utilities and others. Management believes that these market trends will create significant new business opportunities for companies like Cogentrix Energy, Inc. that have demonstrated the ability to construct and operate efficient, low cost power generation facilities.
Management also believes that these market trends and changes in the electric market will result in a disposition of power generation facilities by utilities, independent power producers and industrial companies. This trend will create investment opportunities for companies such as Cogentrix Energy, Inc. that have integrated power services capabilities.
The passage of the Energy Policy Act of 1992 (the "Energy Policy Act") significantly expanded the options available to independent power producers, particularly with respect to siting a generating facility. Among other things, it enables independent power producers to obtain an order from the Federal Energy Regulatory Commission ("FERC") requiring an intermediary utility to give access to its transmission lines to transmit, or wheel, electric power from a project to its utility purchaser. The availability of wholesale transmission wheeling could be an important aspect in the development of new projects. For example, the Company may be able to develop a project in one utility's service territory and wheel the electric power produced by the project through the transmission lines of such utility to a second utility or another wholesale purchaser. The Energy Policy Act also created a new class of generator, Exempt Wholesale Generator ("EWGs"), that, unlike Qualified Facilities ("QFs"), are not required to use alternative or renewable fuels or to have useful thermal energy output. See "Regulation -- Energy Regulations" herein.
The Company believes that knowledge gained from developing and operating power plants in the United States can be applied to take advantage of selective opportunities in international markets. In order to satisfy an increase in electric demand, many countries have adopted active government programs designed to encourage private investment in power generation facilities. To this end, the Company is actively exploring development of projects outside of the United States, principally in Asia and Latin America.
PROJECT DEVELOPMENT STRATEGY
The Company intends to remain among the leaders in the independent power industry by developing and constructing or acquiring electric power generation facilities (or interests therein) in the United States and in selected foreign countries where the political climate is conducive to increased foreign investment. The Company's overall goal in pursuing this strategy is to capitalize on its reputation as an efficient and reliable energy provider.
The Company's overall project development strategy is to concentrate on those segments of the market for independent power, in both the domestic and international sectors, requiring smaller generating facilities, ranging from 60 to 240 megawatts primarily using natural gas as fuel.
In developing future projects, the Company anticipates that it will increasingly participate on a joint venture basis with various partners, including non-regulated subsidiaries of electric utilities, other independent power producers, financial institutions, equipment manufacturers, large construction companies and fuel suppliers. Through such joint venture relationships, the Company expects to gain a number of advantages, including technical expertise possessed by others, enhanced knowledge of and experience with the political and social conditions of the region or country where the project is being developed and the ability to leverage the joint venture partner's human and financial resources. The Company also expects such joint ventures will enable it to share the risks associated with development of projects and build a larger and more diversified portfolio of projects. The Company anticipates that it will share control over the development and construction of such projects with its joint venture partners and will seek to operate the facilities whenever possible.
The Company has identified three market segments in which it intends to focus its future development activities. These targeted market segments are acquisitions of domestic generating assets, domestic and foreign industrial companies and greenfield project development.
ACQUISITIONS OF DOMESTIC GENERATING ASSETS. In pursuing its growth strategy, the Company intends to focus on opportunities where it is able to capitalize on its management and technical expertise to identify acquisition opportunities of domestic generating assets. In pursuing these acquisition opportunities, the Company seeks to target facilities which have power sales contracts with electric utilities or customers with significant credit strength as well as facilities that are highly efficient, low cost energy providers that can take advantage of opportunities in a deregulated energy market. By pursuing this acquisition strategy, the Company has already significantly expanded and diversified its project portfolio. In 1998, the Company has signed agreements related to acquisitions involving various ownership interests in 14 domestic generating facilities. As a result of these transactions, the Company will nearly double its net ownership power generation capacity and substantially diversify its technology and fuel mix.
DOMESTIC AND FOREIGN INDUSTRIAL COMPANIES. With opportunities for development in the electric utility market diminishing, the Company is increasing its focus on the industrial market for new domestic as well as selected international project development opportunities. Management believes that establishing relationships with large United States multinational industrial corporations will also help to serve as an indirect route to the development of projects in the international market.
Many of these industrial companies, both domestic and international, are currently operating their own "inside the fence" cogeneration facilities to produce both electricity and thermal energy, which employ older technology, produce energy inefficiently and generally are managed as an adjunct to the industrial companies' primary manufacturing objectives. The cost of their energy supply is a major component of these industrial companies' costs. The Clean Air Act amendments of 1990 also present challenges for many industrial companies which must retrofit existing facilities to comply with the new law. The Company believes that smaller cogeneration facilities with state of the art technology could readily be employed to replace, or in certain circumstances, upgrade existing inside the fence cogeneration facilities.
Most state regulatory authorities have not yet resolved the issue of whether an independent power producer may lawfully sell power directly to one or more retail customers, and, if so, whether such producer becomes subject to regulation as a public utility. Even if regulatory authorities permit the Company and others to develop such facilities for the retail sale of electricity, electric utilities may decide to mount legal challenges to such developments. To avoid such regulatory and legal challenges, the Company may structure the ownership of projects such that the industrial corporation retains a controlling interest in the project or may use acceptable alternative structures.
GREENFIELD PROJECT DEVELOPMENT. The Company intends to pursue domestic development of highly efficient, low cost power generating facilities. In developing these opportunities, the Company will hedge its exposure to electric market price risk by entering into arrangements with utilities, fuel suppliers and/or power markets.
The Company believes that the knowledge and experience that it has gained in developing and operating facilities in the United States can be effectively employed in selected situations to develop projects outside the United States. In pursuing selected international development projects, the Company intends to focus primarily on the segment of the international market for generating facilities in the 60 to 240 megawatt range. By concentrating on the development of smaller facilities, the Company believes that it can successfully export its proven core business while making relatively smaller equity investments in international projects. The Company intends to pursue selected opportunities in Asia and Latin America, where demand for power is rapidly growing and private investment is encouraged.
ACQUISITIONS OF LS POWER AND BECHTEL ASSETS
In March 1998, the Company acquired from LS Power Corporation an approximate 74% ownership interest in two independent power plants in Whitewater, Wisconsin (the "Whitewater Facility") and Cottage Grove, Minnesota (the "Cottage Grove Facility"). Each of the Cottage Grove and Whitewater Facilities is a 245 megawatt gas-fired, combined-cycle cogeneration facility. The Cottage Grove Facility sells capacity and energy to Northern States Power Company under a 30-year power sales contract terminating in 2027. The Whitewater Facility sells capacity and energy to Wisconsin Electric Power Company under a 25-year power sales contract terminating in 2022. Commercial operations of the facilities commenced in the last half of calendar 1997.
In March 1998, the Company signed an agreement with Bechtel Generating Company, Inc. ("Bechtel") to acquire Bechtel's ownership interest in twelve electric generating facilities and one interstate natural gas pipeline in the United States. The acquisition of these facilities will provide the Company with a net equity interest of approximately 360 megawatts in a diverse generating portfolio that comprises approximately 2,400 megawatts in total plant capacity. These facilities are located in New Jersey, New York, Pennsylvania, West Virginia, Massachusetts and Florida. Nine of the generating facilities were developed and are managed by U.S. Generating Company, an indirect, wholly-owned subsidiary of PG&E Corporation, and are owned in part by affiliates of U.S. Generating Company.
For further discussion of the acquisitions see "Management's Discussion and Analysis of Financial Condition and Results of Operations."
PROJECTS UNDER DEVELOPMENT
In May 1993, the Government of India ("GOI") approved in principle, subject to certain conditions, the Company's proposal to develop a coal-fired power generation facility with a total gross electrical generating capacity of approximately 1,000 megawatts. The project was designated by the GOI as one of eight projects under development which would receive the support of a partial guaranty by the GOI of the payment obligations of the related State Government. The proposed site for the facility near Mangalore in the State of Karnataka has already received in-principle clearance related to the environmental permitting process. The Company has executed a power sales agreement with the Karnataka State Electricity Board and has executed the Government of Karnataka guaranty of the full financial obligation of the Karnataka State Electricity Board and the State Support Agreement which commits the State of Karnataka to facilitate required government actions. The Company is currently negotiating with the GOI on revision to the power sales agreement, which the Company's management believes will lead to issuance of the GOI partial counter-guaranty of the Government of Karnataka guaranty.
In July 1995, the Company executed a joint development agreement with a subsidiary of China Light & Power Company, Limited ("CLP") (the "Joint Venture") which provides for the Company and CLP to co-develop the India project and to share equally in the direct development expenses related to the project. Additionally, the Company expects to secure one or more other partners for the purpose of making equity investments in the project. If the Company is successful in obtaining the necessary governmental approvals and guarantees of the power sales agreement and construction financing, the Company intends to further participate by overseeing construction of the project and managing, under a long-term agreement, the operation of the facility by a third party.
The projects the Company is seeking to develop are complex and the completion of any such project is subject to substantial risks. There can be no assurance that the Company will be able to obtain new power sales agreements, the necessary site agreements, steam sales agreements, licenses and certifications, environmental and other permits and financing necessary for the successful development of new projects. These, and other risks, may result in the Company abandoning projects under development.
PROJECT UNDER CONSTRUCTION
In December 1997, the Company substantially completed construction of a 248 megawatt combined-cycle, gas-fired electric generation facility (the "Clark Facility") for Public Utility District Number 1 of Clark County, Washington ("Clark") and earned a construction management fee of $4.5 million. Upon final completion of the facility and acceptance by Clark, the Company will earn an additional construction management fee of $500,000 and will also share in 50% of the amount, if any, of the excess of the contract amount ($117 million) over the actual costs and expenses incurred in constructing the Clark Facility. The excess is currently expected to be approximately $7 million. Cogentrix of Vancouver, Inc. ("CVC"), a subsidiary of Cogentrix Energy, Inc., performed the development and preliminary engineering of the Clark Facility and received a development fee of $4.5 million in October 1995. CVC is currently managing the post-completion operations and maintenance of the Clark Facility pursuant to a two-year agreement.
POWER MARKETING
Increased competition in the wholesale electric power market, and improved access to that market through wheeling, has prompted hundreds of companies to enter the market as non-generating wholesale power marketers. Such companies purchase and resell electric power, often packaging available electric power from several different sources to meet the unique needs of particular wholesale purchasers.
The Company's power marketing subsidiary, Cogentrix Energy Power Marketing, Inc. ("CEPM"), has entered into agreements with a utility to purchase electric capacity and energy and to schedule transmission of electric energy. CEPM has also entered into power sales and transmission scheduling agreements with a major industrial company to provide capacity and energy to its production facilities in the Pacific Northwest. CEPM currently matches its contracts to purchase capacity and energy with corresponding contracts to sell equivalent capacity and energy, thus CEPM is not subject to losses resulting from price fluctuations in the wholesale electric power market.
GREENHOUSE OPERATIONS
The Company has entered into an agreement with Agro Power Development, Inc. ("Agro"), a developer and operator of greenhouse facilities, giving the Company a right of first refusal to make investments in partnerships which develop, construct and operate greenhouses which produce tomatoes. The Company has made investments in partnerships which currently operate greenhouses with an aggregate 107 acres of production capacity. These greenhouses are located in Texas, Pennsylvania and New York.
DESCRIPTION OF THE COMPANY'S FACILITIES IN OPERATION
(The following discussion of the Company's facilities in operation does not reflect the Company's acquisition on March 20, 1998 of an approximate 74% ownership interest in two independent power plants from LS Power Corporation. See the discussion appearing above under the heading "Acquisitions of LS Power and Bechtel Assets.")
The Company's project subsidiaries currently own 100% of nine cogeneration power facilities in operation. The Company's other two facilities in operation are held by partnerships in each of which a Company subsidiary is a 50% general partner. Ten of these eleven facilities are currently operated and managed by the Company. The eleventh facility is operated and managed by an affiliate of the Company's partner in that facility. Each facility is located on a site which is owned or leased on a long-term basis by a project subsidiary, which ownership or leasehold interest is mortgaged to secure the subsidiary's project financing obligations, and, in certain instances, to secure the Company's project subsidiaries' obligations under their power sales agreements.
PROJECT AGREEMENTS. Each of the Company's project subsidiaries sells electricity to a utility under long-term power sales agreements. A plant's revenue from a power sales agreement usually consists of two components: energy payments and capacity payments. Energy payments, which are generally intended to cover the variable costs of electric generation (such as fuel costs and variable operation and maintenance expense), are based on a facility's net electrical output measured in kilowatt hours, with payment rates either fixed or indexed to the fuel costs of the purchasing utility. Capacity payments, which are intended to compensate for the fixed costs incurred by the project subsidiary (such as debt service on the project financing), are more complex and are calculated based on a declared capacity of a facility. Declared capacity is the electric generating capacity in megawatts that the Company's project subsidiary agrees in a power sales agreement to make available to the utility purchasing its electricity and is a percentage of the facility's design capacity dictated by its equipment and design specifications. Capacity payments are based either on a plant's net electrical output and paid on a kilowatt hour basis or on the plant's declared capacity and can be adjusted if actual capacity varies significantly from declared capacity.
Many power sales agreements (including the Company's) permit the purchasing utility to dispatch the facility (i.e., direct the plant to deliver a variable amount of electrical output) within limited parameters. The power sales agreements for ten of the Company's facilities are of a type typically called "fully dispatchable," providing the utility with greater dispatching rights whenever it determines that it can obtain lower cost power either from the utility's in-system generation or from bulk purchases. The power sales agreements for these facilities are structured in a manner such that when the amount of electrical output is reduced, the plant continues to receive capacity payments (which provide substantially all of the project subsidiary's profits). Energy payments (which cover the variable operating, maintenance and fuel costs) are received for each kilowatt hour delivered.
With the exception of two facilities, which produce thermal energy in the form of hot water for use by commercial greenhouses, all of the Company's plants produce steam ("process steam") for use by an industrial host. These industrial hosts, which include textile manufacturing companies, pharmaceutical manufacturing companies, chemical producers and synthetic fiber plants, use the process steam in their manufacturing processes. The Company's steam sales contracts with these industrial hosts generally are long-term contracts that provide payment on a per thousand pound basis for steam delivered and a minimum annual payment if the industrial host's plant is shut down. All contracts require steam purchases during their initial terms adequate to allow maintenance of QF status. See "Regulation -- Energy Regulations" herein.
Each of the Company's project subsidiaries purchases fuel under long-term supply agreements. The fuel supply contracts with respect to each of the Company's projects are structured so that the fuel cost escalations are generally matched
by increases in the energy payments received by the Company for electricity under the corresponding power sales agreement. This matching is typically effected by having the fuel prices escalate as a function of the solid fuel index of the purchasing utility, which reflects changes in the utility's cost of fuel to operate its plants or by contracting for scheduled increases in energy payments designed to offset scheduled increases in fuel prices.
The power sales agreements and the steam sales agreements provide substantially all of the revenue stream of the Company's facilities. Costs incurred under the fuel supply agreements (including related transportation agreements) accounted for approximately 45.7% of the Company's operating expenses during the six-month period ended December 31, 1997.
PROJECT FINANCING. The Company has financed each facility through project subsidiaries primarily under financing arrangements and related documents which, except as noted herein, require the extensions of credit to be repaid solely from the project's revenues and provide that the repayment of the extensions of credit (and interest thereon) is secured solely by the physical assets, agreements, cash flow and, in certain cases, the capital stock of or partnership interests in that project subsidiary. This type of financing is generally referred to as "project financing." Project financing transactions are generally structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds are then payable in a specified order of priority set forth in the financing documents to assure that, to the extent available, they are used first to pay operating expenses, senior debt service and taxes and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other conditions, amounts may be disbursed to the Company for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service.
The Company's existing facilities are financed using a high proportion of debt to equity. Leveraged financing permits the development of projects with a limited equity base but also increases the risk that a reduction in revenues could adversely affect a particular project's ability to meet its debt or lease obligations. The lenders have security interests covering certain aspects of the project, including the plant, related facility support agreements, the stock or partnership interest of certain of the Company's project subsidiaries, licenses and permits necessary to operate the plant and the cash flow derived from the plant. In the event of a foreclosure after a default, the Company would only retain an interest in the property remaining, if any, after all debts and obligations were paid. In addition, the debt of each operating project may reduce the liquidity of the Company's interest in such project since any sale or transfer of its interest would, in most cases, be subject both to a lien securing such project debt and to transfer restrictions in the relevant financing agreements. Also, the Company's ability to transfer or sell its interest in certain projects is restricted by a purchase option to a steam purchaser and certain rights of first refusal in favor of its power and steam purchasers. See "Facilities in Operation" herein.
The lenders under these project financing structures cannot look to the Company or its other projects for repayment (that is, they are "non-recourse" to the Company and its other project subsidiaries), unless the Company or another project subsidiary expressly agrees to undertake liability. The Company has agreed to undertake limited financial support for certain of its project subsidiaries in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities take the form of guarantees, indemnities, capital infusions and agreements to pay certain debt service deficiencies. To the extent the Company becomes liable under such guarantees and other agreements with respect to a particular project, distributions received by the Company from other projects may be used by the Company to satisfy these obligations. To the extent of these obligations, the lenders to a project have recourse to the Company and the distributions to the Company from other projects. The aggregate contractual liability of the Company to its project lenders is, in each case, a small portion of the aggregate project debt. Thus the project financing structures are generally described throughout this Report as being "substantially non-recourse" to the Company and its other projects. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
The Indenture under which the Senior Notes were issued permits the incurrence of debt, guarantees and liens jointly by any future project subsidiaries or joint ventures with respect to the future development of power generation facilities. To the extent the Company takes advantage of these provisions of the Indenture, the project lender (or lenders) will have recourse to several of the Company's facilities instead of having its (or their) recourse limited to the facility (or facilities) owned by a single project subsidiary.
The Company's plants are insured in accordance with covenants in each project's debt financing agreements. Coverages for each plant include workers' compensation, commercial general liability, supplemented by primary and excess umbrella liability, and a master property insurance program including property, boiler and machinery (at replacement cost) and business interruption.
OPERATING ARRANGEMENTS. Unlike many independent power producers who contract with third party operators, the Company operates ten of its facilities. Each project subsidiary employs directly the persons required to operate the facility it owns or leases. The Company hires its general plant managers early in the construction phase of the plants, invests in the training of operating personnel and structures its plant bonus program to reward efficient and cost effective operation of the plants. Executive management of the Company meets several times a year with the plant managers and conducts on-site plant performance reviews with each plant manager.
The Company provides to the plants it operates certain administrative and management services for a periodic fee, which in some cases is adjusted annually by an inflation factor. The ability of a project subsidiary to pay these management fees is contingent upon the continuing compliance by the project subsidiary with certain covenants under the project financing agreements and may be subordinated to the payment of obligations under those agreements. The Company has earned and will continue to earn incentive compensation from the Hopewell Facility, in which the Company holds a 50% general partnership interest and is the managing general partner, if the facility achieves certain net income levels.
ASH REMOVAL. Project subsidiaries owning nine of the Company's facilities contract with ReUse Technology, Inc. ("ReUse"), a wholly-owned subsidiary of the Company operated as an autonomous business unit, to remove coal ash generated by such plants. A third party removes and handles coal ash at the other coal-fired plant. As an alternative to disposing of coal ash in landfills, ReUse has developed the use of coal ash as structural fill material and in the manufacturing and production of various ash derived products for resale.
ReUse also provides ash services for cogeneration facilities owned and operated by unaffiliated independent power producers. In connection with the provision by ReUse of such services under a contract for one of these facilities, Cogentrix has agreed to take all action necessary (including making loans and equity contributions) to ensure that ReUse has adequate financial resources to perform its obligations under its agreement with the facility's owner up to a maximum aggregate liability of $1.5 million.
FACILITIES IN OPERATION
Set forth in the table and the text below are descriptions of the Company's eleven plants in operation at December 31, 1997. In each case, the Company developed the plant (except for the Ringgold facility that the Company purchased immediately prior to construction and the Birchwood facility in which the Company purchased its 50% interest during construction), which included siting, permitting and financing activities. Revenues are currently being realized from the sale of electricity and thermal energy generated by each of these facilities.
Each of the Company's facilities relies on a power sales agreement with a single customer for the majority of its revenues over the life of the power sales agreement. During the six-month period ended December 31, 1997, two regulated utilities, Carolina Power & Light Company ("CP&L") and Virginia Electric and Power Company ("Virginia Power"), accounted for approximately 85% of the Company's consolidated revenues. The failure of either of these utility customers to fulfill its contractual obligations for a prolonged period of time would have a substantial negative impact on the Company's primary source of revenues. Both CP&L and Virginia Power's senior debt securities are rated investment grade by Standard & Poor's Corporation and Moody's Investors Service, Inc.
(1) Actual project cost includes all costs directly associated with the construction of the facility, related improvements and land acquisition, together with costs incurred to obtain construction and permanent financing and other costs associated with the formation of each project entity and the start-up of the facility.
ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES. Cogentrix Eastern Carolina Corporation, a North Carolina corporation ("CECC"), owns and operates three 35 megawatt stoker coal-fired cogeneration plants in Elizabethtown, Lumberton and Kenansville, North Carolina (collectively, the "ELK Facilities" and individually an "ELK Facility"). The ELK Facilities were the first cogeneration facilities developed by the Company and are presently financed under a single project financing credit facility. The Elizabethtown and Lumberton plants commenced commercial operation in December 1985 with the Kenansville plant following in April 1986.
The ELK Facilities sell electricity to CP&L under separate power sales agreements, which were amended effective in September 1996. Under the amended terms, the power sales agreements for the Elizabethtown and Lumberton Facilities each have an initial term expiring in November 2000, and the power sales agreement for the Kenansville Facility has an initial term expiring in September 2001. Each of the power sales agreements has automatic renewals for one-year renewal
terms unless either party terminates the agreement prior to the commencement of a renewal term. The purchase price for electricity during such renewal term would continue to be the rate set forth in the power sales agreements. Annual increases in energy prices under the power sales agreement are designed to offset annual increases in coal and rail transportation prices.
In addition to CP&L's right to dispatch or suspend delivery of electricity from the ELK Facilities for maintenance and emergencies, the ELK Facilities are also subject to economic dispatch by CP&L. This right allows CP&L to suspend or reduce purchases of energy from the ELK Facilities if CP&L determines that it can operate its system for a designated period more economically. The power sales agreement is structured so that CECC will continue to receive capacity payments during any period of economic dispatch. Capacity payments cover project debt service, fixed operating costs and constitute a substantial portion of the profit component of the power sales agreement. Energy payments, which would be reduced (or possibly eliminated) as a result of an economic dispatch, primarily cover variable operating, maintenance, coal and rail transportation costs.
In the event CECC decides to dispose of an ELK Facility, it must first offer the facility to the respective steam purchaser, and if the steam purchaser does not exercise its right, CECC must then offer the facility to CP&L at fair market value.
Each of the power sales agreements provides that in the event of termination (other than for a material breach by CP&L) prior to the expiration of the initial term of the power sales agreements, CECC must pay CP&L a termination charge equal to the excess paid for capacity and energy over what would have been paid to CECC under the North Carolina Utilities Commission ("NCUC") published capacity credit and variable energy rates plus interest.
If the average capacity made available in the peak period or average energy generated or made available in peak or off-peak periods during any 12-month period falls below 80% of the established contract capacity level or the contract peak or off-peak energy level, as the case may be, CP&L may establish a new contract capacity level or contract energy level. If a reduction in the contract capacity level is invoked, a special charge will be imposed by CP&L equal to a percentage of the termination charge described above. If a reduction in the contract energy level is invoked, a special reduction in the contract energy charge will also be imposed. In addition, if CECC desires to terminate the power sales agreement prior to its expiration and a substitute operator satisfactory to CP&L is not secured, CECC must pay to CP&L the termination charge described above plus an amount equal to the depreciated installed cost of the interconnection facilities relating to the plant (using a 20-year useful life). Cogentrix has guaranteed the performance of CECC under the CP&L power sales agreements.
Alamac Knit Fabrics, Inc. purchases steam for its apparel fabrics division mills from the Lumberton Facility and the Elizabethtown Facility under separate steam sales agreements expiring in December 2000, each of which contains renewal options. Guilford Mills, Inc. ("Guilford") purchases steam from the Kenansville Facility for use in its textile manufacturing plant under a steam sales agreement expiring in July 2001, which contains renewal options.
Each of the ELK Facilities uses low-sulfur stoker coal mined in Kentucky supplied under a single coal sales agreement with James River Coal Sales, Inc. ("James River") and its affiliate, Bell County Coal Corporation. The coal sales agreement provides that CECC will purchase and James River will provide all of CECC's coal requirements through September 2001. If the ELK Facilities do not purchase an average of 320,000 tons per fiscal year (as appropriately reduced due to force majeure events), the contract will be extended if during any subsequent period the ELK Facilities are selling electricity to CP&L until CECC purchases such short-fall amount.
The coal purchased for the ELK Facilities is transported by CSX Transportation, Inc. ("CSX") under separate rail transportation contracts each having a term through September 2001 to rail unloading facilities owned by CECC. Coal is then hauled by truck to each of the plants by independent contractors, and ash is removed from each of the plants by ReUse, under separate long-term coal hauling and ash disposal agreements.
The ELK Facilities are financed pursuant to a senior credit facility which provides for a term loan ($26.7 million outstanding at December 31, 1997) and a $3.3 million letter of credit to secure the obligations of CECC to pay debt service.
Cogentrix has pledged the stock of CECC to secure the obligations of CECC under the senior credit facility, but Cogentrix is not liable for any deficiency if the proceeds of any sale or disposition of the collateral are insufficient to pay the secured obligations.
The ELK Facilities generated $16.4 million of revenues in the six-month period ended December 31, 1997, $35.7 million of revenues in fiscal 1997, $53.9 million of revenues in fiscal 1996 and $52.4 million of revenues in fiscal 1995.
ROXBORO AND SOUTHPORT FACILITIES. Cogentrix of North Carolina, Inc., a North Carolina corporation ("CNC"), operates two stoker coal-fired cogeneration plants in Roxboro and Southport, North Carolina (individually, the "Roxboro Facility" and "Southport Facility"; collectively, the "Roxboro and Southport Facilities"), which are owned by another wholly-owned subsidiary of the Company, Cogentrix of North Carolina Holdings, Inc. The Roxboro and Southport Facilities are financed under a single project financing credit facility. The 60 megawatt Roxboro Facility, which commenced commercial operation in August 1987, may operate at a declared capacity of up to 56 megawatts. The 120 megawatt Southport Facility, which may operate at a declared capacity of up to 107 megawatts, commenced commercial operation in September 1987.
The Roxboro and Southport Facilities sell electricity to CP&L under separate power sales agreements, each having an initial term expiring in December 2002 with automatic renewals for two-year renewal terms unless either party terminates the agreement prior to the commencement of a renewal term. The purchase price for electricity during such renewal term would continue to be the rate for 2002 set forth in the power sales agreements. These power sales agreements were amended effective in September 1996 to provide CP&L economic dispatch rights on the facilities and to eliminate options CP&L had to purchase these facilities. Under the amended power sales agreements, CP&L has a right of first refusal on either or both facilities.
The power sales agreements provide for scheduled annual increases in energy payments through 1997, which the Company believes are sufficient to offset scheduled annual increases in coal and rail transportation prices. Energy payments from 1998 through 2002 under the power sales agreements are designed to offset annual fluctuations in coal and rail transportation prices.
In addition to CP&L's right to dispatch or suspend delivery of electricity from the Roxboro and Southport Facilities for maintenance and emergencies, the Roxboro and Southport Facilities are also subject to economic dispatch by CP&L. This right allows CP&L to suspend or reduce purchases of energy from the Roxboro and Southport Facilities if CP&L determines that it can operate its system for a designated period more economically. The power sales agreements are structured so that CNC will continue to receive capacity payments during any period of economic dispatch. Capacity payments cover project debt service, fixed operating costs and constitute a substantial portion of the profit component of the power sales agreements. Energy payments, which would be reduced (or possibly eliminated) as a result of an economic dispatch, primarily cover variable operating, maintenance, coal and rail transportation costs.
Each of the power sales agreements provides that in the event CNC desires to terminate the power sales agreement or abandons the Roxboro or Southport Facility, CNC must pay CP&L a termination charge. Such termination charge will be equal to the sum of (i) the depreciated installed cost of the interconnection facilities relating to the plant (using a 20-year useful life), plus (ii) the cost incurred by CP&L to replace the capacity provided by the Roxboro or Southport Facility in excess of the capacity payments which would have been made to CNC for the Roxboro or Southport Facility, plus (iii) a carrying charge equal to the overall pretax cost of capital allowed to CP&L by the NCUC retail rate order in effect during the time the energy credits were received.
Cogentrix has guaranteed the performance of CNC under the CP&L power sales agreements.
Collins & Aikman Corporation ("C&A") purchases process steam for its textile manufacturing facility from the Roxboro Facility under a 15-year steam sales agreement (of which approximately five years remain) that is renewable by C&A for an additional five-year term upon one year's prior written notice. During the initial term of the steam sales agreement, C&A is obligated to purchase and use a minimum of five percent of the Roxboro Facility's total energy output so that the facility will remain a QF under PURPA.
Archer-Daniels-Midland Company ("ADM") purchases steam for its pharmaceutical and chemical manufacturing company from the Southport Facility under a 15-year steam sales agreement (of which approximately five years remain) that is renewable by ADM for an additional five-year term upon one year's prior written notice. During the initial term of the steam sales agreement, ADM is obligated to purchase and use a minimum of five percent of the Southport Facility's total energy output so that the facility will remain a QF under PURPA.
CNC has executed long-term coal sales agreements for both the Roxboro and Southport Facilities with subsidiaries of Alliance Coal Corporation. The terms of these contracts correspond with the terms of each Facility's power sales agreement.
Norfolk Southern Railway Company transports coal to the Roxboro Facility under a rail transportation contract ending in 2002. The coal for the Southport Facility is transported by CSX, under a rail transportation contract ending in 2002, to a rail side track located approximately six miles from the Southport Facility and is then hauled by a CNC operated locomotive to the plant site.
Ash hauling services are provided for the Roxboro and Southport Facilities by ReUse under contracts expiring in December 2002.
The Southport and Roxboro Facilities are financed pursuant to a senior credit facility which provides for a term loan ($93 million outstanding at December 31, 1997) and a $6.5 million letter of credit facility to secure the obligations of CNC to pay debt service. In connection with the financing, the Company entered into an agreement for the benefit of the project lenders to fund cash deficits CNC could experience as a result of incurring certain costs, subject to a cap of $11.3 million.
Certain of the Company's subsidiaries have pledged their respective ownership interests in the Roxboro and Southport Facilities as collateral security for the senior credit facility, but Cogentrix Energy, Inc. is not liable for any deficiency if the proceeds of any sale or disposition of the collateral are insufficient to pay the secured obligations.
The steam sales agreement for the Southport Facility provides that upon at least 12 months' prior notice, CNC will sell to ADM up to an additional 100,000 pounds of steam per hour. The power sales agreement further provides that if upon a sale of the Southport Facility CP&L exercises its right of first refusal and a package boiler to meet ADM's increased steam demands has not been installed, CNC must deposit into an escrow account at such time an amount sufficient to provide a package boiler to meet such increased steam demands. Management anticipates such a boiler could be provided at a cost of approximately $2,500,000.
The Roxboro and Southport Facilities generated $24.9 million of revenues in the six-month period ended December 31, 1997, $58.2 million of revenues in fiscal 1997, $86.9 million of revenues in fiscal 1996 and $84.4 million of revenues in fiscal 1995.
HOPEWELL FACILITY. The Company's Hopewell facility (the "Hopewell Facility"), located in Hopewell, Virginia, is a 120 megawatt stoker coal-fired cogeneration facility owned by James River Cogeneration Company ("JRCC"), which may operate at a declared capacity of up to 92.5 megawatts. JRCC is a North Carolina general partnership, in which a 50% general partnership interest is owned by Cogentrix of Virginia, Inc., a Virginia corporation ("CVA"), which is a wholly-owned subsidiary of the Company. The remaining 50% is owned by Capistrano Cogeneration Company, a subsidiary of Edison Mission Energy. Commercial operation of the Hopewell Facility commenced in December 1987.
CVA, as managing general partner, has complete responsibility for the operation, maintenance and management of the Hopewell Facility under a 20-year operations, maintenance and management agreement with JRCC (expiring in December 2008). JRCC is governed by a partnership agreement which provides that certain significant business decisions regarding the partnership must be approved by representatives of both partners. The operations, maintenance and management agreement provides for CVA to receive base compensation as well as incentive compensation if the facility achieves certain levels of net income.
The Hopewell Facility sells electricity to Virginia Power under a power sales agreement which expires in January 2008. The power sales agreement was amended, effective in February 1998, to provide Virginia Power economic dispatch rights on
the Facility and to eliminate the regulatory disallowance provision in the power sales agreement, which allocated, in part, the risk of disallowance by the Virginia State Corporation Commission ("SCC") to JRCC.
Under the amended power sales agreement, JRCC provides up to 92.5 megawatts of capacity to Virginia Power. The amended power sales agreement provides for scheduled annual increases in energy payments through 2002, which the Company believes are sufficient to offset scheduled increases in coal and rail transportation costs. Energy payments from 2003 through 2008 under the power sales agreement are designed to offset annual fluctuations in coal and rail transportation prices.
In addition to Virginia Power's right to suspend delivery of electricity for maintenance and emergencies, the Hopewell Facility is also subject to economic dispatch by Virginia Power. This right allows Virginia Power to suspend or reduce purchases of energy from the Hopewell Facility if Virginia Power determines that it can operate its system for a designated period more economically. The power sales agreement is structured so that JRCC will continue to receive capacity payments during any period of economic dispatch. Capacity payments cover project debt service, fixed operating costs and constitute a substantial portion of the profit component of the power sales agreement. Energy payments, which would be reduced (or possibly eliminated) as a result of an economic dispatch, primarily cover variable operating, maintenance, coal and rail transportation costs. If the power sales agreement is terminated prior to the end of its initial or any subsequent term other than due to a default by Virginia Power, JRCC must pay Virginia Power the difference between payments for capacity already made and those that would have been allowable under the applicable avoided cost schedules plus interest.
The power sales agreement grants to Virginia Power a right of first refusal to purchase the Hopewell Facility at fair market value provided that such amount will not exceed JRCC's net investment in the Hopewell Facility.
Allied-Signal Corporation ("ASC") purchases steam from the Hopewell Facility under a 20-year steam sales agreement (of which approximately 10 years remain). ASC is obligated to purchase and use a minimum of five percent of the Hopewell Facility's total energy output in a manner such that the facility will remain a QF under PURPA.
Coal for the Hopewell Facility is supplied from mines in Kentucky by Pontiki Coal Corporation ("Pontiki") under a 15-year coal sales agreement (of which approximately five years remain), which requires Pontiki to sell and JRCC to purchase all of the Hopewell Facility's requirements for coal. Because the term of the coal sales agreement for the Hopewell Facility expires at the end of 2002, JRCC will need to assure itself of a supply of coal for the remaining term of its power sales agreement. JRCC's current plans are to negotiate a replacement long-term coal sales agreement. However, if JRCC is unable to enter into agreements acceptable to it, JRCC currently believes it would be able to purchase its requirements on the short-term spot market at prices that are presently significantly below the present contract rates. The coal is transported by Norfolk Southern Railroad Company under a 15-year rail transportation agreement (of which approximately five years remain).
Ash generated by the Hopewell Facility is removed and disposed of by ReUse under an ash removal agreement having a term expiring in 2005.
In February 1998, JRCC refinanced its project debt with the proceeds of a senior credit facility, which provides for a $80 million term loan and a $5 million debt service reserve letter of credit. In connection with the refinancing, the Company entered into an agreement for the benefit of the project lenders to fund cash deficits JRCC could experience as a result of incurring certain costs, subject to a cap of $10.6 million.
Cogentrix has pledged the stock of CVA as security for the obligations of JRCC under this senior credit facility, but Cogentrix is not liable for any deficiency if the proceeds of any sale or disposition of the pledged stock are insufficient to pay all secured obligations.
The Hopewell Facility generated $24.8 million of revenues in the six-month period ended December 31, 1997, $51.2 million of revenues in fiscal 1997, $57.4 million in revenues in fiscal 1996 and $54.9 million in revenues in fiscal 1995.
PORTSMOUTH FACILITY. The Company's Portsmouth Facility (the "Portsmouth Facility") located in Portsmouth, Virginia is a 120 megawatt stoker coal-fired cogeneration facility owned by Cogentrix Virginia Leasing Corporation, a North Carolina corporation ("CVLC"), which may operate at a declared capacity of up to 115 megawatts. Commercial operation of the Portsmouth Facility commenced in June 1988.
The Portsmouth Facility sells electricity to Virginia Power under a power sales agreement which expires in June 2008. The power sales agreement was amended, effective in December 1997, to provide Virginia Power economic dispatch rights on the Facility and to eliminate the regulatory disallowance provision in the power sales agreement, which allocated, in part, the risk of disallowance by the SCC to CVLC.
Under the amended power sales agreement, CVLC provides up to 115 megawatts of capacity to Virginia Power. The amended power sales agreement provides for scheduled annual increases in energy payments through 2002, which the Company believes are sufficient to offset scheduled increases in coal and rail transportation costs. Energy payments from 2003 through 2008 under the power sales agreement are designed to offset annual fluctuations in coal and rail transportation prices.
In addition to Virginia Power's right to suspend delivery of electricity for maintenance and emergencies, the Portsmouth Facility is also subject to economic dispatch by Virginia Power. This right allows Virginia Power to suspend or reduce purchases of energy from the Portsmouth Facility if Virginia Power determines that it can operate its system for a designated period more economically. The power sales agreement is structured so that CVLC will continue to receive capacity payments during any period of economic dispatch. Capacity payments cover project debt service, fixed operating costs and constitute a substantial portion of the profit component of the power sales agreement. Energy payments, which would be reduced (or possibly eliminated) as a result of an economic dispatch, primarily cover variable operating, maintenance, coal and rail transportation costs.
In addition, if the power sales agreement is terminated prior to the end of its initial or any subsequent term other than due to a default by Virginia Power, CVLC must pay Virginia Power the difference between payments for capacity already made and those that would have been allowable under the applicable avoided cost schedules plus interest.
The power sales agreement grants to Virginia Power a right of first refusal to purchase the Portsmouth Facility at fair market value provided that such amount will not exceed CVLC's net investment in the Portsmouth Facility.
The Portsmouth Facility supplies process steam to Clariant Corporation ("Clariant") pursuant to a 20-year steam sales agreement (of which approximately 11 years remain) which renews automatically for successive two-year periods unless either party gives two years' notice of cancellation. Clariant is obligated to purchase and use a minimum of five percent of the Portsmouth Facility's total energy output (except in the case of force majeure) so that the facility will remain a QF under PURPA.
Coal for the Portsmouth Facility is supplied from mines in Kentucky by Arch Coal Sales Company ("ACS") pursuant to a 15-year coal sales agreement (of which approximately six years remain), which requires ACS to sell and CVLC to purchase all of the Portsmouth Facility's requirements for coal.
Coal for the Portsmouth Facility is transported by rail and barge. CVLC has a 15-year rail transportation contract (of which approximately six years remain) with Norfolk Southern Railway Company. From the rail unloading facility in Norfolk, Virginia, the coal is then transported by a barge owned by CVLC to the Portsmouth Facility under a barge transportation contract having a term expiring December 31, 2002 with an unrelated party that provides tugboat and supervisory services for the loading and unloading of the coal.
Ash generated by the Portsmouth Facility is managed by ReUse under an ash removal agreement having a term expiring December 31, 2005, subject to two five-year renewal options.
In December 1997, CVLC refinanced its project debt with a senior credit facility which provides for a term loan ($61.5 million outstanding at December 31, 1997), a revolving credit facility ($40.5 million commitment with $-0- outstanding at December 31, 1997) and a $6 million debt service reserve letter of credit. In connection with the refinancing,
the Company entered into an agreement for the benefit of the project lenders to fund cash deficits CVLC could experience as a result of incurring certain costs, subject to a cap of $30 million.
Cogentrix has pledged the stock of CVLC to secure the obligations of CVLC under the credit facility, but Cogentrix is not liable for any deficiency if the proceeds of any sale or disposition of the collateral are insufficient to pay the secured obligations.
The Portsmouth Facility generated $31.3 million of revenues in the six-month period ended December 31, 1997, $61.0 million in revenues in fiscal 1997, $58.9 million in revenues in fiscal 1996 and $57.4 million in revenues in fiscal 1995.
ROCKY MOUNT FACILITY. The Company's Rocky Mount Facility located near Rocky Mount, North Carolina is a 120 megawatt stoker coal-fired cogeneration facility (the "Rocky Mount Facility") owned by Cogentrix of Rocky Mount, Inc., a North Carolina corporation ("CRM"). Commercial operation of the Rocky Mount Facility commenced in October 1990. Under a power sales agreement with North Carolina Power Company ("NC Power"), a division of Virginia Power, the Rocky Mount Facility provides a declared capacity of 115.5 megawatts of electricity for an initial 25-year term (of which approximately 18 years remain) with two renewal terms of up to five years each. Annual changes in energy prices under the power sales agreement are designed to offset annual fluctuations in coal and rail transportation prices. NC Power has a right of first refusal to purchase the Rocky Mount Facility.
In addition to NC Power's right to dispatch or suspend delivery of electricity from the Rocky Mount Facility for maintenance and emergencies, the facility is also subject to economic dispatch by NC Power. This right allows NC Power to suspend or reduce purchases of energy from the Rocky Mount Facility if NC Power determines that it can operate its system for a designated period more economically. The power sales agreement is structured so that CRM will continue to receive capacity payments during any period of economic dispatch. Capacity payments constitute a substantial portion of the profit component of the power sales agreement. Energy payments, which would be reduced (or possibly eliminated) as a result of an economic dispatch, primarily cover variable operating, maintenance, coal and rail transportation costs associated with operating at different levels.
Currently, NC Power is permitted full recovery from its customers of payments to CRM under the power sales agreement. The power sales agreement provides, however, that if an applicable legislative or regulatory authority should take action which would have the effect of disallowing NC Power from recovering from its customers all or a portion of the payments for capacity in excess of a certain amount during the first 18 years following the commencement of commercial operation of the facility (until October 2008), NC Power will continue to pay for capacity at the contract price through the first 18 years and may thereafter withhold up to 75% of the payments for capacity for the following three years to the extent necessary to repay the disallowance to NC Power with interest. In the event such withholdings do not fully repay such disallowance, CRM must repay the difference at the end of the 21st year. Aggregate payments for capacity after the 18th anniversary of the commercial operation date are not permitted to exceed the amount that NC Power is allowed to recover from its customers.
In light of this regulatory disallowance provision in the power sales agreement, the project lender for the Rocky Mount Facility has established a regulatory disallowance reserve account, which is required to be funded at any time a regulatory disallowance occurs or, from and after January 1, 2004, any filing with a regulatory authority, which is deemed meritorious in the judgment of the lender in consultation with counsel, is made challenging the pass-through of payments under the power sales agreement (each a "Regulatory Disallowance Event"). If a Regulatory Disallowance Event occurs during the period from 1994 through 2002, 25% of cash flow from the facility must be deposited to the regulatory disallowance reserve account until the balance of such account is equal to the amount required to be funded. If a Regulatory Disallowance Event occurs during the period from 2003 through 2013, 100% of the cash flow from the facility must be deposited to the regulatory disallowance reserve account until the balance of such account is equal to the amount required to be funded. The amount required to be funded in such account is an amount equal to the lesser of (i) projected reduction in cash flows from 2009 through 2013 as a result of the disallowance, and (ii) the amount of the debt outstanding at September 30, 2008.
If the Rocky Mount Facility has forced outage days in any year with respect to more than the greater of 25 days or ten percent of the total number of days the facility was required by NC Power to operate, capacity payments for such period will be reduced by four percent for each such excess forced outage day.
In the event capacity testing indicates that the Rocky Mount Facility's dependable capacity is less than 90% of the declared capacity, CRM will be obligated to pay annual liquidated damages to NC Power. A letter of credit has been posted by CRM in favor of NC Power to secure its obligations to perform under the power sales agreement.
Steam from the Rocky Mount Facility is sold to Abbott Laboratories ("Abbott") pursuant to a 25-year steam sales agreement (of which approximately 18 years remain) which may be extended for an additional five-year term upon one year's prior written notice by Abbott. Abbott is obligated to purchase and use a minimum of five percent of the total energy output so that the facility will remain a QF under PURPA. The steam sales agreement provides that if CRM does not deliver steam in accordance with the agreement under certain circumstances, Abbott is entitled to receive certain quantities of steam in the future at substantially reduced prices.
Coal for the Rocky Mount Facility is supplied from mines in West Virginia under a 23-year coal sales agreement (of which approximately 16 years remain) with Laurel Creek Co., Inc. and ACS Coal Sales Company ("ACS Coal Sales"), which requires ACS Coal Sales to sell and CRM to purchase all of the Rocky Mount Facility's requirements for coal. The contract price for coal includes a base price which is modified based upon changes in a fuel and transportation index that equals the fluctuation in rates payable by Virginia Power for energy under the power sales agreement adjusted by fluctuations in pricing under CRM's rail transportation contract. CRM purchases the lime required by the plant's pollution control equipment from APG Lime Corp. under a five-year agreement expiring in December 2000.
CSX transports the coal for the Rocky Mount Facility pursuant to a 23-year rail transportation contract (of which approximately 16 years remain) with pricing indexed to parallel increases in rates under CSX's transportation agreements with Virginia Power.
Ash generated by the Rocky Mount Facility is managed by ReUse under an ash removal agreement having a term expiring in 2013.
The Rocky Mount Facility is financed pursuant to a term loan ($125.8 million outstanding at December 31, 1997). In addition, CRM has a cash collateralized letter of credit in a face amount equal to $3,150,000 issued in favor of NC Power in support of CRM's obligations under the power sales agreement with NC Power.
The Rocky Mount Facility generated $25.1 million in revenues in the six-month period ended December 31, 1997, $48.5 million in revenues in fiscal 1997, $47.5 million in revenues in fiscal 1996 and $45.3 million in revenues in fiscal 1995.
RINGGOLD FACILITY. The Company's Ringgold facility (the "Ringgold Facility"), located in Ringgold, Pennsylvania, is a 15.5 megawatt gas-fired cogeneration facility using an internal combustion engine fueled primarily by natural gas. The Ringgold Facility is owned by Cogentrix of Pennsylvania, Inc., a Delaware corporation ("CPA"). The Ringgold Facility commenced commercial operation in April 1991.
Pennsylvania Electric Company ("Penelec") purchases energy from the Ringgold Facility under a 20-year power sales agreement (of which approximately 13 and one-half years remain). Under the power sales agreement, failure of CPA to generate and sell electricity throughout the term of the agreement (other than due to force majeure) at an annual average level which is at least equal to 85% of the average output achieved during a rolling three-year period of operation would result in the payment of a penalty which may be offset against amounts payable by Penelec for energy.
In January 1998, the Company signed an agreement with Penelec to terminate the Ringgold Facility's power purchase agreement with Penelec. This termination agreement was the result of a request for proposals to buy-back or restructure power sales agreements issued to all major operating IPP projects in Penelec's territory in April 1997. The termination agreement with Penelec provides for a payment to the Company of approximately $25 million which will be sufficient to retire all of the outstanding project debt. The buy-back of the power purchase agreement
is subject to the issuance of an order by the Pennsylvania Public Utility Commission granting Penelec the authority to fully recover from its customers the consideration paid to CPA under the buyout agreement. Management does not expect this event to have an adverse impact on the Company's consolidated results of operations or financial position.
Thermal energy (in the form of hot water) from the Ringgold Facility is provided to a 10-acre greenhouse owned by CPA which is leased to and operated by Keystone Village Farms, Inc. ("Keystone"), a subsidiary of Agro Power Development, Inc. (see "Greenhouse Operations" herein), under a lease with a ten-year term, which may be extended with the consent of the Company. Keystone harvests tomatoes from the greenhouse which are then sold to wholesalers for resale to grocery store chains.
Natural gas for the facility is supplied pursuant to two gas supply contracts. One of these contracts is with JC Enterprises ("JCE") under an agreement pursuant to which CPA has agreed to purchase two-thirds of its requirements for gas. The price for gas under the agreement with JCE is a fixed price which escalates by a fixed percentage monthly. JCE is responsible for delivering the gas to CPA's property from its gas wells located in close proximity to the plant. The term of this contract is 15 years (of which approximately eight years remain) or until a specified volume of gas is purchased, whichever is earlier. CPA also purchases gas under a gas purchase agreement with Eastern Marketing Corporation ("Eastern") pursuant to which it has prepaid for the quantity of gas contracted for thereunder. Eastern is responsible for transporting the gas to CPA's property. The term of the Eastern contract is ten years (of which approximately three years remain).
The Ringgold Facility is financed pursuant to a senior term loan ($15.7 million outstanding at December 31, 1997) and a subordinated note payable ($7.4 million outstanding at December 31, 1997). Cogentrix has granted a lien on the stock of CPA to the senior lenders. In April 1994, Cogentrix Delaware Holdings, Inc. (a wholly owned subsidiary of Cogentrix Energy, Inc.) purchased for $3,000,000 the entire $7.4 million outstanding principal balance of the subordinated note and the related accrued interest receivable from the financial institution holding the subordinated note.
When this project was initially developed, CPA entered into a consulting agreement which provided for certain payments to be made annually to the original developer of the Ringgold Facility. In September 1994, the Company purchased the developer's interest in the consulting agreement with CPA and acquired all outstanding shares of junior preferred stock of CPA held by him.
As a result primarily of higher than anticipated construction costs, the failure and subsequent replacement of certain equipment and higher than anticipated maintenance and operation expenses, the Ringgold Facility has failed to produce sufficient revenue to cover the debt service requirements of the subordinated credit facility and to cover completely the debt service requirements of the senior credit facility. Since the date of commencement of construction through June 30, 1997, the Company has made approximately $18.8 million in equity contributions to CPA in order to cover construction costs and permit CPA to make required payments of principal and interest. Given the current restructuring efforts, the Company intends to continue to provide funds to CPA, if necessary, for debt service.
The Ringgold Facility generated $4.4 million in revenues for the six-month period ended December 31, 1997, $8.4 million in revenues in fiscal 1997, $7.8 million in revenues in fiscal 1996 and $7.6 million in revenues in fiscal 1995.
RICHMOND FACILITY. Cogentrix of Richmond, Inc., a North Carolina corporation ("CR"), owns and operates a 240 megawatt stoker coal-fired cogeneration plant in Richmond, Virginia (the "Richmond Facility"). Commercial operation of the Richmond Facility was commenced in two phases: Unit I in May 1992 and Unit II in August 1992.
The Richmond Facility provides 209 megawatts of declared capacity electricity to Virginia Power under two 25-year power sales agreements (of which approximately 20 years remain) each of which may be extended for an additional five-year term provided that two years prior to the end of the initial term the parties agree to such extension. Annual changes in energy prices under the power sales agreements are designed to offset annual fluctuations in coal and rail transportation prices. Virginia Power has a right of first refusal to purchase the Richmond Facility subject to the prior exercise of any such right by the steam purchaser.
Currently, Virginia Power is permitted full recovery from its customers of payments made to CR under the power sales agreements. The power sales agreements provide, however, that if an applicable legislative or regulatory authority should take action which would have the effect of disallowing Virginia Power from recovering from its customers all or a portion of the payments for capacity in excess of a certain amount during the first 18 years following the commencement of commercial operation of the facility, Virginia Power will continue to pay for capacity at the contract price through the first 18 years and may thereafter withhold up to 75% of the payments for capacity for the following three years to the extent necessary to repay the disallowance to Virginia Power with interest. In the event such withholdings do not fully repay such disallowance, CR will repay the difference at the end of the 21st year. Aggregate payments for capacity after the 18th anniversary of the commercial operation date are not permitted to exceed the amount that Virginia Power is allowed to recover from its customers.
If the Richmond Facility has forced outage days in any year with respect to more than the greater of 25 days or ten percent of the total number of days the facility was required by Virginia Power to operate, capacity payments for such period will be reduced by four percent for each such excess forced outage day. In addition to Virginia Power's right to dispatch or suspend delivery of electricity from the Richmond Facility for maintenance and emergencies, the facility is also subject to economic dispatch by Virginia Power. This right allows Virginia Power to suspend or reduce purchases of energy from the Richmond Facility if Virginia Power determines that it can operate its system for a designated period more economically. The power sales agreements are structured so that CR will continue to receive capacity payments during any period of economic dispatch. Capacity payments constitute a substantial portion of the profit component of the power sales agreement. Energy payments, which would be reduced (or possibly eliminated) as a result of an economic dispatch, primarily cover variable operating, maintenance, coal and rail transportation costs associated with operating at different levels.
In the event capacity testing indicates that the Richmond Facility's dependable capacity is less than 90% of the declared capacity, CR will be obligated to pay annual liquidated damages to Virginia Power. Letters of credit have been posted by CR in favor of Virginia Power to secure its obligations to perform under the power sales agreements.
The Richmond Facility provides steam to E. I. Du Pont de Nemours & Company ("DuPont") for its Spruance plant located in Chesterfield County, Virginia, under a long-term steam sales agreement. DuPont is obligated to purchase and use a minimum of five percent of the Richmond Facility's total energy output in a manner such that the Facility will remain a QF under PURPA. If CR is unable to operate the Richmond Facility to comply with the steam sales agreement, DuPont has a qualified right to operate the facility. DuPont also has the right to purchase the Richmond Facility upon the termination of the steam sales agreement for a price equal to fair market value of the facility at the time of exercise.
Coal for the Richmond Facility is purchased under two separate coal sales agreements. Under a 20-year agreement (of which approximately 15 years remain), Electric Fuels Corporation ("Electric Fuels") provides coal mined in Kentucky for Unit I of the Richmond Facility. Coastal provides the coal requirements for Unit II from mines in Kentucky under a separate 15-year agreement (of which approximately 10 years remain). The coal sales agreements require the coal providers to sell and CR to purchase all of the requirements for the respective unit of the Richmond Facility, subject to certain maximum and minimum requirements. The contract price for coal includes a base price which is modified based upon a fuel and transportation index that parallels the fluctuation in rates payable by Virginia Power for energy under the power sales agreement adjusted by fluctuations in pricing under CR's rail transportation contracts. CSX transports the coal for both units of the Richmond Facility pursuant to two separate rail transportation contracts each having a 20-year term expiring in 2012.
Ash generated by the Richmond Facility is managed by ReUse under an ash removal agreement having a term expiring in 2008.
The Richmond Facility is financed pursuant to a senior credit facility, which includes (i) a letter of credit ($150.1 million outstanding at December 31, 1997) issued to support commercial paper notes of CR issued from time to time; (ii) letters of credit ($48.0 million outstanding at December 31, 1997) issued to support certain revenue bonds issued by the Industrial Development Authority of the City of Richmond, Virginia; and (iii) letters of credit in an aggregate face amount equal to $5,700,000 issued in support of CR's obligations to Virginia Power under the power sales agreements.
CR purchased one of the power sales agreements relating to the Richmond Facility from WV Hydro, Inc. ("WV"). In connection with such purchase and in consideration of certain consulting arrangements, CR has continuing obligations to make payments to Clover Development Company ("Clover"), an affiliate of WV, in an aggregate amount ranging from
$250,000 to $750,000, each year through 2003, from excess facility cash flow. If excess facility cash flow for any year is insufficient to pay the $250,000 minimum amount, the deficiency will be carried forward and is payable from excess facility cash flow, if any, in future years. In addition, CR is obligated to pay to Clover an amount ranging from 3 to 3.5 percent of the net proceeds payable to CR upon any sale, disposition or refinancing of the Richmond Facility after payment of senior and subordinated project financing debt and expenses.
The Richmond Facility generated $41 million in revenues for the six-month period ended December 31, 1997, $79.5 million in revenues in fiscal 1997, $80.9 million in revenues in fiscal 1996 and $79.2 million in revenues in fiscal 1995.
BIRCHWOOD FACILITY. Birchwood Power Partners, L.P. ("Birchwood"), a Delaware limited partnership, owns the Birchwood Facility, which is located in King George, Virginia. Cogentrix/Birchwood Two, L.P., an indirect, wholly-owned subsidiary of the Company, owns a 50% interest in Birchwood. An indirect, wholly-owned subsidiary of The Southern Company owns the remaining 50% of Birchwood. The Birchwood Facility commenced commercial operation in November 1996.
The Birchwood Facility provides up to 202 megawatts of declared capacity electricity to Virginia Power under a 25-year power sales agreement (of which approximately 24 years remain) which may be extended for an additional five-year term provided that two years prior to the end of the initial term the parties agree to such extension. Annual changes in energy prices under the power sales agreement are designed to offset annual fluctuations in coal and rail transportation prices. Virginia Power has a right of first refusal to purchase the Birchwood Facility. In addition, Virginia Power has an option to purchase the Birchwood Facility at the end of the term of the power sales agreement.
Currently, Virginia Power is permitted full recovery from its customers of payments made to Birchwood under the power sales agreement. The power sales agreement provides, however, that if an applicable legislative or regulatory authority should take action which would have the effect of disallowing Virginia Power from recovering from its customers all or a portion of the payments for capacity in excess of a certain amount during the first 20 years following the commencement of commercial operation of the facility, Virginia Power will continue to pay for capacity at the contract price through the first 20 years and may thereafter withhold up to 75% of the payments for capacity for the following year to the extent necessary to repay the disallowance to Virginia Power with interest. In the event such withholdings do not fully repay such disallowance, Birchwood will repay the difference at the end of the 21st year. Aggregate payments for capacity after the 20th anniversary of the commercial operation date are not permitted to exceed the amount that Virginia Power is allowed to recover from its customers.
If the Birchwood Facility is unable to operate within the dispatch parameters established by Virginia Power under the power sales agreement, the capacity payments for such period are subject to reduction. In addition to Virginia Power's right to dispatch or suspend delivery of electricity from the Birchwood Facility for maintenance and emergencies, the facility is also subject to economic dispatch by Virginia Power. This right allows Virginia Power to suspend or reduce purchases of energy from the Birchwood Facility if Virginia Power determines that it can operate its system for a designated period more economically. The power sales agreement is structured so that Birchwood will continue to receive capacity payments during any period of economic dispatch. Capacity payments constitute a substantial portion of the profit component of the power sales agreement. Energy payments, which would be reduced (or possibly eliminated) as a result of an economic dispatch, primarily cover variable operating, maintenance, coal and rail transportation costs associated with operating at different levels.
In the event capacity testing indicates that the Birchwood Facility's dependable capacity is less than 90% of the declared capacity, Birchwood will be obligated to pay annual liquidated damages to Virginia Power. A letter of credit has been posted by Birchwood in favor of Virginia Power to secure its obligations to perform under the power sales agreement.
The 36-acre greenhouse located adjacent to the Facility, which is jointly owned by the partners of Birchwood and operated by Agro, uses steam from the Facility.
Birchwood has a 25-year coal supply agreement for the requirements of the Facility with Laurel Creek Co., Inc. ("Laurel"), Rockspring Development, Inc. ("Rockspring"), Neweagle Industries, Inc. (as assignee of AgipCoal Holding
USA, Inc.) and Neweagle Coal Sales Corp. (as assignee of AgipCoal Sales USA, Inc.) (collectively, "Neweagle"). Birchwood also has a back-up coal supply letter agreement with Arch Mineral Corp. ("Arch") and two of its subsidiaries, ACSC Coal Sales, Inc. ("ACSC") and Cumberland River Coal Company ("CRCC"), whereby Arch guarantees that ACSC and CRCC will supply coal to the Facility in the event of default by Neweagle under the coal supply agreement.
ER&L Birchwood, Inc. ("ER&LB"), a subsidiary of Energy Resources and Logistics, Inc. ("Energy Resources"), and an indirect subsidiary of CSX, provides transportation of the coal from the coal seller's mines in West Virginia to the Facility. ER&LB will use CSX's rail lines and equipment to meet its obligations under the 25-year coal transportation agreement. CSX by separate agreement assures full and complete performance of all of ER&LB's obligations under the coal transportation agreement.
The combined fuel and transportation cost under the coal supply agreement and the coal transportation agreement is approximately equal to the fuel compensation price that Birchwood receives under the power purchase agreement. Furthermore, Neweagle and ER&LB have agreed to the same price adjustment mechanism and redetermination formula included in the power purchase agreement for the fuel compensation price. In effect, this passes the fuel and transportation cost escalation risks from Birchwood through to the suppliers.
JTM Industries, Inc. ("JTM") removes and disposes of the ash generated by the Birchwood Facility under an ash removal contract that expires in 2021. JTM will attempt to identify viable markets to maximize the quantity of ash being used. JTM and Birchwood will develop a revenue sharing program in connection with the marketing of the ash.
The Birchwood Facility is financed pursuant to a senior credit facility which consists of a bank credit facility ($153.6 million outstanding at December 31, 1997), an institutional debt facility ($135.0 million outstanding at December 31, 1997), and $50 million of tax exempt debt. Cogentrix/Birchwood Two, L.P. has pledged its ownership interests in Birchwood and the greenhouse located adjacent to the Birchwood Facility as collateral security for the senior credit facility, however Cogentrix Energy, Inc. is not liable for any deficiency if the proceeds of any sale or disposition of the collateral are insufficient to pay the secured obligations.
PRINCIPAL CUSTOMERS
Electric utility customers accounting for more than ten percent of the Company's revenue for the six-month period ended December 31, 1997 and for each of the last three fiscal years were as follows:
COMPETITION
The demand for power in the United States traditionally has been met by utilities constructing large-scale electric generating plants under cost-of-service based regulation. The enactment of PURPA in 1978 spawned the growth of the independent power industry which expanded rapidly in the 1980s. The electric power industry is now in the midst of fundamental change, in terms of both who the participants are and how they operate and are regulated. The initial independent power producers to enter the market were an entrepreneurial group of cogenerators and small power producers who recognized the business opportunities offered by PURPA. This initial group of independent power producers, which included the Company, was later joined by larger, better-capitalized companies, such as subsidiaries of fuel supply companies, utility affiliates, engineering companies, equipment manufacturers and affiliates of other industrial companies. In addition, a number of regulated utilities created subsidiaries which compete with the independent power producers. Some independent power producers specialize in market niches, such as a specific technology or fuel (e.g., gas-fired cogeneration,
waste-to-energy, hydroelectric, geothermal, wind, solar, wood, coal and conservation) or a specific region of the country where they believe they have a market advantage.
Based on net ownership of total project megawatts in operation, the Company is among the larger independent power producers in the United States. Although the Company is an established leader in the independent power industry, other independent power producers and utility affiliates, including, among others, Enron Power Corp., Calpine Corporation, CalEnergy, The AES Corporation, Edison Mission Energy and U.S. Generating Company, have significantly larger capital resources available to them than the Company.
Over the past decade, obtaining a power sales agreement with a utility has become a progressively more difficult, expensive and competitive process. The Company and its competitors now must put a significant amount of financial resources at risk in order to develop a proposal or bid to a utility. Many states and utilities now have policies that require or encourage power sales agreements to be awarded by competitive bidding, which both increases the costs and decreases the chances of obtaining such agreements.
Amendments to the Public Utility Holding Company Act of 1935 ("PUHCA") enacted in the Energy Policy Act of 1992 have increased the number of the Company's competitors by reducing certain restrictions on the ownership of projects which are not QFs under PURPA. On the other hand, the Energy Policy Act has also made it simpler for developers to develop certain types of larger generation projects without the necessity of locating a steam host or developing a complex ownership structure to avoid PUHCA restrictions.
REGULATION
The Company is subject to federal, state and local energy and environmental laws and regulations applicable to the development, ownership and operation of its United States plants. Federal laws and regulations govern transactions with utilities, types of fuel utilized, the type of energy produced and power plant ownership. State regulatory commissions must approve the rates and, in some instances, other terms under which utilities purchase electricity from certain independent producers. Under certain circumstances, such state commissions may have broad jurisdiction over non-utility power plants. Power projects also are subject to laws and regulations governing environmental emissions and other substances produced by a plant, along with the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have state and local enforcement and implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before construction or operation of a power plant commences and that the facility operate in compliance therewith. The Company strives to comply with all environmental laws, regulations, permits and licenses but, despite such efforts, at times has been in non-compliance. No such instance of non-compliance has resulted in significant fines or revocation of any permit or license.
ENERGY REGULATIONS
QFs under PURPA.
Each of the Company's current operating facilities is a QF. QFs are relieved of compliance with extensive federal, state and local regulations that control the development, financial structure and operation of power plants and cost-of-service based ratemaking to determine the prices at which power generation facilities sell energy. In order to be a QF, a cogeneration facility must sequentially produce both electricity and useful thermal energy for non-mechanical or non-electrical uses in certain proportions to the facility's total useful energy output. A QF utilizing oil or natural gas as fuel also must meet certain energy efficiency standards. A small power production facility may be a QF if it uses certain alternative fuels as its primary energy input, subject to limitations on fossil fuel input and size for the facility. Finally, a QF must not be controlled or more than 50% owned by an electric utility or by an electric utility holding company, or a subsidiary of either or any combination thereof.
PURPA exempts QFs from PUHCA, most provisions of the Federal Power Act (the "FPA") and, except under certain limited circumstances, state rate and financial regulations. These exemptions are important to the Company and its competitors.
In the absence of a power sales agreement, FERC regulations require utilities to purchase electricity generated by QFs at a price based on the purchasing utility's full "avoided cost," and that the utility sell back-up power to the QF on a non-discriminatory basis. Avoided costs are the incremental costs to a utility of electric energy or capacity or both which, but for the purchase thereof from QFs, such utility would generate for itself or purchase from another source. Due to increasing competition for utility contracts, the current practice is for most power sales agreements to be awarded below avoided cost.
The Company endeavors to minimize the risk of its facilities losing their QF status. The occurrence of events outside the Company's control, such as loss of a steam customer, could jeopardize QF status. While the facilities usually would be able to react in a manner to avoid the loss of QF status by, for example, replacing the steam customer or finding another use for the steam which meets PURPA's requirements, there is no certainty that such action would be practicable or economic.
If one of the Company's facilities were to lose its status as a QF, the subsidiary would lose its exemptions from PUHCA and the FPA (and certain state laws and regulations). This could subject the subsidiary to regulation under the FPA and, in such event, would result in the Company inadvertently becoming a public utility holding company. The Company's other facilities could in turn lose their QF status. Moreover, loss of QF status could result in certain utility customers terminating their power sales agreement with the nonqualifying facility. If loss of QF status were threatened for a facility, the Company could avoid holding company status (and thereby protect the QF status of its other facilities) by applying to the FERC to obtain EWG status for the owner of the nonqualifying facility. See "EWGs under the Energy Policy Act" herein. Alternatively, the FERC may grant a limited waiver to the QF that would provide continued exemption under PUHCA, provided the facility's rates were regulated under the FPA.
EWGs under the Energy Policy Act.
The passage of the Energy Policy Act has significantly expanded the options available to independent power producers with respect to their regulatory status. In addition to (or in lieu of) QF status, an independent power producer selling exclusively at wholesale now can also apply to the FERC to be granted status as an EWG. Except for existing cost-of-service based facilities (for which state consents are required) any owner of a facility may apply for status as an EWG. An EWG (like a QF) is exempt from regulation under PUHCA. However, EWG status does not exempt a facility from FERC and state public utility commission ("PUC") regulatory reviews, which may be more expansive than those applicable to QFs. Birchwood, the owner of the Birchwood Facility, which is a QF, has also been determined to be an EWG.
Foreign Investments under the Energy Policy Act.
The Energy Policy Act has also expanded the options for companies that wish to invest in foreign enterprises that own power production facilities outside the United States. Amendments to PUHCA in the Energy Policy Act provide that a domestic company making such an investment may avoid "holding company" status or other regulation under PUHCA, if the foreign enterprise obtains EWG status or files a notice with the Commission that it is a foreign utility company ("FUCO").
PUHCA.
Under PUHCA, any entity owning or controlling ten percent or more of the voting securities of a "public utility company" is a "holding company" and is subject to registration with the Commission and regulation under PUHCA, unless eligible for an exemption. Under the Energy Policy Act and PURPA, EWGs, FUCOs, and owners and operators of QFs are deemed not to be public utility companies under PUHCA. The Securities and Exchange Commission ("SEC") has also determined that power marketers are not public utility companies under PUHCA. Momentum is growing in Congress for the repeal of PUHCA, as more legislators adopt the view that this statute has outlived its purpose. Elimination of PUHCA would enable more companies to consider owning generation and transmission assets, would permit "single state" utility systems to expand beyond their state borders, and would permit companies that are currently in registered holding company systems to diversify their investments to a greater extent than now permitted. This could attract more competitors to the power development and power marketing business. The Company believes that it is well positioned, however, to meet stronger competition and, indeed, may be able to pursue more investment opportunities made available by the repeal of PUHCA.
FPA.
The FPA grants the FERC exclusive rate-making jurisdiction over wholesale sales of electricity in interstate commerce, including ongoing as well as initial rate jurisdiction, which enables the FERC to revoke or modify previously approved rates. While QFs under PURPA are exempt from the traditional rate-making and certain other provisions of the FPA, projects not qualifying for QF status (for example, most EWGs) are subject to the FPA and to FERC rate-making jurisdiction. Power marketers are also subject to FERC review of their wholesale rates, and to FERC oversight of various business dealings such as corporate reorganizations. Pursuant to the FPA, the Company's power marketing subsidiary has filed its wholesale electric power rates with the FERC and obtained authorization to sell electric power at rates set by supply and demand in the marketplace.
State Regulation.
PUCs regulate retail rates of electric utilities and in certain cases power sales agreements from independent power producers. In addition, states have been delegated the authority to determine utilities' avoided costs under PURPA. PUCs often will pre-approve agreements with prices that do not exceed avoided costs, because such contracts often have been acquired through a competitive or market-based process. Recognizing the competitive nature of the acquisition process, many PUCs will permit utilities to "pass through" expenses associated with a power sales agreement with an independent power producer. In addition, retail sales of electricity or steam by an independent power producer may be subject to PUC regulation, depending on state law.
EWGs are subject to broad regulation by PUCs, ranging from the requirement of certificates of public convenience and necessity to regulation of organizational, accounting, financial and other corporate matters. In addition, states may assert jurisdiction over the siting and construction of EWGs (as well as QFs), and over the issuance of securities and the sale or other transfer of assets by these facilities. Many state utility commissions and state legislatures are actively seeking ways to lower electric power costs at the retail level, including options that would permit or compel competition at the retail level. Federal legislation that would require states to permit retail competition is also being given serious consideration. An opening of the retail market would create tremendous opportunities for companies that have until now been limited to the wholesale market. At the same time, state commissions are pressuring the utilities they regulate to cut purchased power costs through strict enforcement of existing contracts with QFs and EWGs, many of which are considered to be overpriced. Because the Company is in compliance with its QF contracts, it is not threatened by these pressures. State commissions are also encouraging efforts by utilities to buy out or buy down such contracts.
Proposed Legislation.
In addition to federal legislative initiatives, the state commissions or state legislatures of many states are considering, or have considered, whether to open the retail electric power market to competition (so-called "retail access" or "customer choice"). Such "customer choice" plans typically allow customers to choose their electricity suppliers by a certain date. Retail competition is possible when a customer's local utility agrees, or is required, to "unbundle" its distribution service (i.e., the delivery of electric power to retail customers through its local distribution lines) from its transmission and generation service.
The competitive price environment that will result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term power purchase contracts with QFs and EWGs (including the above-market rates, or "stranded investment" costs, provided for in such contracts). Many states will also provide that the stranded investment costs will be "securitized" through new financial instruments. On the other hand, QFs and EWGs may be subject to pressure to lower their contract prices or to renegotiate contracts in an effort to reduce the "stranded investment" costs of their utility customers.
Retail access programs may provide the Company with additional opportunities to provide power from the Company's projects to industrial users or power marketers. In addition, in light of the states' approaches to "stranded investment" costs, the Company does not believe retail access programs will have a material adverse effect on the Company's existing contracts.
Transmission and Wheeling.
Under the FPA, the FERC regulates the rates, terms and conditions for electricity transmission in interstate commerce. The FERC's authority under the FPA to require electric utilities to provide transmission service to QFs and EWGs was significantly expanded by the Energy Policy Act. Currently, none of the Company's facilities requires the wheeling of electricity over power lines owned by others. Except when market factors (such as an exceptional site or power sales opportunity) warrant it, the Company generally attempts to site its facilities within the utility customer's service area, and thus avoid the need to utilize wheeling. The new provisions of the Energy Policy Act, however, and actions taken by the FERC under the FPA have improved transmission access and pricing for independent power producers like the Company.
In April 1996, the FERC issued a rulemaking order under the FPA, Order 888, requiring all jurisdictional public utilities to file "open access" transmission tariffs. Compliance with Order 888 has been virtually universal. However, many utilities are seeking permission from the FERC to recover for "stranded investment" through add-ons to their transmission rates. To the extent that the FERC permits such charges, the cost of transmission may be too high on some systems to be of practical use to wholesale sellers like the Company. Therefore, the full value of Order 888 remains to be determined.
The FERC is also encouraging the voluntary restructuring of transmission operations through the use of independent system operators and regional transmission groups. Such entities may create efficiencies for traditional utilities, but are not likely to have a substantial impact on power developers and power marketers like the Company.
ENVIRONMENTAL REGULATIONS -- UNITED STATES
The construction and operation of power projects are subject to extensive environmental protection and land use regulation in the United States. Those regulations applicable to the Company primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, waste disposal and noise regulation. These laws and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits and approvals from federal, state and local agencies. If such laws and regulations are changed and the Company's facilities are not grandfathered, extensive modifications to project technologies and facilities could be required.
Although a number of major environmental statutes are scheduled for reauthorization, the Company expects that environmental regulations will continue to become more stringent as environmental regulations previously passed become implemented. Accordingly, the Company plans to continue a strong emphasis on implementation of environmental standards and procedures at its operating plants to minimize the environmental impact of its energy generation.
Clean Air Act.
In late 1990, Congress passed the Clean Air Act Amendments of 1990 (the "1990 Amendments") which affect existing facilities as well as new project development. The original Clean Air Act of 1970 set guidelines for emissions standards for major pollutants from newly-built sources. All of the Company's facilities perform at levels better than federal performance standards mandated for such facilities under the Clean Air Act. The 1990 Amendments attempt to reduce emissions from existing sources -- particularly large older facilities that were exempted from certain regulations under the original Clean Air Act.
The 1990 Amendments create a marketable commodity called a sulfur dioxide ("SO2") "allowance." All non-exempt facilities over 25 megawatts that emit SO2 (including independent power plants) must obtain allowances in order to operate after 1999. Each allowance gives the owner the right to emit one ton of SO2. The 1990 Amendments exempt from the SO2 allowance provisions all independent power projects which were operating, under construction or with power sales agreements (or letters of intent therefor) as of November 15, 1990, as well as facilities outside the contiguous 48 states. As a result, most of the Company's current operating facilities are exempt. The Company's non-exempt operating facilities have determined their need for allowances and have accounted for these requirements in their operating budgets and financial forecasts. In the future, the facilities the Company expects to develop will continue to rely on "clean (low sulfur) coal," with flue gas desulfurization technology or natural gas technology. The Company believes that the additional costs of obtaining the number of allowances needed for future projects should not materially affect the Company's ability to develop such
projects. There has also been an oversupply of allowances in the market resulting in a significant decrease in allowance prices.
The 1990 Amendments also require states to impose annual operating permit fees. While such permit fees may be substantial and will be greater for coal-fired projects than for those burning gas or certain other fuels, such fees are not expected to significantly increase the Company's plant operating costs.
The 1990 Amendments also contain other provisions that could affect the Company's projects. Provisions dealing with geographical areas the EPA has designated as in "nonattainment" with national ambient air quality standards require that existing sources of air pollutants in a nonattainment area be retrofit with reasonably available control technology ("RACT") for all pollutants for which an area is designated nonattainment. The technology currently installed at the Company's projects should uniformly meet or exceed RACT for all such pollutants. The nonattainment provisions also require that each new or expanded source of air pollutants in newly designated nonattainment areas which has not submitted a complete air permit application before November 15, 1992 must obtain emissions reductions from existing sources that more than offset the emissions from the new or expanded source. While the "offset" requirements may hamper new project development in certain geographical areas, development of new projects has and will likely continue, particularly as markets for "offsets" develop.
The 1990 Amendments also provide an extensive new operating permit program for existing sources called the Title V permitting program. Because all of the existing Company facilities were permitted under the Prevention of Significant Deterioration New Source Review Process, the permitting impact to the Company under the 1990 Amendments is expected to be minimal. Continuous emission monitoring systems may need to be upgraded at some facilities while the permit fees will increase operating expenses. The costs of applying for and obtaining operating air permits are not anticipated to be significant.
The hazardous air pollutant provisions of the 1990 Amendments presently exclude electric steam generating facilities, such as the Company's facilities. Three studies of the emissions from such facilities are, however, in progress. Until all of these studies are completed and Congress either amends the Clean Air Act further or the EPA promulgates regulations, the federal hazardous air pollutants emissions restrictions, which will be applied to the Company's facilities and other electric steam generating facilities, will remain uncertain.
In July 1997, the EPA promulgated more restrictive ambient air quality standards for ozone and particulate matter (less than 25 microns in diameter - PM-2.5). These new standards will likely increase the number of nonattainment areas for both ozone and PM-2.5. If the Company's plants are in these new nonattainment areas, further emission reduction requirements could result in the installation of additional control technology.
In addition, the Ozone Transport Assessment Group ("OTAG"), composed of state and local air regulatory officials from the 37 eastern states, has recommended additional NOx emission reductions that go beyond current federal standards. These recommendations include reductions from utility and industrial boilers. In the fall of 1997, the EPA proposed a call for revisions to state implementation plans ("SIPs"). This SIP call implements some of the OTAG's recommendations and goes beyond some of OTAG's recommendations for reductions in NOx emissions. If more stringent NOx emission standards are adopted by the EPA and/or certain states as a result of these recommendations, the Company could be required to install additional NOx emission control technologies and/or obtain allowances from other emitters.
The Company does not believe that any of the potential additional requirements discussed above will have a material adverse effect on the operations or financial position of the Company.
The 1990 Amendments expand the enforcement authority of the federal government by increasing the range of civil and criminal penalties for violations of the Clean Air Act and enhancing administrative civil penalties and adding a citizen suit provision. These enforcement provisions also include enhanced monitoring, recordkeeping and reporting requirements for existing and new facilities. On February 13, 1997, the EPA issued a regulation providing for the use of "any credible evidence or information" in lieu of, or in addition to, the test methods prescribed by regulation to determine the compliance status of permitted sources of air pollution. This rule may effectively make emission limits previously established for many
air pollution sources, including the Company's, more stringent. On March 10, 1997, a number of utilities filed a petition for review of the EPA regulations in the U.S. Court of Appeals for the District of Columbia Circuit.
The Kyoto Protocol regarding greenhouse gas emissions and global warming was signed by the U.S. committing to significant reductions in greenhouse gas emissions. The U.S. Senate must ratify the agreement for the protocol to take effect. The Clinton Administration has proposed a package of legislative and administrative policies to curb greenhouse gases, none of which are affected by the need for Senate ratification. Management believes that none of these policies will have a material effect on the consolidated results of operations or financial position of the Company. Future initiatives on this issue and the effects on the Company are unknown at this time.
Clean Water Act.
The Company's existing facilities are subject to a variety of state and federal regulations governing existing and potential water/wastewater and stormwater discharges from the facilities. Generally, federal regulations promulgated through the Clean Water Act govern overall water/wastewater and stormwater discharges through NPDES permits. Under current provisions of the Clean Water Act, existing permits must be renewed every five years, at which time permit limits are under extensive review and can be modified to account for more stringent regulations. In addition, the permits have re-opener clauses which can be used to modify a permit at anytime. Several of the Company's facilities have either recently gone through permit renewal or will be renewed within the next few years. Based upon recent renewals, the Company does not anticipate more stringent monitoring requirements.
Emergency Planning and Community Right-to-Know Act.
In April of 1997, the EPA expanded the list of industry groups required to report the Toxic Release Inventory ("TRI") under Section 313 of the Emergency Planning and Community Right-to-Know Act ("EPCRA") to include electric utilities. The Company's operating plants will be required to complete a toxic chemical inventory release form for each listed toxic chemical manufactured, processed or otherwise used in excess of threshold levels for the 1998 reporting year. The purpose of this requirement is to inform the EPA, states, localities and the public about releases of toxic chemicals to the air, water and land that can pose a threat to the community.
ENVIRONMENTAL REGULATIONS -- INTERNATIONAL
Although the type of environmental laws and regulations applicable to independent power producers and developers varies widely from country to country, many foreign countries have laws and regulations relating to the protection of the environment and land use which are similar to those found in the United States. Laws applicable to the construction and operation of electric power generation facilities in foreign countries generally regulate discharges and emissions into water and air and also regulate noise levels. Air pollution laws in foreign jurisdictions often limit the emissions of particulates, dust, smoke, carbon monoxide, sulfur dioxide, nitrogen oxide and other pollutants. Water pollution laws in foreign countries generally limit wastewater discharges into municipal sewer systems and require treatment of wastewater which does not meet established standards. New projects and modifications to existing projects are also subject, in many cases, to land use and zoning restrictions imposed in the foreign country. In addition, developers of foreign independent power projects often conduct environmental impact assessments of proposed projects pursuant to existing legislative requirements. Certain lenders to international development projects may impose their own requirements relating to the protection of the environment.
The Company believes that the level of environmental awareness and enforcement is growing in most countries, including most of the countries in which the Company intends to develop and operate new projects. As a result, plants built overseas will likely include pollution control equipment that is required in the United States. Therefore, based on current trends, the Company believes that the nature and level of environmental regulation that it is subject to will become increasingly stringent, whether the Company undertakes new projects in foreign countries or in the United States.
EMPLOYEES
At December 31, 1997, the Company employed 470 people, approximately 286 of whom are involved in facility operations and 92 of whom are involved in ash disposal operations. No employees are covered by a collective bargaining agreement.
ITEM 2.
ITEM 2. PROPERTIES
In addition to the Company's properties listed under Item 1. "Business - -- Description of the Company's Facilities," the Company leases its principal executive office, a single 61,024 square foot building, located at 9405 Arrowpoint Boulevard in Charlotte, North Carolina. The Company leases the building and related land from a partnership comprised of four of the Company's shareholders. The building lease has an initial term ending in 2004, with optional renewals through 2047. The term of the land lease extends through 2047. See "Certain Transactions."
The Company also leases office space in Prince George, Virginia; Portland, Oregon; Singapore; Bangalore, India; Mangalore, India and New Delhi, India, none of which leases or leased premises are material.
The Company believes that its facilities and properties have been satisfactorily maintained, are in good condition, and are suitable for the Company's operations.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Under the terms of the amended power sales agreements for the Elizabethtown, Lumberton, Kenansville, Roxboro and Southport Facilities, the purchasing utility, CP&L, has exercised its right of economic dispatch resulting in significantly reduced fuel requirements at each of these facilities. Coal is supplied to the ELK Facilities by James River Coal Sales, Inc. ("James River") and its affiliate, Bell County Coal Corporation. Coal is supplied to the Southport Facility by Coastal Coal Sales, Inc. ("Coastal"). The coal sales agreements for both the ELK Facilities and the Southport Facility provide for the sale and purchase of the coal requirements of those facilities through the respective contract term.
Under the amended power sales agreement for the Company's Portsmouth Facility, Virginia Power has from time to time since December 1997 exercised its right of economic dispatch resulting in significantly reduced fuel requirements at the facility. Coal is supplied to the Portsmouth Facility by Arch Coal Sales Company, Inc. ("Arch"). The coal sales agreement with Arch provides for the sale and purchase of the coal requirements of the Portsmouth Facility during the period extending 15 years from late 1987, the year of commencement of commercial operations at the facility.
As a result of the economic dispatch of these facilities and their consequent reduced fuel requirements, the Company's project subsidiaries operating these facilities are purchasing significantly less coal. James River, Coastal and Arch have each initiated either a civil action or an arbitration proceeding seeking to recover damages and, in some cases, seeking injunctive relief. A summary of each of these pending disputes is set forth below.
JAMES RIVER DISPUTE (ELK FACILITIES)
In November 1996, James River and its affiliate instituted an action in the United States District Court for the Eastern District of Kentucky against CECC claiming breach of contract and fraud in the inducement based on the reduction in fuel requirements at the ELK Facilities. In this complaint, James River and its affiliate sought specific performance and, in the alternative, an unspecified amount of damages.
CECC filed a motion to dismiss the complaint for (i) lack of jurisdiction and (ii) failure to state a claim upon which relief can be granted. Prior to the court ruling on the motion, the case was transferred in September 1997 to the United States District Court, Western District of North Carolina. The CECC motion to dismiss was taken up by the North Carolina court, which by order dated January 8, 1998 denied the motion to dismiss count I (breach of contract) and granted the motion to dismiss count II (fraud in the inducement). James River filed an amended complaint on January 29, 1998, and CECC refiled its motion to dismiss count II of the amended complaint on February 24, 1998. The motion to dismiss is under consideration by the court.
The coal sales agreement for the ELK Facilities contains an arbitration provision requiring contract disputes to be submitted to arbitration in Charlotte, North Carolina. Upon resolution of the pending Motion, CECC may seek enforcement of that provision.
COASTAL DISPUTE (SOUTHPORT FACILITY)
In October 1996, Coastal initiated an arbitration proceeding against CNC through the American Arbitration Association in Charlotte, North Carolina. The notice of arbitration alleged breach of contract based on the reduction in fuel requirements at the Southport Facility. The arbitration was conducted by a three-member panel during the period September 30 through October 3, 1997, and an arbitration award was rendered on October 22, 1997 in favor of CNC denying any recovery to Coastal ("Arbitration Award").
On January 20, 1998, ANR Coal Company, L.L.C. ("ANR"), as successor to Coastal, filed a complaint in United States District Court for the Western District of North Carolina (the "Court") seeking an order vacating the Arbitration Award. The principal basis of the complaint is an allegation that the impartial third arbitrator of the panel was improperly biased and failed to make complete disclosure of pertinent information during the selection process. CNC filed its motion to dismiss, motion to confirm and answer on February 17, 1998. The matter is currently under consideration by the Court. CNC does not believe the allegations of ANR in the complaint are meritorious or provide a basis upon which the Court could properly vacate the Arbitration Award.
ARCH DISPUTE (PORTSMOUTH FACILITY)
In March 1998, Arch filed a complaint in the United States District Court, Southern District of West Virginia against the Company's project subsidiary that owns and operates the Portsmouth Facility alleging a breach of contract. In the complaint, Arch seeks a determination that CVLC (i) is obligated to purchase approximately 360,000 tons of coal per year, (ii) breached the Coal Agreement by wrongfully reducing its requirements of coal, and (iii) violated a duty of good faith and fair dealing owed to Arch. Arch also seeks a determination that CVLC is obligated to purchase approximately 360,000 tons of coal per year and damages for CVLC's failure to purchase such quantities of coal.
The claims made by Arch directly contradict the clear, overriding provisions of the coal sales agreement, which specifically provide that notwithstanding any provision in the agreement to the contrary, CVLC shall not be obligated to purchase more than the Portsmouth Facility's requirements of coal. Furthermore, the coal agreement contains an arbitration clause, which the Company believes is enforceable, that requires any disputes between the parties to be resolved by arbitration in Charlotte, North Carolina.
The Company is confident that the claims made by Arch against CVLC will ultimately be resolved in favor of CVLC. CVLC will vigorously defend the matter, seek to enforce the terms of the agreement against Arch, including the arbitration clause, and otherwise continue to perform under the agreement as required.
SUMMARY OF COAL PURCHASE AGREEMENT DISPUTES
Management believes that, as to the James River and Arch suits, there is no basis for certain claims and there are meritorious defenses as to the remainder. Management believes the Coastal Arbitration Award was the product of an arbitration process that was entirely proper and in accordance with American Arbitration Association guidelines and procedures. The Company intends to vigorously contest the actions of James River, Arch and ANR (Coastal) and is confident that they will be resolved in favor of the Company. The Company has established reserves which management believes to be adequate to cover any costs which may result from these matters. The ultimate disposition of the James River, Arch and ANR (Coastal) actions, in the judgement of management, will not have a material adverse impact on the Company's consolidated results of operations or financial position.
OTHER ROUTINE LITIGATION
In addition, the Company experiences routine litigation in the normal course of business. Management is of the opinion that none of this routine litigation will have a material adverse impact on the consolidated financial position or results of operations of the Company.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS
(a) Market Information - There is no established market for the Company's common stock, which is closely held.
(b) Principal Shareholders - All of the issued and outstanding shares of common stock of the Company are beneficially owned by the six persons listed in Item 12 of this report.
(c) Dividends - For the fiscal year ended June 30, 1997, the Company's board of directors declared a dividend on its outstanding common stock of $5.0 million, which was paid in September 1997. The Company's board of directors declared a dividend on its outstanding common stock of $2.1 million for the six-month period ended December 31, 1997, which was paid in March 1998. The board of directors has adopted a policy, which is subject to change at any time, of maintaining a dividend payout ratio of no more than 20% of the Company's net income for the immediately preceding fiscal year. In addition, under the terms of the Indenture of the Senior Notes and a revolving credit facility agreement, the Company's ability to pay dividends and make other distributions to its shareholders is restricted.
ITEM 6.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth certain selected consolidated financial data as of and for the six-month period ended December 31, 1997 and the five years ended June 30, 1997, which should be read in conjunction with the Company's consolidated financial statements and related notes thereto and with "Management's Discussion and Analysis of Financial Condition and Results of Operations." The selected consolidated financial data as of and for the six-month period ended December 31, 1997 and each of the five years in the period ended June 30, 1997 set forth below has been derived from the consolidated financial statements of the Company, which were audited by Arthur Andersen LLP, independent public accountants.
Effective January 1, 1998, the Company changed its fiscal year to commence on January 1 and conclude on December 31 of each year. The Company's fiscal year previously commenced each July 1, concluding on June 30 of the following calendar year.
(1) Project financing debt with respect to each of the Company's facilities is "substantially non-recourse" to Cogentrix Energy, Inc. and its other project subsidiaries. For a discussion of the term "substantially non-recourse," see "Business -- Description of the Company's Facilities -- Project Financing" herein.
(2) Parent debt represents obligations of Cogentrix Energy, Inc. only and does not include non-recourse obligations of the Company's project subsidiaries.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition to discussing and analyzing the Company's recent historical financial results and condition, the following "Management's Discussion and Analysis of Financial Condition and Results of Operations" includes statements concerning certain trends and other forward-looking information affecting or relating to the Company which are intended to qualify for the protections afforded "Forward-Looking Statements" under the Private Securities Litigation Reform Act of 1995, Public Law 104-67. The forward-looking statements made herein and elsewhere in this Form 10-K are inherently subject to risks and uncertainties which could cause the Company's actual results to differ materially from the forward-looking statements. See cautionary statements appearing above, under "Item 1. Business" and elsewhere in this Form 10-K for a discussion of the important factors affecting the realization of those results.
GENERAL
The Company is engaged in the acquisition, development, ownership, and operation of power generation facilities and the sale of electricity and steam in the United States and selected international markets. The Company owns (entirely or in part) eleven power generation facilities having an aggregate generating capacity of 1,120 megawatts. In March 1998, the Company acquired an ownership interest in two gas-fired power generation facilities in the Midwest United States, having an aggregate generating capacity of 490 megawatts. In addition, the Company has a pending acquisition, subject to the fulfillment of all required conditions, of ownership interests in twelve power generation facilities in Florida and the Northeastern United States, comprising an aggregate generating capacity of approximately 2,400 megawatts. Upon completion of the pending acquisition, the Company's net interest in power generation facilities will be 1,675 megawatts, an increase from 840 megawatts in 1994.
Each of the Company's generating facilities relies on a power sales agreement for the majority of its revenues. During the six-month period ended December 31, 1997, two regulated utilities, CP&L and Virginia Power, accounted for approximately 85% of the Company's consolidated revenues. As the result of the Company's recent growth, the Company's operations will become more diverse with regard to both geography and fuel source and will become less dependent on any single project or customer.
Each of the Company's power generation facilities produces electricity for sale to a utility and thermal energy for sale to an industrial user. The electricity and thermal energy generated by these facilities are typically sold under long-term power or steam sales agreements, generally having original terms of 20 to 30 years. Several of the Company's generating facilities originally sold electricity under long-term must-run power sales agreements, which obligated the utility to purchase all electricity generated by the power generation facility. Over the last two years, the Company has amended the majority of these must-run power sales agreements to provide the utility the ability to suspend or reduce purchases of energy from the facilities if the utility determines it can operate its system for a designated period more economically. These amended power sales agreements are structured such that the Company continues to receive capacity payments during any period of economic dispatch. Capacity payments cover project debt service, fixed operating costs, and constitute a substantial portion of the profit component of the power sales agreement. Energy payments, which are reduced (or possibly eliminated) as a result of economic dispatch, primarily cover variable operating and maintenance costs as well as fuel and fuel transportation costs. The restructuring of a must-run power sales agreement to an economic dispatch power sales agreement causes a significant reduction in electric revenues recognized under the contract, which is offset by a corresponding reduction in fuel cost and operations and maintenance expense. In response to the reduction in fuel requirements at certain of the facilities at which the Company has restructured the power sales agreement, the facilities' coal suppliers have instituted various legal proceedings against the Company seeking to recover damages. See "Legal Proceedings" herein.
Certain of the Company's power sales agreements either terminate in years 2000 through 2002 or provide for a significant reduction in capacity payments received under such agreements after 2002. Accordingly, revenues recognized by the Company under these power sales agreements after 2002 will be eliminated or significantly reduced.
The activities of the Company are subject to stringent environmental regulations by federal, state, local and (for future non-U.S. projects) foreign governmental authorities. The Clean Air Act Amendments of 1990 require states to impose permit fees on certain emissions, and Congress may consider proposals to restrict or tax certain emissions, which proposals, if adopted, could impose additional costs on the operation of the Company's facilities. There can be no assurance that the Company's business and financial condition would not be materially and adversely affected by the cost of compliance with future changes in domestic or foreign environmental laws and regulations or additional requirements for reduction or control of emissions imposed by regulatory authorities in connection with renewals of required permits. The Company maintains a comprehensive program to monitor its project subsidiaries' compliance with all applicable environmental laws, regulations, permits and licenses.
The domestic power generation industry is currently going through a period of significant change as many states are implementing or considering regulatory initiatives designed to increase competition. In addition to restructuring activities in various states, there have also been several industry restructuring bills introduced in Congress (see Item 1. Business - Regulation). The Company cannot predict the final form or timing of the proposed restructurings and the impact, if any, that such restructurings would have on the Company's existing business or consolidated results of operations. The Company believes that any such restructuring would not have a material adverse effect on its power sales agreements and, accordingly, believes that its existing business and results of consolidated operations would not be materially adversely affected, although there can be no assurance in this regard.
In 1996, the Company began making investments in partnerships formed to develop, construct and operate greenhouses to produce tomatoes. These partnerships are currently operating greenhouses with a combined total of 107 acres of production capacity. The Company has a 50% interest in each of these partnerships and accounts for these investments under the equity method.
RESULTS OF OPERATIONS
The following table sets forth the results of operations and percentage of total operating revenues represented by the components of operating revenues and expenses for the six-month period ended December 31, 1997 and 1996 (unaudited) and the years ended June 30, 1997 and 1996.
Six-Month Period Ended December 31, 1997 as compared to the Six-Month Period Ended December 31, 1996
Total operating revenues decreased 1.8% to $177.9 million for the six-month period ended December 31, 1997 as compared to $181.1 million for the six-month period ended December 31, 1996. This decrease was primarily attributable to the significant decrease in electric revenues resulting from the amendment in September, 1996, of the Company's power sales agreements with CP&L on the Elizabethtown, Lumberton, Kenansville, Roxboro, and Southport Facilities. The decrease in operating revenues was also due to a decrease in steam revenues at the Hopewell and Southport Facilities resulting from a decrease in demand for steam by the Facilities' steam hosts. These decreases in operating revenues were partially offset by a $4.5 million construction management fee earned by the Company in December, 1997, related to the construction of an electric generation facility for Clark, as well as a $3.1 million increase in electric revenues at the Rocky Mount and Portsmouth Facilities. The increase in electric revenues at the Rocky Mount Facility was due to an increase in on-peak megawatt hours provided to the purchasing utility, while the increase in electric revenues at the Portsmouth Facility was mainly attributable to the restructured power sales agreement with the purchasing utility eliminating Portsmouth's accrued obligation to return previously disallowed capacity payments to the purchasing utility. The decreases in operating revenues were also offset by a $0.8 million increase in income from unconsolidated investments in power projects which was primarily the result of earnings generated by the Company's investment in the Birchwood Facility, which commenced commercial operations in November 1996. This increase in earnings was partially offset by the impact of the Company selling its investment in Bolivian Power Company Limited ("Bolivian Power") in December 1996. The Company recognized approximately $427,000 in income from unconsolidated investments in power projects during the six-month period ended December 31, 1996 related to its investment in Bolivian Power.
Operating costs decreased 13.5% to $93.7 million for the six-month period ended December 31, 1997 as compared to $108.3 million for the six-month period ended December 31, 1996. This decrease resulted primarily from the significant decrease in operating expenses at the Elizabethtown, Lumberton, Kenansville, Roxboro, and Southport Facilities resulting from their economic dispatch by CP&L. The decrease in operating expense was also due to reductions in maintenance costs at the Rocky Mount Facility, at which Facility the Company performed routine maintenance during the six-month period ended December 31, 1996. The decrease in operating costs was also related to transaction costs incurred in connection with project debt refinancings completed during the six-month period ended December 31, 1996, and severance costs incurred by
the Lumberton, Elizabethtown, Kenansville, Roxboro, and Southport Facilities in the six-month period ended December 31, 1996 associated with the reduction of the workforce at those Facilities due to the amendment of their power sales agreements. These decreases were partially offset by an increase in operating costs incurred by ReUse related to an increase in third party ash services activity during the six-month period ended December 31, 1997 and an increase in maintenance costs at the Portsmouth Facility related to routine maintenance performed during the six-month period ended December 31, 1997.
General, administrative and development expenses increased 13.9% to $18.2 million for the six-month period ended December 31, 1997 as compared to $16.0 million for the six-month period ended December 31, 1996. The increase in general, administrative and development expenses related primarily to incentive compensation expense incurred in December 1997 related to the successful completion of the Clark Facility. The increase was also attributable to severance costs incurred during the six-month period ended December 31, 1997 related to the reduction of the workforce at the corporate office.
During the six-month period ended December 31, 1996, the Company undertook an analysis of the post-contract operating environment for all of its operating facilities in light of the dramatic market changes taking place in the power generation industry. As a result of this analysis, the Company recorded a loss on impairment of cogeneration facilities of $57.3 million and recognized an $8.3 million liability related to the Company's estimated cost of removal obligations under certain land leases (see discussion below under "Fiscal Year Ended June 30, 1997 as compared to Fiscal Year Ended June 30, 1996"). Also, as part of this analysis the Company reviewed the depreciable lives of its operating facilities and concluded that, effective January 1, 1997, the Lumberton, Elizabethtown, Kenansville, Roxboro, and Southport Facilities would be depreciated over the remaining terms of these Facilities' power sales agreements. The 9.7% increase in depreciation and amortization expense in the six-month period ended December 31, 1997 as compared to the six-month period ended December 31, 1996 related primarily to this change in the estimated useful lives of these facilities.
The decrease in investment and other income for the six-month period ended December 31, 1997 as compared to the six-month period ended December 31, 1996 is due to the Company recognizing a one-time gain on the sale of its investment in Bolivian Power in December 1996. The Company sold its investment in Bolivian Power to NRG Generating Holdings (No. 9), B.V., a wholly owned subsidiary of NRG Energy, Inc. ("Holdings"), pursuant to a cash tender offer which Holdings made for all the outstanding common stock of Bolivian Power at a price of $43 per share. The Company recognized a $3.1 million gain on the sale of its investment in Bolivian Power, net of transaction costs, which included payments made to certain unaffiliated individuals who performed development activities for Bolivian Power.
Interest expense decreased 8.75% to $25.7 million for the six-month period ended December 31, 1997 as compared to $28.1 million for the six-month period ended December 31, 1996. The decrease in interest expense was primarily attributable to a decrease in the weighted average debt outstanding from $719 million for the six-month period ended December 31, 1996 to $680 million for the six-month period ended December 31, 1997. The decrease in weighted average debt outstanding related to scheduled maturities of the Company's project financing debt.
Equity in net loss of affiliates increased to $1.8 million for the six-month period ended December 31, 1997 as compared to $1.1 million for the six-month period ended December 31, 1996. The increase in equity in net loss was primarily attributable to the Company recognizing its share of losses from its investments in greenhouse facilities in Texas, Pennsylvania, and New York during the six-month period ended December 31, 1997. These greenhouse facilities were either not yet in commercial operation, had just started commercial operation or the Company did not yet hold an investment interest in them during the six-month period ended December 31, 1996. The increase in equity in net loss of affiliates was partially offset by a reduction in development costs associated with the termination in December 1996 of funding for a partnership pursuing development opportunities in Latin America.
The increase in minority interest in income of joint venture for the six-month period ended December 31, 1997 as compared to the six-month period ended December 31, 1996 related to an increase in the net income of the Hopewell Facility. The increase in net income of the Hopewell Facility related primarily to a reduction of maintenance costs incurred at the Hopewell facility during the six-month period ended December 31, 1997 as compared to the six-month period ended December 31, 1996. The increase in net income is also due to a reduction in the amount of interest expense incurred during the six-month period ended December 31, 1997 as compared to the six-month period ended December 31, 1996 related to a
decrease in the amount of project debt outstanding at the Hopewell Facility, and transaction costs incurred in connection with the refinancing of Hopewell's project debt during the six-month period ended December 31, 1996.
The extraordinary loss on early extinguishment of debt for the six-month period ended December 31, 1997 related to the refinancing of the Portsmouth Facility's project debt in December, 1997. The loss consisted of a write-off of the deferred financing costs on the Portsmouth Facility's original project debt and net swap termination fees on interest rate swap agreements hedging the original project debt. The extraordinary loss on early extinguishment of debt for the six-month period ended December 31, 1996 related to the write-off of the deferred financing costs on the Elizabethtown, Lumberton, and Kenansville Facilities' original project debt, which was refinanced in September 1996.
The provision for income taxes for the six-month period ended December 31, 1997 represented an effective rate of 39.6% of income before income taxes as compared to an effective rate of 38.3% of loss before benefit for income taxes for the six-month period ended December 31, 1996. The increase in effective rate for the six-month period ended December 31, 1997 related to a reduced recognition of losses for state income tax purposes in the prior year. A more complete discussion of income taxes is included in Note 7 of Notes to Consolidated Financial Statements.
Fiscal Year Ended June 30, 1997 as compared to Fiscal Year Ended June 30, 1996
Total operating revenues decreased 14.1% to $352.8 million for fiscal 1997 as compared to $410.5 million for fiscal 1996. This decrease was primarily attributable to the significant decreases in electric revenues resulting from economic dispatch of, and consequently reduced energy payments from, the Elizabethtown, Lumberton, Kenansville, Roxboro and Southport Facilities. The decrease in operating revenues is also attributable to the absence of revenue in fiscal 1997 comparable to (i) the payment received in fiscal 1996 upon the execution of a joint development agreement with CLP related to the development of the Company's India project, (ii) the $5 million fee earned by the Company in fiscal 1996 related to the pre-construction development phase of an electric generation facility for Clark and (iii) the $7.5 million capacity buydown payment received in fiscal 1996 from the utility purchasing the electrical output of the Hopewell Facility. To a lesser extent, the decrease in operating revenues was also attributable to a $1.5 million decrease in steam revenues at the Hopewell, Kenansville and Richmond Facilities resulting from a decrease in demand for steam by these Facilities' steam hosts and a $2.7 million decrease in electric revenue at the Richmond and Rocky Mount Facilities resulting from a decrease in megawatt hours sold to the purchasing utility. The decrease in operating revenues was also due to a net decrease in income from unconsolidated investments in power projects which was primarily attributable to the Company selling its investment in Bolivian Power in December 1996. The Company recognized approximately $3.9 million in income from unconsolidated investments in power projects in fiscal 1996 related to Bolivian Power, which included the Company's share of a one-time gain recognized by Bolivian Power on the sale of its distribution assets. This decrease in income from unconsolidated investments was partially offset by earnings generated by the Company's investment in the Birchwood Facility, which commenced commercial operations in November 1996. These decreases in operating revenues were partially offset by a $4.6 million increase in electric revenues at the Hopewell and Portsmouth Facilities due to an increase in on-peak megawatt hours provided to the purchasing utility, as well as escalation/inflation adjustment provisions in certain power sales agreements.
Operating costs decreased 16.8% to $204.4 million for fiscal 1997 as compared to $245.6 million for fiscal 1996. This decrease resulted primarily from the significant decrease in operating expenses at the Elizabethtown, Lumberton, Kenansville, Roxboro and Southport Facilities resulting from their economic dispatch by CP&L, as well as a decrease in fuel expense at the Richmond and Rocky Mount Facilities associated with a decrease in megawatt hours sold. The decrease in operating expense is also due to reductions in maintenance costs at the Hopewell, Portsmouth and Southport Facilities, at which Facilities the Company performed routine maintenance during fiscal 1996. These decreases were partially offset by an increase in maintenance costs at the Richmond Facility associated with routine maintenance performed in fiscal 1997 and an increase in operating costs incurred by ReUse related to third-party agreements and expense associated with a payment due to a deceased officer's beneficiary in fiscal 1997.
General, administrative and development expenses increased 31.5% to $39.4 million for fiscal 1997 as compared to $29.9 million for fiscal 1996. The increase was primarily the result of $10.7 million of payments made in connection with restructuring or terminating incentive compensation arrangements for certain employees, an increase in performance bonuses paid and severance payments made to certain executive officers in fiscal 1997. These increases were partially offset by a
reduction in payments made under the profit-sharing plan, due to a net loss before tax, a reduction in development expenses incurred on a project the Company is developing in Idaho, as well as a general reduction in consulting expenses related to development.
During fiscal 1997, the Company undertook an analysis of the post-contract operating environment for all of its operating facilities in light of the dramatic market changes that are taking place in the power generation industry. The analysis included assumptions regarding future levels of operations, operating costs and market prices for equivalent generation available from other sources. As a part of this analysis, in accordance with the Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," the Company assessed whether any impairment of the Company's facilities had occurred. This assessment included comparing the projected future cash flows to be provided by these assets to the net book value of such assets. Based on this assessment, the Company determined that an impairment loss had occurred on the Elizabethtown, Lumberton, Kenansville and Ringgold Facilities. This loss on impairment of cogeneration facilities of $57.3 million, recorded in fiscal 1997, represented the excess of the net book value of these cogeneration facilities over their current fair value, determined by discounting to present value projected future cash flows to be provided by such assets. The Company believes that its projections of future cash flows are based upon reasonable assumptions about the future performance of these assets. Because of the risks and uncertainties associated with any projections, there can be no assurances, however, that actual events will be consistent with the assumptions made, and future cash flows may be greater or less than those projected.
The Company's analysis of the post-contract operating environment also resulted in the recognition of an $8.3 million liability related to the Company's estimated cost of removal obligations under the land leases for the Elizabethtown, Lumberton and Kenansville Facilities. The total impairment loss and cost of removal of $65.6 million has been reflected in the statement of operations for the year ended June 30, 1997. Also in connection with the overall assessment of the post-contract operating environment for its cogeneration facilities, the Company concluded that, effective January 1, 1997, the Lumberton, Elizabethtown, Kenansville, Roxboro and Southport Facilities would be depreciated over the remaining term of these Facilities' power sales agreements. The 5.8% increase in depreciation and amortization expense in fiscal 1997 as compared to fiscal 1996 related primarily to this change in the estimated useful lives of these facilities.
The 3.5% decrease in interest expense is a result of the decrease in the weighted average debt outstanding from $739 million in fiscal 1996 to $704 million in fiscal 1997. The decrease in weighted average debt outstanding, which related to scheduled maturities of the Company's project finance debt and the repayment of the subordinated debt at the Elizabethtown, Lumberton and Kenansville Facilities, was partially offset by an increase in project debt outstanding at the Hopewell Facility and the Roxboro and Southport Facilities, which related to refinancings completed during fiscal 1997.
Investment income increased 76.3% to $13.2 million for fiscal 1997 as compared to fiscal 1996. The increase in investment income was related to larger cash and investment balances maintained by the Company during fiscal 1997 as compared to fiscal 1996, the recognition of a net loss on the sale of marketable securities of approximately $900,000 during fiscal 1996 and the $3.1 million gain on the sale (discussed below) of an investment during fiscal 1997.
In December 1996, the Company sold its investment in Bolivian Power Company Limited ("Bolivian Power") to NRG Generating Holdings (No. 9), B.V., a wholly owned subsidiary of NRG Energy, Inc. ("Holdings"), pursuant to a cash tender offer which Holdings made for all the outstanding common stock of Bolivian Power at a price of $43 per share. The Company recognized a $3.1 million gain on the sale of its investment in Bolivian Power, net of transaction costs, which included payments made to certain unaffiliated individuals who performed development activities for Bolivian Power.
The decrease in equity in net loss of affiliates to $800,000 for fiscal 1997 as compared to equity in net loss of $1.8 million in fiscal 1996 was primarily due to a reduction in development costs associated with the termination in December 1996 of funding for a partnership pursuing development opportunities in Latin America. The decrease in equity in net loss in fiscal 1997 was also due to earnings generated by the Company's investment in a greenhouse facility in Texas which commenced commercial operations in November 1996.
The decrease in minority interest in income of joint venture in fiscal 1997 as compared to fiscal 1996 related to the decrease in net income of the Hopewell Facility. The decrease in net income of the Hopewell Facility in turn resulted primarily from the absence of revenue in fiscal 1997 comparable to the $7.5 million capacity buydown payment received in
fiscal 1996 from the utility purchasing the electrical output of the Hopewell Facility. This decrease was partially offset by a reduction in maintenance costs incurred at the Hopewell Facility in fiscal 1997 as compared to fiscal 1996.
The benefit for income taxes for fiscal 1997 represented an effective rate of 38.3% of loss before benefit for income taxes as compared to an effective rate of 40.1% of income before income taxes for fiscal 1996. The decrease in the effective rate in fiscal 1997 related to the reduced recognition of current year losses for state income tax purposes. A more complete discussion of income taxes is included in Note 7 of Notes to Consolidated Financial Statements.
The extraordinary loss on early extinguishment of debt in fiscal 1997 related to the write-off of the deferred financing costs on the Elizabethtown, Lumberton and Kenansville Facilities' original project debt, which was refinanced in September 1996.
LIQUIDITY AND CAPITAL RESOURCES
The principal components of operating cash flow for the six-month period ended December 31, 1997 were generated by net income of $10.7 million, increases due to adjustments for depreciation and amortization of $20.4 million, deferred income taxes of $4.6 million, write-off of deferred financing costs of $1.4 million, minority interest in income of joint venture of $.8 million, and distributions from and equity in net loss of unconsolidated affiliates of $9.1 million, which were partially offset by a net $5.2 million use of cash reflecting changes in other working capital assets and liabilities. Cash flow provided by operating activities of $41.8 million, proceeds from project finance borrowings of $62.7 million, and $3.1 million of cash escrows released were primarily used to purchase property, plant and equipment additions of $.7 million, to purchase marketable securities of $.8 million, to make investments in a greenhouse facility of $2.7 million, to provide $.9 million of funds to a development joint venture company, to pay deferred financing costs of $1.5 million, to repay project finance borrowings of $86.8 million and to pay a dividend to common shareholders of $5.0 million.
The principal components of operating cash flow for the fiscal year ended June 30, 1997 were generated by a net loss of $28.3 million, increases due to adjustments for depreciation and amortization of $40 million, loss on impairment and cost of removal of cogeneration facilities of $65.6 million, extraordinary loss on early extinguishment of debt of $1.2 million, distributions from and equity in net loss of unconsolidated affiliates of $7.4 million and a net $16.5 million source of cash reflecting changes in other working capital assets and liabilities, which were partially offset by deferred taxes of $27.6 million, gain on the sale of the investment in Bolivian Power of $3.1 million and minority interest in income of joint venture, net of dividends, of $7.7 million. Cash flow provided by operating activities of $64 million, net of proceeds from the sale of the investment in Bolivian Power of $25.4 million, proceeds from project finance borrowings of $70.7 million, and $55 million of cash escrows and restricted marketable securities released were primarily used to purchase equipment of $3.0 million, to make investments in marketable securities of $21.5 million, to make investments in affiliates of $58.2 million, to repay project finance borrowings of $95.5 million, to pay deferred financing costs of $2.9 million and to pay common stock dividends of $4.8 million.
The principal components of cash flow provided by operating activities for fiscal year ended June 30, 1996 were generated by net income of $23.8 million, increases due to adjustments for depreciation and amortization of $37.8 million, deferred income taxes of $8.6 million, minority interest in income of joint venture of $3.4 million, net of dividends, loss on the sale of securities, net of $0.9 million, and a net $5.5 million source of cash reflecting changes in other working capital assets and liabilities which were partially offset by $1.5 million of equity in net income of affiliates net of dividends received from unconsolidated affiliates. Cash flow provided by operating activities of $78.5 million and proceeds from project finance borrowings of $0.4 million were primarily used to purchase property, plant and equipment of $1.6 million, to purchase marketable securities of $12.5 million, to make investments in affiliates of $6.5 million, to repay project finance borrowings of $46.6 million, to fund cash escrows of $7.5 million and to pay a dividend to common shareholders of $4.2 million.
Historically, the Company has financed each facility primarily under financing arrangements and related documents which generally require the extensions of credit to be repaid solely from the project's revenues and provide that the repayment of the extensions of credit (and interest thereon) is secured solely by the physical assets, agreements, cash flow and, in certain cases, the capital stock of that project subsidiary. This type of financing is generally referred to as "project financing." The project financing debt of the Company's subsidiaries and joint ventures is substantially non-recourse to the
Company and its other project subsidiaries, except in connection with certain transactions where Cogentrix Energy, Inc. or Cogentrix has agreed to certain limited guarantees and other obligations with respect to such projects. These limited guarantees and other obligations include agreements for the benefit of the project lenders to three project subsidiaries to fund cash deficits the projects may experience as a result of incurring certain costs, subject to an aggregate cap of $51.9 million. In addition, Cogentrix has guaranteed certain project subsidiaries' obligations to the utility under power sales agreements and obligations of up to $1.5 million of ReUse under an ash disposal agreement with an unrelated third party. Because certain of these limited guarantees and other obligations do not by their terms stipulate a maximum dollar amount of liability, the aggregate amount of the Company's potential exposure under these guarantees cannot be quantified. The aggregate contractual liability of the Company to its subsidiaries' project lenders is, in each case, a small portion of the aggregate project debt. If, however, the Company were required to satisfy all these guarantees and other obligations or even one or more of the significant ones, such event could have a material adverse impact on the Company's financial condition.
As of December 31, 1997, the Company had long-term debt (including the current portion thereof) of approximately $667.7 million. With the exception of the $100 million of Senior Notes issued in March, 1994, substantially all of such indebtedness is project financing debt. Future annual maturities of long-term debt range from $61.4 million to $81.4 million in the five-year period ending December 31, 2002. The Company believes that its project subsidiaries will generate sufficient cash flow to pay all required debt service on the project financing debt and to allow them to pay management fees and dividends to Cogentrix Energy, Inc. periodically in sufficient amounts to allow Cogentrix Energy, Inc. to pay all required debt service on the Senior Notes, fund a significant portion of its development activities and meet its other obligations. If, as a result of unanticipated events, the Company's ability to generate cash from operating activities is significantly impaired, the Company could be required to curtail its development activities to meet its debt service obligations.
In May 1997, the Company entered into a credit agreement with Australia and New Zealand Banking Group Limited, as Agent, which provides for a $50 million revolving credit facility (the "Corporate Credit Facility") with a term of three years ("Revolving Term"). The Corporate Credit Facility provides for one-year extensions of the Revolving Term, subject to lender consent. The Company can utilize the Corporate Credit Facility in the form of direct advances or the issuance of unsecured letters of credit. The outstanding balance of the Corporate Credit Facility at the end of the Revolving Term is payable over two years in four equal semiannual repayments of direct advances or collateralization of letters of credit. As of December 31, 1997, the Company had no advances or letters of credit outstanding under the Corporate Credit Facility. In March 1998, the Company borrowed $50 million under the Corporate Credit Facility to fund a portion of the purchase price related to the Whitewater and Cottage Grove acquisitions.
Any projects the Company develops in the future, and those independent power projects it may seek to acquire, are likely to require substantial capital investment. The Company's ability to arrange financing on a substantially non-recourse basis and the cost of such capital are dependent on numerous factors. In order to access capital on a substantially non-recourse basis in the future, the Company may have to make larger equity investments in, or provide more financial support for, the project entity.
The ability of the Company's project subsidiaries to pay dividends and management fees periodically to Cogentrix Energy, Inc. is subject to certain limitations in their respective project credit documents. Such limitations generally require that: (i) project debt service payments be current, (ii) project debt service coverage ratios be met, (iii) all project debt service and other reserve accounts be funded at required levels, and (iv) there be no default or event of default under the relevant project credit documents. There are also additional limitations that are adapted to the particular characteristics of each project subsidiary. Management does not believe that such restrictions or limitations will adversely affect its ability to meet its debt obligations. See "Business -- Description of the Company's Facilities," and " -- Facilities in Operation" herein.
In December 1994, the Company acquired a 50% interest in Birchwood, a partnership formed to own a 220 megawatt coal-fired cogeneration facility (the "Birchwood Facility") in King George County, Virginia, from two indirect wholly-owned subsidiaries of The Southern Company. The purchase price of the 50% interest in Birchwood Power was approximately $29.5 million and was funded with a portion of the net proceeds of the Company's Senior Note offering. The Company also provided an equity contribution to Birchwood Power of approximately $43.7 million in March 1997, which was funded with the remaining proceeds of the Company's Senior Note offering and corporate cash balances. Birchwood,
which commenced commercial operations in November 1996, sells electricity to Virginia Power and provides thermal energy to a 36-acre greenhouse under long-term contracts.
In September 1996, the Company renegotiated the project financing arrangements for its Roxboro and Southport Facilities. The amended agreements resulted in an approximate $18.4 million increase in the amount of indebtedness outstanding and extended the final maturity date of the loan by 7 months. The Company's project subsidiary operating the Roxboro and Southport Facilities transferred substantially all of the additional funds borrowed (net of transaction costs) to Cogentrix Energy, Inc., which utilized $5.5 million to make a capital contribution to the project subsidiary operating the ELK Facilities in connection with the refinancing of its project debt in September 1996.
In December 1996, the Company sold its investment in Bolivian Power pursuant to a cash tender offer received for all of the outstanding common stock of Bolivian Power at a price of $43 per share. The Company received proceeds of $25.4 million from the sale of its investment in Bolivian Power, net of transaction costs, which included payments made to certain unaffiliated individuals who performed development activities for Bolivian Power. See "Results of Operations" for the financial reporting impact of the sale of the investment in Bolivian Power.
In December 1997, the Company substantially completed construction of a 248 megawatt combined-cycle, gas-fired electric generation facility for Clark and earned a construction management fee of $4.5 million. Upon final completion of the facility and acceptance by Clark, the Company will earn an additional construction management fee of $500,000 and will also share in 50% of the amount, if any, of the excess of the contract amount ($117 million) over the actual costs and expenses incurred in constructing the Clark Facility. The excess is currently expected to be approximately $7 million.
In December 1997, the Company renegotiated the project financing arrangements for its Portsmouth Facility. The amended agreements resulted in an extension of the final maturity date of the loan by three months and an increase in the amount of commitment provided by the project lenders in the form of a $40.5 million revolving credit facility. This revolving credit facility is available to be drawn by the Portsmouth Facility at any time for general corporate purposes, including paying dividends to Cogentrix Energy, Inc. In March 1998, the Portsmouth Facility borrowed $20 million under the revolving credit facility and distributed such amount to Cogentrix Energy, Inc. for purposes of funding a portion of the purchase price related to the Whitewater and Cottage Grove acquisitions.
In February 1998, the Company renegotiated the project financing arrangements for its Hopewell Facility, in which it owns a 50% interest. The amended agreements resulted in a $34.6 million increase in outstanding indebtedness of JRCC and extended the final maturity date of the loan by six months. JRCC transferred substantially all of the additional funds borrowed (net of transaction costs) to its partners. The distribution received by Cogentrix Energy, Inc. related to the refinancing was approximately $16.6 million, which was used by the Company to fund a portion of the acquisition price related to the Whitewater and Cottage Grove acquisitions.
In March 1998, the Company acquired from LS Power Corporation an approximate 74% ownership interest in the Whitewater Facility and the Cottage Grove Facility. Each of the Cottage Grove and Whitewater Facilities are 245 megawatt gas-fired, combined-cycle cogeneration facilities. Commercial operations of the facilities commenced in the last half of calendar 1997. The aggregate acquisition price for the equity interest in the Cottage Grove and Whitewater Facilities was $158.0 million. In addition, the Company pre-funded a $16.7 million distribution to the previous owners. This distribution represented unused construction contingency and cash flows that were accumulated by the Cottage Grove and Whitewater Facilities prior to January 1, 1998. Cogentrix Energy, Inc. will be entitled to a distribution of the $16.7 million in 1998. The purchase price was funded with proceeds of the Corporate Credit Facility and corporate cash balances.
In March 1998, the Company signed an agreement with Bechtel Generating Company, Inc. to acquire an ownership interest in twelve electric generating facilities, comprising a net equity interest of 360 megawatts, and one interstate natural gas pipeline in the United States (the "Bechtel Asset Acquisition"). The closing of the Bechtel Asset Acquisition, which is subject to customary conditions including the obtaining of certain consents and regulatory approvals, is currently expected to occur in calendar 1998.
In connection with the Bechtel Asset Acquisition, the Company plans to issue up to $250 million of senior notes in a Rule 144A offering with a covenant to register exchange notes with the U.S. Securities and Exchange Commission. These senior notes will be unsecured and will rank pari passu with the Company's $100 million of outstanding Senior Notes due 2004.
The proceeds will be used by the Company to finance the Bechtel Asset Acquisition and to repay the outstanding borrowings under the Corporate Credit Facility.
For the fiscal year ended June 30, 1997, the Company's board of directors declared a dividend on its outstanding common stock of $5.0 million, which was paid in September 1997. The Company's board of directors declared a dividend on its outstanding common stock of $2.1 million for the six-month period ended December 31, 1997, which was paid in March 1998. The board of directors' policy, which is subject to change at any time, provides for a dividend payout ratio of no more than 20% of the Company's net income for the immediately preceding fiscal year. In addition, under the terms of the Indenture of the Senior Notes and the Corporate Credit Facility, the Company's ability to pay dividends and make other distributions to its shareholders is restricted.
IMPACT OF ENERGY PRICE CHANGES, INTEREST RATES AND INFLATION
Energy prices are influenced by changes in supply and demand as well as economic conditions generally and tend to fluctuate significantly. Through various hedging mechanisms, the Company has attempted to mitigate the impact of changes on the results of operations of most of its projects. The basic hedging mechanism against increased fuel and transportation costs is to provide contractually for matching increases in the energy payments the Company's project subsidiaries receive from the utility purchasing the electricity generated by the facility.
Under the power sales agreements for two of the Company's facilities, energy payments are indexed, subject to certain caps, to reflect the purchasing utility's solid fuel cost of producing electricity. The Company's other power sales agreements provide periodic, scheduled increases in energy prices that are designed to match periodic, scheduled increases in fuel and transportation costs that are included in the fuel supply and transportation contracts for the facilities.
Changes in interest rates could have a significant impact on the Company. Interest rate changes affect the cost of capital needed to construct projects as well as interest expense of existing project financing debt. As with fuel price escalation risk, the Company attempts to hedge against the risk of fluctuations in interest rates by arranging either fixed-rate financing or variable-rate financing with interest rate swaps, collars or caps on a portion of its indebtedness.
Although hedged to a significant extent, the Company's financial results will likely be affected to some degree by fluctuations in energy prices, interest rates and inflation. The effectiveness of the hedging techniques implemented by the Company is dependent, in part, on each counterparty's ability to perform in accordance with the provisions of the relevant contracts. The Company has sought to reduce the risk by entering into contracts with creditworthy organizations.
RECENTLY ISSUED BUT NOT YET EFFECTIVE ACCOUNTING STATEMENTS
In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting Comprehensive Income." This pronouncement establishes standards for the reporting and display of comprehensive income and its components in financial statements. Comprehensive income is defined as the total of net income and all other non-owner changes in equity. This statement will be adopted by the Company effective January 1, 1998. The Company believes this pronouncement will not have a material effect on its financial statements.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This pronouncement establishes standards for reporting information about operating segments in annual and interim financial statements. SFAS No. 131 will be adopted by the Company effective January 1, 1998. The Company believes this pronouncement will not have a material effect on its financial statements.
YEAR 2000 COMPLIANCE
The Company is currently in the process of evaluating its information technology infrastructure for Year 2000 compliance. The majority of the Company's internal financial information systems are in the process of being replaced with a fully compliant new system. This new system is expected to be fully implemented by January 1, 1999. The Company is also evaluating its plant's operating systems. Based on present information, the Company believes that only minor
modifications and upgrades will be required for the operating systems to be Year 2000 compliant. As such, the Company does not anticipate that the costs incurred to complete the necessary transition to ensure Year 2000 compliance will have a material impact on the Company's consolidated results of operations or financial position. Any costs necessary to modify existing systems to ensure Year 2000 compliance will be expensed as incurred. The Company is also communicating with customers, suppliers, financial institutions and others to coordinate Year 2000 conversion. In the event that any of the Company's significant customers or suppliers do not successfully and timely achieve Year 2000 compliance, the Company's business or operations could be adversely affected.
CHANGE OF CORPORATE FISCAL YEAR
Effective January 1, 1998, the Company changed its fiscal year to commence on January 1 and conclude on December 31 of each year. The Company's fiscal year previously commenced each July 1, concluding on June 30 of the following calendar year.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
Schedules other than those listed above have been omitted, since they are not required, are not applicable or are unnecessary due to the presentation of the required information in the financial statements or notes thereto.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO COGENTRIX ENERGY, INC.:
We have audited the accompanying consolidated balance sheets of Cogentrix Energy, Inc. (a North Carolina corporation) and subsidiary companies as of December 31, 1997, June 30, 1997 and June 30, 1996, and the related consolidated statements of operations, changes in shareholders' equity and cash flows for the six-month period ended December 31, 1997 and for each of the three years in the period ended June 30, 1997. 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. The summarized financial data for Bolivian Power Company Limited contained in Note 4 are based on the financial statements of Bolivian Power Company Limited which were audited by other auditors. Their report has been furnished to us and our opinion, insofar as it relates to the data in Note 4, is based solely on the report of the other auditors.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the financial position of Cogentrix Energy, Inc. and subsidiary companies as of December 31, 1997, June 30, 1997 and June 30, 1996, and the results of their operations and their cash flows for the six-month period ended December 31, 1997 and for each of the three years in the period ended June 30, 1997, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Charlotte, North Carolina, March 20, 1998.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS:
Compania Boliviana de Energia Electrica S.A. -- Bolivian Power Company Limited
We have audited the consolidated financial statements of Compania Boliviana de Energia Electrica S.A. -- Bolivian Power Company Limited and its subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income of cash flows and of shareholders' equity for each of the three years in the period ended December 31, 1996. 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 in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements audited by us present fairly, in all material respects, the financial position of Compania Boliviana de Energia Electrica S.A. -- Bolivian Power Company Limited and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with accounting principles generally accepted in the United States of America.
PRICE WATERHOUSE
La Paz, Bolivia
February 28, 1997
COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1997, JUNE 30, 1997 AND JUNE 30, 1996 (DOLLARS IN THOUSANDS)
The accompanying notes to consolidated financial statements are an integral part of these consolidated balance sheets.
COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE SIX-MONTH PERIODS ENDED DECEMBER 31, 1997 AND 1996 (UNAUDITED) AND THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS, EXCEPT FOR EARNINGS (LOSS) PER COMMON SHARE)
The accompanying notes to consolidated financial statements are an integral part of these consolidated statements.
COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 1997 AND THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS, EXCEPT FOR DIVIDENDS PER COMMON SHARE)
The accompanying notes to consolidated financial statements are an integral part of these consolidated statements.
COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIODS ENDED DECEMBER 31, 1997 AND 1996 (UNAUDITED) AND THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS)
The accompanying notes to consolidated financial statements are an integral part of these consolidated statements.
COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF BUSINESS
Cogentrix Energy, Inc. and subsidiary companies (collectively, the "Company") is principally engaged in the business of acquiring, developing, owning and operating independent power generating facilities (individually, a "Facility," or collectively, the "Facilities"). As of December 31, 1997, the Company owned or had interests in eleven Facilities in the United States with an aggregate installed capacity of approximately 1,120 megawatts. Two of the eleven Facilities are owned 50% by the Company and 50% by other independent power producers. Electricity generated by each Facility is sold to an electric utility (the "Utility") and steam is sold to an industrial company (the "Steam Purchaser"), all under long-term contractual agreements.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation -- The accompanying consolidated financial statements include the accounts of Cogentrix Energy, Inc., its subsidiary companies and a 50% owned joint venture in which the Company has effective control through majority representation on the board of directors of the managing general partner. Investments in other affiliates in which the Company has a 20% to 50% interest and/or the ability to exercise significant influence over operating and financial policies are accounted for on the equity method. All material intercompany transactions and balances among Cogentrix Energy, Inc. and its subsidiary companies and its consolidated joint venture have been eliminated in the accompanying consolidated financial statements.
Cash and Cash Equivalents -- Cash and cash equivalents include bank deposits, commercial paper, government securities and certificates of deposit that mature within three months of their purchase. Amounts in debt service accounts which might otherwise be considered cash equivalents are treated as current restricted cash.
Marketable Securities -- Marketable securities include commercial paper, corporate obligations, government securities, and certificates of deposit with maturity dates in excess of three months from their date of purchase. All investments in debt securities held by the Company are classified as available for sale securities and are reported at fair value. Realized gains or losses are determined on the specific identification method and are reflected in income. Unrealized gains and losses are reported net of taxes as a separate component of shareholders' equity, except those unrealized losses that are deemed to be other than temporary, which are reflected in income.
Construction Agreement -- In December 1994, the Company executed an engineering, procurement and construction agreement (the "Construction Agreement") with Public Utility District No. 1 of Clark County, Washington ("Clark"). Under this Construction Agreement, the Company is engineering, procuring equipment for and constructing a 248 megawatt combined-cycle, gas-fired electric generation facility (the "Clark Facility"). The Company is accounting for the construction under the completed-contract method, and, as such, all third-party construction costs and reimbursements are deferred until the contract is completed. Costs incurred as of December 31, 1997, June 30, 1997 and June 30, 1996 of $121,396,000, $104,960,000 and $37,117,000, respectively, are netted against the related reimbursed costs of $120,531,000, $99,552,000 and $35,572,000, respectively, and the difference is included in accounts receivable on the accompanying consolidated balance sheets.
Inventories -- Coal inventories consist of the contract purchase price of coal and all transportation costs incurred to deliver the coal to each Facility. Gas inventories represent the cost of natural gas purchased as fuel reserves for a Facility that is forecasted to be consumed during the next fiscal year. Spare parts inventories consist of major equipment and recurring maintenance supplies required to be maintained in order to facilitate routine maintenance activities and minimize unscheduled maintenance outages. As of December 31, 1997, June 30, 1997 and June 30, 1996, fuel and spare parts inventories are comprised of the following (dollars in thousands):
Coal inventories at certain Facilities are recorded at last-in, first-out ("LIFO") cost, with the remaining Facilities' coal inventories recorded at first-in, first-out ("FIFO") cost. The cost of coal inventories recorded on a LIFO basis was $427,000, $900,000 and $1,458,000 less than the cost of these inventories on a FIFO basis as of December 31, 1997, June 30, 1997 and June 30, 1996, respectively. Spare parts inventories are recorded at average cost.
Property, Plant and Equipment -- Property, plant and equipment is recorded at actual cost. Substantially all property, plant and equipment consists of cogeneration facilities which are depreciated on a straight-line basis over their estimated useful lives (ranging from 9 to 30 years). Other property and equipment is depreciated on a straight-line basis over the estimated economic or service lives of the respective assets (ranging from 3 to 10 years). Maintenance and repairs are charged to expense as incurred. Emergency and rotatable spare parts inventories are included in plant and are depreciated over the useful life of the related components.
Deferred Financing, Start-up and Organization Costs -- Financing costs, consisting primarily of legal and other direct costs incurred to obtain financing for the Facilities, are deferred and amortized over the permanent financing term. Start-up and organization costs include payroll costs and fees paid to consultants, technicians and vendors associated with the formation of each entity and the start-up of the Facilities. All start-up costs were fully amortized as of June 30, 1997.
Natural Gas Reserves -- Natural gas reserves consist of the cost of natural gas purchased as long-term fuel reserves for a Facility. These reserves are recorded at cost.
Investments in Affiliates - Investments in affiliates include investments in unconsolidated entities which own or derive revenues from power projects currently in operation, investments in unconsolidated entities which own and operate greenhouses, and investments in unconsolidated development joint venture entities. The Company's share of income or loss from investments in operating power projects is included in operating revenues in the accompanying consolidated statements of operations. The Company's share of income or loss from investments in greenhouses and development joint venture entities is included in other income (expense) in the accompanying consolidated statements of operations.
Project Development Costs -- Project development costs represent costs incurred after executing a power sales contract or obtaining a viable project site or signing a letter of intent and prior to obtaining project financing and starting physical construction. These costs represent amounts incurred for professional services, salaries, permits, options and other direct and incremental costs and are included in construction in progress when project financing is obtained or expensed at the time the Company determines the project will not be developed.
Revenue Recognition -- Revenues from the sale of electricity and steam are recorded based upon output delivered and capacity provided at rates specified under contract terms. Significant portions of the Company's revenues have been derived from certain electric utility customers. Two customers accounted for 63% and 22% of revenues in the six-month period ended December 31, 1997, 62% and 25% of revenues in the year ended June 30, 1997, 55% and 33% of revenues in the year ended June 30, 1996, and 57% and 34% of revenues in the year ended June 30, 1995.
Interest Rate Protection Agreements -- The Company enters into interest-rate protection agreements with major financial institutions to fix or limit the volatility of interest rates on its variable-rate, long-term debt. The differential paid or received is recognized as an adjustment to interest expense. Any premiums associated with interest rate protection
agreements are capitalized and amortized to interest expense over the term of the agreement. Unamortized premiums are included in other assets in the accompanying consolidated balance sheets.
Income Taxes -- Deferred income tax assets and liabilities are recognized for the estimated future income tax effects of temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets are also established for the estimated future effect of net operating loss and tax credit carryforwards when it is more likely than not that such assets will be realized. Deferred taxes are calculated based on provisions of the enacted tax law.
Use of 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.
New Accounting Pronouncements - In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting Comprehensive Income." This pronouncement establishes standards for the reporting and display of comprehensive income and its components in financial statements. Comprehensive income is defined as the total of net income and all other non-owner changes in equity. This statement will be adopted by the Company effective January 1, 1998. The Company believes this pronouncement will not have a material effect on its financial statements.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This pronouncement establishes standards for reporting information about operating segments in annual and interim financial statements. SFAS No. 131 will be adopted by the Company effective January 1, 1998. The Company believes this pronouncement will not have a material effect on its financial statements.
Change of Fiscal Year - Effective January 1, 1998, the Company changed its fiscal year to commence on January 1 and conclude on December 31 of each year. The Company's fiscal year previously commenced each July 1, concluding on June 30 of the following calendar year.
Reclassifications -- Certain amounts included in the accompanying consolidated financial statements for the fiscal years ended June 30, 1997, 1996 and 1995 have been reclassified from their original presentation to conform with the presentation for the six-month period ended December 31, 1997.
3. INVESTMENT IN DEBT SECURITIES
At December 31, 1997, investments in debt securities included in marketable securities in the accompanying consolidated balance sheet consisted of government securities and corporate obligations. The Company's net unrealized gain of $40,000 on its investment in debt securities is reported in the accompanying consolidated statements of changes in shareholders' equity, net of $14,000 in deferred income taxes.
At June 30, 1997, investments in debt securities included in restricted cash and marketable securities in the accompanying consolidated balance sheet consisted of government securities and corporate obligations. These securities are recorded at their fair market value which approximates cost. Restricted investments consist of an investment in a certificate of deposit which collateralizes the Company's obligation under a letter of credit (Note 10).
At June 30, 1996, there were no debt securities held in restricted cash or marketable securities. Restricted investments consisted of investments in certificates of deposit which collateralized the Company's obligations under certain letters of credit.
At June 30, 1995, the Company's net unrealized loss of $834,000 on its investment in debt securities is reported in the accompanying consolidated statements of changes in shareholders' equity, net of $222,000 allocated to minority interest in joint venture and net of $256,000 in deferred income taxes.
4. INVESTMENTS IN UNCONSOLIDATED POWER PROJECTS
Bolivian Power Company Limited
In November 1994, the Company acquired 719,206 shares of common stock of Bolivian Power Company Limited ("Bolivian Power"), representing approximately 17.1% of Bolivian Power's issued and outstanding shares of common stock, for a purchase price of approximately $18 million. In conjunction with the transaction, three executive officers of the Company were elected to the seven-member board of directors of Bolivian Power. In addition, the Company was providing to Bolivian Power general administrative and management services, as well as significant advisory services with respect to financial, regulatory and governmental matters, pursuant to a management agreement. The investment in Bolivian Power was accounted for using the equity method, because the Company had the ability to exercise significant influence over Bolivian Power's operating and financial policies.
In January 1996, Bolivian Power closed the sale of its distribution subsidiaries, realizing an after-tax gain of approximately $13.5 million. The Company's share of this gain was approximately $2.3 million. In December 1996, the Company sold its investment in Bolivian Power pursuant to a cash tender offer made for all of the outstanding common stock of Bolivian Power at a price of $43 per share. The Company received proceeds from the sale of $25.4 million, net of transaction costs, which included payments to certain unaffiliated individuals who performed development activities for Bolivian Power. The resulting book gain of $3.1 million is included in investment and other income in the accompanying consolidated statement of operations for the year ended June 30, 1997. The Company recognized approximately $0.4 million, $3.9 million and $1.1 million in income from unconsolidated investments in power projects in the accompanying consolidated statements of operations for the years ended June 30, 1997, 1996 and 1995, respectively, related to its investment in Bolivian Power. The following table presents summarized financial information for Bolivian Power as of December 31, 1996 and 1995 and for the three years ended December 31, 1996 (dollars in thousands):
Birchwood Power Partners, L.P.
In December 1994, the Company acquired a 50% interest in Birchwood Power Partners, L.P. ("Birchwood Power"), a partnership formed to construct and own a 220 megawatt coal-fired cogeneration facility (the "Birchwood Facility") in King George County, Virginia, from two indirect wholly-owned subsidiaries of The Southern Company. The Company initially paid $29.5 million for its 50% interest in Birchwood Power. In addition, pursuant to the equity funding obligation under Birchwood Power's project financing arrangements, the Company provided an equity contribution to Birchwood Power of approximately $43.7 million in March 1997. The initial distribution of $6.9 million received by the Company from Birchwood Power in April 1997 was also subsequently paid to a subsidiary of The Southern Company in accordance with the
terms of the original transaction agreement and was treated as part of the purchase price of the Company's interest in Birchwood Power.
The Birchwood Facility, which commenced commercial operations in November 1996, sells electricity to a utility and provides thermal energy to a 36-acre greenhouse under long-term contracts. The Birchwood Facility is operated by an affiliate of The Southern Company under a long-term operations and maintenance agreement. The Company has 50% representation on Birchwood Power's management committee, which must approve all material transactions of Birchwood Power. The Company is accounting for its investment in Birchwood Power under the equity method. The Company's share of net income of Birchwood Power is recorded net of the amortization of the $36.4 million premium paid to purchase the Company's 50% share interest in Birchwood Power. This premium is being amortized on a straight-line basis over the estimated useful life of the Birchwood Facility. The Company recognized approximately $1,727,000 and $147,000 in income from unconsolidated investments in power projects, net of premium amortization, in the accompanying consolidated statements of operations for the six-month period ended December 31, 1997 and for the year ended June 30, 1997, respectively, related to its investment in Birchwood Power. The following table presents summarized financial information for Birchwood Power as of and for the years ended December 31, 1997, 1996, and 1995 (dollars in thousands):
5. INVESTMENT IN OTHER UNCONSOLIDATED AFFILIATES
DEVELOPMENT JOINT VENTURES
Michigan Cogeneration Partners -- In partnership with Wolverine Energy, Inc., an indirect subsidiary of Northern States Power Company, a Minnesota-based investor-owned electric utility, the Company pursued the development of a 65 megawatt cogeneration power facility in Michigan. Development of this project began in September 1993 when the Company and its joint venture partner (the "Michigan Partnership") purchased from another developer a power sales agreement with Consumers Power Company providing for the sale of up to 65 megawatts of electric power. In July 1994,
the Michigan Partnership joined with Consumers Power Company to terminate the power sales agreement pursuant to terms under which the Partnership received $29.9 million. The Company, which owns a 50% interest in the Michigan Partnership, recognized its share of the Michigan Partnership's net income of $22.9 million for the year ended June 30, 1995, which was comprised solely of the proceeds received from this transaction net of project development costs. The Company recorded the $10.2 million gain from this transaction, which consisted of the Company's share of the net income of the Michigan Partnership net of corporate incentive compensation costs related to the transaction, as equity in net income of affiliates in the accompanying consolidated statement of operations for the year ended June 30, 1995. The Michigan Partnership was dissolved in June 1996.
Other Development Joint Ventures - The Company makes investments in other joint venture partnerships whose purpose is to develop power projects. The Company utilizes the equity method of accounting for those partnerships in which it holds an ownership interest between 20% and 50%. The Company recognized approximately $103,000 in equity losses for the six-month period ended December 31, 1997, and $1,257,000, $1,758,000 and $1,546,000 in equity losses for the years ended June 30, 1997, 1996 and 1995, respectively, related to its investments in these partnerships. These losses are reflected in equity in income (loss) of affiliates in the accompanying consolidated statements of operations.
GREENHOUSES
The Company has entered into an agreement with Agro Power Development, Inc., a developer and operator of greenhouse facilities, to make investments in partnerships which develop, construct and operate greenhouses which produce tomatoes. As of December 31, 1997, the Company held a 50% interest in four limited partnerships which had a combined 107 acres of production capacity in operation. The Company is accounting for its investment in these partnerships under the equity method. The Company recognized approximately $1,710,000 in equity losses and $444,000 in equity income from affiliates in the accompanying consolidated statements of operations for the six-month period ended December 31, 1997 and the year ended June 30, 1997, respectively, related to its investments in these partnerships.
6. LONG-TERM DEBT
The following long-term debt was outstanding as of December 31, 1997, June 30, 1997, and June 30, 1996, respectively (dollars in thousands):
Information related to each of these borrowings is as follows:
HOPEWELL FACILITY:
In July 1996, the Hopewell Facility's project debt agreement was amended, which effectively replaced commercial paper notes with a note payable to banks and resulted in a $13,000,000 increase in the amount of outstanding indebtedness. The amended project debt accrues interest at an annual rate equal to the applicable London Interbank Offering Rate ("LIBOR") as chosen by the Company, plus .875% per annum through July 1999 and 1.125% thereafter (6.81% at December 31, 1997). Principal is payable quarterly with interest payable the earlier of the maturity of the applicable LIBOR term or quarterly through June 2002. The Hopewell Facility's project debt agreement was amended in February 1998 (see Note 14).
PORTSMOUTH FACILITY:
The Portsmouth Facility's project debt agreement was amended in December 1997, resulting in the extension of the final maturity of the loan by three months to December 31, 2002. The amended terms of the loan agreement also increased the outstanding credit commitment from the project lenders by $40.5 million in the form of a revolving credit facility. As of December 31, 1997, there were no outstanding balances under this credit facility. The amended terms of the loan agreement provide for interest to accrue at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus an additional margin of .875% through December 1998 and 1.0% thereafter (6.845% at December 31, 1997). The banks' outstanding credit commitment under the loan agreement is reduced quarterly, with interest payable the earlier of the maturity of the applicable LIBOR term or quarterly through December 2002. The loan agreement also provides for a $6 million letter of credit to secure the project's obligations to pay debt service. Cogentrix Energy, Inc. has indemnified the lenders of the senior credit facility for any cash deficits the Portsmouth Facility could experience as a result of incurring certain costs, subject to a cap of $30 million.
An extraordinary loss of $2,458,000 was recorded in the six-month period ended December 31, 1997 related to the write-off of unamortized deferred financing costs from the original senior loan of $1,395,000 and net swap termination fees of $1,063,000 related to interest rate swap agreements hedging the original project debt. This extraordinary loss is shown net of a tax benefit of $956,000 in the accompanying consolidated statements of operations.
ROCKY MOUNT FACILITY:
The note payable to financial institution consists of a $125,761,000 senior loan which accrues interest at a fixed annual rate of 7.58%. Payment of principal and interest is due quarterly through December 2013.
RINGGOLD FACILITY:
The note payable to banks consists of a $15,737,000 senior loan which accrues interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus .95% to 1.35% per annum (6.9% at December 31, 1997). Interest is payable the earlier of the maturity of the applicable LIBOR term or quarterly in arrears. Payments of principal under the senior loan are due semiannually through April 2004.
RICHMOND FACILITY:
Commercial paper notes outstanding are supported by an irrevocable, direct-pay letter of credit provided by a syndicate of banks (the "Banks"). The maximum amount of commercial paper notes supported by the letter of credit is $150,114,000 as of December 31, 1997. The annual interest rate incurred is the yield on the commercial paper notes plus a 1.25% to 1.50% per annum fee (weighted average rate of 7.17% at December 31, 1997) paid to the Banks for providing the letter of credit.
Tax-exempt industrial development bonds (the "Bonds") have been issued to support the purchase of certain pollution control and solid waste disposal equipment for a Facility ($48,000,000 outstanding at December 31, 1997). Principal and interest payments on the Bonds are supported by an irrevocable, direct-pay letter of credit provided by the Banks. The annual interest rate is the yield on the Bonds plus a 1.25% to 1.50% per annum fee (6.875% at December 31, 1997). The letters of credit described above are part of one credit facility (the "Credit Facility"). The Credit Facility provides for commitment reductions through September 2007.
ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:
The project debt on the Elizabethtown, Lumberton and Kenansville Facilities, which consisted of a senior loan with a syndicate of banks and a subordinated credit facility with a financial institution, was refinanced in September 1996
with the proceeds of a $39 million senior credit facility and $5.5 million capital contribution by the Company. The senior credit facility accrues interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus .875% through September 1997 and 1% thereafter (6.94% at December 31, 1997). Principal is payable quarterly with interest payable at the earlier of the maturity of the applicable LIBOR term or quarterly through September 2000. The senior credit facility also provides for a $3.3 million letter of credit to secure the project's obligations to pay debt service. An extraordinary loss of $1.2 million was recorded in the fiscal year ended June 30, 1997 related to the write-off of unamortized deferred financing costs from the original senior loan and subordinated credit facility. This extraordinary loss is shown net of a tax benefit of $470,000 in the accompanying consolidated statements of operations.
ROXBORO AND SOUTHPORT FACILITIES:
The project debt agreement for the Roxboro and Southport Facilities was amended in September 1996, resulting in an $18.4 million increase in the amount of outstanding indebtedness. The revised senior credit facility accrues interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus .875% through September 1997, 1% thereafter through September 2001 and 1.125% thereafter (6.94% at December 31, 1997). Principal is payable quarterly with interest payable at the earlier of the maturity of the applicable LIBOR term or quarterly through June 2002. The senior credit facility also provides for a $6.5 million letter of credit to secure the project's obligations to pay debt service. Cogentrix Energy, Inc. has indemnified the lenders of the senior credit facility for any cash deficits the Roxboro and Southport Facilities could experience as a result of incurring certain costs, subject to a cap of $11.3 million.
INTEREST RATE PROTECTION AGREEMENTS:
The Company has entered into interest rate cap, interest rate collar and interest rate swap agreements (Note 12) to manage its interest rate risk on its variable-rate project financing debt. The notional amounts of debt covered by these agreements as of December 31, 1997 and June 30, 1997 are $259,191,000 and $391,371,000, respectively. The agreements effectively change the interest rate on the portion of debt covered by the notional amounts from a weighted average variable rate of 7.06% to a weighted average effective rate of 7.29% at December 31, 1997. These agreements expire at various dates through July 2006.
SENIOR NOTES:
On March 15, 1994, the Company issued $100 million of registered, unsecured senior notes due 2004 (the "Senior Notes") in a public debt offering. The Senior Notes were priced at par to yield 8.10%. In February 1994, the Company entered into a forward sale of ten-year U.S. Treasury Notes in order to protect against a possible increase in the general level of interest rates prior to the completion of the Senior Notes offering. This hedge transaction resulted in the recognition of a gain which has been deferred and included as part of the Senior Notes on the accompanying consolidated balance sheets. This deferred gain will be recognized over the term of the Senior Notes, reducing the effective rate of interest on the Senior Notes to 7.5%. The Senior Notes require annual sinking fund payments beginning in March 2001. The impact of the sinking fund requirements has been reflected in the schedule of future maturities of long-term debt contained herein.
CORPORATE CREDIT FACILITY:
In May 1997, the Company entered into a credit agreement with Australia and New Zealand Banking Group Limited, as Agent, which provides for a $50,000,000 revolving credit facility with an initial term of three years (the "Corporate Credit Facility"). The Corporate Credit Facility allows for direct advances or the issuance of letters of credit. The outstanding balance at the end of the three-year term (May 2000) is payable over two years in four equal semiannual repayments of direct advances or collateralization of letters of credit. Borrowings bear interest at LIBOR plus an applicable margin based on the credit rating on the Company's Senior Notes. Commitment fees related to the Corporate Credit Facility are currently 30 basis points per annum, payable each quarter on the outstanding unused portion of the Corporate Credit Facility. As of December 31, 1997, the Company had no borrowings or letters of credit outstanding.
The project financing debt is substantially non-recourse to the Company (as parent). The project financing agreements of the Company's subsidiaries, the Indenture for the Senior Notes and the Corporate Credit Facility agreement contain certain covenants which, among other things, place limitations on the payment of dividends, limit additional indebtedness, and restrict the sale of assets. The project financing agreements also require certain cash to be held with a trustee as security for future debt service payments. In addition, the Facilities, as well as the long-term contracts which support them, are pledged as collateral for the Company's obligations under the project financing agreements.
The ability of the Company's project subsidiaries to pay dividends and management fees periodically to the Company (as parent) is subject to certain limitations in their respective project credit documents. Such limitations generally require that: (i) project debt service payments be current, (ii) project debt service coverage ratios be met, (iii) all project debt service and other reserve accounts be funded at required levels, and (iv) there be no default or event of default under the relevant project credit documents. Dividends, when permitted, are declared and paid immediately to the Company at the end of such period.
The Company's ability to pay dividends to its shareholders is restricted by certain covenants of the Indenture for the Senior Notes and the Corporate Credit Facility agreement. These covenants did not restrict the Company's ability to declare a $2.1 million dividend to the Company's shareholders for the six-month period ended December 31, 1997.
Future maturities of long-term debt at December 31, 1997, net of unamortized issue discounts on commercial paper notes and excluding the unamortized balance of the deferred gain on the Senior Notes hedge transaction, are as follows (dollars in thousands):
Cash paid for interest on the Company's long-term debt amounted to $29,249,000, $54,458,000, $58,253,000 and $58,952,000 for the six-month period ended December 31, 1997 and the years ended June 30, 1997, 1996 and 1995, respectively.
7. INCOME TAXES
The provision (benefit) for income taxes for the six-month period ended December 31, 1997 and the years ended June 30, 1997, 1996 and 1995 consists of the following (dollars in thousands):
Reconciliations between the federal statutory income tax rate and the Company's effective income tax rate are as follows:
The net current and noncurrent components of deferred income taxes reflected in the accompanying consolidated balance sheets as of December 31, 1997, June 30, 1997 and June 30, 1996 are as follows (dollars in thousands):
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) operating loss and tax credit carryforwards. Significant components of the Company's net deferred tax liability as of December 31, 1997, June 30, 1997 and June 30, 1996 are as follows (dollars in thousands):
At December 31, 1997, the Company had federal investment tax carryforwards of approximately $1,086,000 expiring 2002 and $1,205,000 expiring in 2006 and alternative minimum tax credit carryforwards of approximately $23,537,000 with no expiration date available to reduce its future federal income tax liabilities.
Cash paid for income taxes amounted to $4,142,000, $8,271,000, $7,023,000 and $4,664,000 for the six-month period ended December 31, 1997 and the years ended June 30, 1997, 1996 and 1995, respectively.
8. LEASE COMMITMENTS
The Company leases an office building and land from Equipment Leasing Partners ("ELP"), a partnership formed by several of the Company's shareholders, with remaining initial lease terms of 7 years and 50 years, respectively. The Company also leases certain equipment from ELP used to transport and handle coal and ash at certain Facilities. Future minimum lease payments under the agreements with ELP and agreements with other equipment providers at December 31, 1997 are as follows (dollars in thousands):
9. LOSS ON IMPAIRMENT AND COST OF REMOVAL OF COGENERATION FACILITIES
During the fiscal year ended June 30, 1997, the Company undertook an analysis of the post-contract operating environment for all of its operating facilities in light of the dramatic market changes that are taking place in the power generation industry. The analysis included assumptions regarding future levels of operations, operating costs and market prices for equivalent generation available from other sources. As a part of this analysis, in accordance with the Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," the Company assessed whether any impairment of the Company's Facilities had occurred. This assessment included comparing the projected future cash flows to be provided by these assets to the net book value of such assets. Based on this assessment, the Company determined that an impairment loss had occurred on the Elizabethtown, Lumberton, Kenansville and Ringgold Facilities. This loss on impairment of cogeneration facilities of $57.3 million represents the excess of the net book value of these cogeneration facilities over their current fair value, determined by discounting to present value projected future cash flows to be provided by such assets. The Company believes that its projections of future cash flows are based upon reasonable assumptions about the future performance of these assets. Because of the risks and uncertainties associated with any projections, there can be no assurances, however, that actual events will be consistent with the assumptions made, and future cash flows may be greater or less than those projected. The analysis also resulted in the recognition of an $8.3 million liability related to the Company's estimated cost of removal obligations under the land leases for the Elizabethtown, Lumberton and Kenansville Facilities. The total impairment loss and cost of removal of $65.6 million has been reflected in the accompanying consolidated statements of operations for the year ended June 30, 1997.
Also in connection with the overall assessment of the post-contract operating environment for its cogeneration facilities, the Company concluded that the estimated useful lives of the Elizabethtown, Lumberton, Kenansville, Roxboro and Southport Facilities should be adjusted to reflect the economic lives of the plants as determined by the remaining terms of their respective power purchase agreements. The annual depreciation expense for these five facilities, in aggregate, increased approximately $6.1 million per year as a result of the changes in estimated useful lives and the impairment loss recognized during the fiscal year ended June 30, 1997.
10. COMMITMENTS AND CONTINGENCIES
Long-Term Contracts -- The Company has several long-term contractual commitments that comprise a significant portion of its financial obligations. These contractual commitments with original terms varying in length from 10 to 25 years are the basis for a major portion of the revenue and operating expenses recognized by the Company and provide for specific services to be provided at fixed or indexed prices. The major long-term contractual commitments are as follows:
(i) The Company is required to sell electricity generated by each Facility to a Utility and the Utility is required to purchase this electricity at pre-established or annually escalating prices.
(ii) The Company is required to sell and the Steam Purchaser is required to purchase a minimum amount of process steam from each Facility for each contract year. The Steam Purchaser is generally required to purchase its entire steam requirements from the Company. The purchase price of steam under these contracts escalates annually or is fixed and determinable during the term of the contracts.
(iii) The Company is obligated to purchase and fuel suppliers are required to supply all the fuel requirements of each Facility. Fuel requirements include the quality and estimated quantity of fuel required to operate each Facility. The price of fuel escalates annually for the term of each contract. In addition, the Company has transportation contracts with various entities to deliver the fuel to each Facility. These contracts also provide for annual escalations throughout the term of the contracts.
Effective September 1996, the Company amended the power sales agreements on its Lumberton, Elizabethtown, Kenansville, Roxboro and Southport Facilities. These amendments provide the purchasing utility additional rights related to the dispatch of the Facilities and eliminated the purchase options which the utility held related to the Roxboro and Southport Facilities.
Effective December 1997, the Company amended the power sales agreement on its Portsmouth Facility. This amendment provided the purchasing utility additional rights related to the dispatch of the Facility. The terms of the amended power sales agreement also eliminated Portsmouth's accrued obligation to return previously disallowed capacity payments to the purchasing utility.
Under terms of contracts with one Utility, the Company is obligated to pay up to $8,850,000 in liquidated damages to the Utility if two of the Company's Facilities do not demonstrate certain operating and reliability standards. A bank has issued letters of credit in favor of the Utility which secure the Company's obligations to the Utility under this provision of the contracts.
Under certain contracts with one Utility, the Utility is permitted, subsequent to the maturity date of the original project financing debt, to reduce future payments or recover certain payments previously made in the event that a state utility commission prohibits the Utility from recovering such payments made under a power sales agreement.
Construction Agreement -- In October 1995, the Company delivered to Clark a $20 million letter of credit, provided by a bank, which was collateralized with a pledge of marketable securities. This letter of credit supported certain contingent obligations of the Company under the Construction Agreement. In December 1997, the Company substantially completed construction of the Clark Facility and earned a construction fee of $4.5 million, which is included in other operating revenue in the accompanying consolidated statement of operations for the six-month period ended December 31, 1997. The $20 million letter of credit was also released to the Company at this time. Upon final completion of the Clark Facility and acceptance by the owner, the Company will earn an additional $500,000 fee. The Company will also share in 50% of the amount, if any, equal to the excess of the contract amount over the costs and expenses incurred in constructing the Clark Facility.
Management Incentive Compensation Plans -- The Company has entered into various incentive compensation plans with certain employees which provide for compensation to the employees (during the period of employment) equal to a percentage, as determined by the board of directors, of the Company's income before income taxes or certain subsidiaries' cash flow. The Company incurred expense under these plans of $3,710,000 for the fiscal year ended June 30, 1996 and $3,950,000 for the fiscal year ended June 30, 1995. During the fiscal year ended June 30, 1997, the Company incurred $10.7 million of expenses in connection with the restructuring or termination of these incentive compensation plans. During the six-month period ended December 31, 1997, the Company incurred $1,067,000 of expense related to these incentive compensation plans.
Employee Benefit Plans -- The Company sponsors a defined contribution 401(k) savings plan for its full-time employees. The Company matches employees' contributions to the plan up to specified limitations. Company contributions to the plan were $804,000 in the six-month period ended December 31, 1997, $1,618,000 in the fiscal year ended June 30, 1997, $1,629,000 in fiscal 1996 and $1,612,000 in fiscal 1995.
The Company has a non-qualified Supplemental Retirement Plan agreement with certain directors and officers. Under the plan, the participants may elect to have up to 35% of their compensation deferred. In addition, the Company will credit the participant's deferral account, up to specified limitations, with an amount equal to the participant deferral. The participants' account balances are distributable upon termination of employment or death. The Company purchases insurance on the participants' lives (cash surrender value of $2,685,000 at December 31, 1997) which is used to fully fund the liability under the plan on an annual basis. The Company is owner and beneficiary of the policies.
Guarantees -- In connection with its substantially non-recourse project financings and certain other subsidiary contracts, the Company and its subsidiary, Cogentrix, Inc. have expressly undertaken certain limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments include guarantees by Cogentrix, Inc. of a certain subsidiary's obligation capped at $1.5 million and certain subsidiaries' performance under their contracts with one Utility. In addition, Cogentrix Energy, Inc. has indemnified the project lenders of certain subsidiaries for any cash deficits such subsidiaries could experience as a result of incurring certain costs, subject to an aggregate cap of $51.9 million, which includes the impact of the JRCC refinancing in February 1998 (see Note 14).
Pending Claims and Litigation -- Effective September 1996, the Company amended the power sales agreements on its Elizabethtown, Lumberton, Kenansville, Roxboro and Southport facilities. Under the amended terms of these power sales agreements, the purchasing utility has exercised its right of economic dispatch resulting in significant reductions in fuel requirements at each of these facilities. In response to this reduction in fuel requirements, one of the coal suppliers for these facilities initiated an arbitration proceeding and another filed a civil action against certain subsidiaries of the Company. The arbitration proceeding was completed in October, 1997, with the arbitration panel denying any recovery to the coal supplier. The coal supplier subsequently challenged the arbitration panel's ruling. Management believes that the coal supplier's claims provide no basis by which a court could vacate an arbitration ruling. With respect to the civil action filed by the other coal supplier, management believes that there is no basis for certain claims and there are meritorious defenses as to the remainder. The Company intends to vigorously defend the pending civil action.
Effective December 1997, the Company amended the power sales agreement on its Portsmouth facility. Under the amended terms, the purchasing utility has exercised its right of economic dispatch which has led to significant reductions in that facility's fuel requirements. In response to the reduced fuel requirements, the coal supplier for the Portsmouth facility has filed a civil action against a subsidiary of the Company. Management believes that there is no basis for certain claims of the coal supplier and there are meritorious defenses as to the remainder. The Company intends to vigorously defend the pending civil action.
The Company has established reserves which management believes to be adequate to cover any costs resulting from these matters. Management believes that the resolution of these disputes will not have a material adverse impact on the Company's consolidated financial position or results of operations.
In addition, the Company experiences routine litigation in the normal course of business. Management is of the opinion that none of this routine litigation will have a material adverse effect on the consolidated financial position or results of operations of the Company.
11. FUNDS HELD BY TRUSTEES
The majority of revenue received by the Company is required by the terms of various credit agreements to be deposited in accounts administered by certain banks (the "Trustees"). The Trustees invest funds held in these accounts at the direction of the Company. These accounts are established for the purpose of depositing all receipts and monitoring all disbursements of each Facility. In addition, special accounts are established to provide debt service payments and income taxes. The funds in these accounts are pledged as security under the project financing agreements of each subsidiary.
Funds held by the Trustees were $42,170,000 at December 31, 1997, $49,187,000 at June 30, 1997,and $59,287,000 at June 30, 1996. Debt service account balances are reflected as restricted cash, whereas all other accounts are classified as cash and cash equivalents in the accompanying consolidated balance sheets.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISKS
The Company invests its temporary cash balances in U.S. government obligations, corporate obligations and financial instruments of highly-rated financial institutions. A substantial portion of the Company's accounts receivable are from two major regulated electric utilities and the associated credit risks are limited.
The carrying values reflected in the accompanying consolidated balance sheets at December 31, 1997, June 30, 1997, and June 30, 1996 approximate the fair values for cash and cash equivalents and variable-rate long-term debt. Investments in debt securities and certificates of deposit included in restricted cash, marketable securities and restricted investments are also reported at fair market value, which approximates cost, at December 31, 1997, June 30, 1997, and June 30, 1996 (Note 3). The fair value of the Company's fixed-rate borrowings at December 31, 1997 is $8,376,000 greater than the historical carrying value of $225,761,000. At June 30, 1997, the fair value of the Company's fixed-rate borrowings was $1,759,000 lower than the historical carrying value of $226,409,000, and at June 30, 1996, the fair value of the Company's fixed-rate borrowings was $3,631,000 lower than the historical carrying value of $238,018,000. In making such calculations, the Company utilized credit reviews, quoted market prices and discounted cash flow analyses, as appropriate.
The Company is exposed to credit-related losses in the event of non-performance by counterparties to the Company's interest rate protection agreements (Note 6). The Company does not obtain collateral or other security to support such agreements but continually monitors its positions with, and the credit quality of, the counterparties to such agreements. As of December 31, 1997, the gross unrealized loss on the interest rate protection agreements was $2,670,000. As of June 30, 1997, the gross unrealized gains and losses on the Company's interest rate protection agreements were $3,130,000 and $2,102,000, respectively, resulting in an estimated net unrealized gain of $1,028,000, and as of June 30, 1996, the gross unrealized gains and losses on the Company's interest rate protection agreements were $4,984,000 and $4,185,000, respectively, resulting in an estimated net unrealized gain of $799,000.
13. RELATED PARTY TRANSACTIONS
The Company has notes receivable and advances due from shareholders and an affiliated entity of approximately $118,000, $450,000 and $678,000 as of December 31, 1997, June 30, 1997 and June 30, 1996, respectively. The notes receivable bear interest at various rates, all of which are in excess of the prime rate in effect from time to time, and have specified repayment terms. These notes have been classified as other assets in the accompanying consolidated balance sheets.
The Company leases certain equipment, its principal executive office building and land from an affiliated entity. Payments by the Company under these lease agreements were approximately $869,000, $1,968,000, $2,041,000, and $2,158,000 for the six-month period ended December 31, 1997 and the years ended June 30, 1997, 1996 and 1995, respectively.
In September 1991, the Company entered into a consulting agreement with a shareholder, director and former executive officer to provide consulting services related to general business matters. The agreement provided for monthly payments of $12,500 through December 1995 and monthly payments of $8,333 thereafter through December 1996. In addition, the shareholder was a participant in management incentive compensation plans (Note 10) while employed as an executive officer of the Company and continues to receive incentive compensation annually pursuant to such plans equal to a percentage of net cash flow, as defined, of certain subsidiaries. Total compensation to the shareholder under the consulting agreement and incentive compensation plans was approximately $100,000, $374,000, $442,000, and $510,000 for the six-month period ended December 31, 1997 and the years ended June 30, 1997, 1996 and 1995, respectively.
Three shareholders, who are also employees of the Company, terminated their participation in certain management incentive compensation plans during the fiscal year ended June 30, 1997 (Note 10). The Company recognized $3.5 million of expense related to the termination of the shareholders' participation in these plans.
14. SUBSEQUENT EVENTS
Cogentrix of Pennsylvania, Inc.
In January 1998, the Company signed an agreement with Pennsylvania Electric Company ("Penelec") to terminate the Ringgold Facility's power purchase agreement. This termination agreement was the result of a request for proposals to buy-back or restructure power sales agreements issued to all operating IPP projects in Penelec's territory in April 1997. The termination agreement with Penelec provides for a payment to the Company of approximately $25 million which will be sufficient to retire all of Cogentrix of Pennsylvania, Inc.'s ("CPA") outstanding project debt. The buy-back of the power purchase agreement is subject to the issuance of an order by the Pennsylvania Public Utility Commission granting Penelec the authority to fully recover from its customers the consideration paid to CPA under the buyout agreement. Management does not expect this event to have an adverse impact on the Company's consolidated results of operations or financial position.
James River Cogeneration Company
Effective February 1998, James River Cogeneration Company ("James River"), a joint venture owned 50% by the Company, which owns a cogeneration facility located in Hopewell, Virginia (the "Hopewell Facility"), amended its power sales agreement with Virginia Power to provide Virginia Power additional rights related to the dispatch of the Hopewell
Facility. In connection with the amendment of the power sales agreement, the Company amended the terms of the existing project debt on the Hopewell Facility.
The amended terms of the Hopewell project debt resulted in an extension of the final maturity of the note payable by six months to December 31, 2002 and increased outstanding borrowings $34.6 million, the proceeds of which (net of transaction costs) were paid as a distribution to the James River partners. The amended note payable accrues interest at an annual rate equal to the applicable LIBOR rate, as chosen by the Company, plus an additional margin of .875% through February 1998 and 1.00% thereafter. The amended note payable also provides for a $5 million letter of credit to secure the project's obligation to pay debt service. Cogentrix Energy, Inc. has indemnified the lenders of the note payable for any cash deficits the Hopewell Facility could experience as a result of incurring certain costs, subject to a cap of $10.6 million. An extraordinary loss of $2.4 million will be recorded in the first quarter of 1998 related to the write-off of unamortized deferred financing costs from the original project debt and a swap termination fee on an interest rate swap agreement hedging the original project debt.
The pro forma future maturities of long-term debt as of December 31, 1997, excluding unamortized issue discounts on commercial paper notes and the unamortized balance of the deferred gain on the Senior Notes hedge transaction and taking into account the amended project debt agreement for the Hopewell Facility, are as follows (dollars in thousands):
Whitewater and Cottage Grove Transaction
In March 1998, the Company acquired from LS Power Corporation an approximate 74% ownership interest in two power generation facilities in Whitewater, Wisconsin (the "Whitewater Facility") and in Cottage Grove, Minnesota (the "Cottage Grove Facility"). Each of the Cottage Grove and Whitewater Facilities are 245 megawatt gas-fired, combined-cycle cogeneration facilities. Commercial operations of the facilities commenced in the last half of calendar 1997. The Cottage Grove Facility sells capacity and energy to Northern States Power Company under a 30-year power sales contract terminating in 2027. The Whitewater Facility sells capacity and energy to Wisconsin Electric Power Company under a 25-year power sales contract terminating in 2022. The aggregate acquisition price for the equity interest in the Cottage Grove and Whitewater Facilities was $158.0 million. In addition, the Company pre-funded a $16.7 million distribution to the previous owners. This distribution represented unused construction contingency and cash flows that were accumulated by the Cottage Grove and Whitewater Facilities prior to January 1, 1998. Cogentrix Energy, Inc. will be entitled to a distribution of the $16.7 million in calendar 1998. The purchase price was funded with proceeds of the Corporate Credit Facility and corporate cash balances.
Bechtel Asset Acquisition
In March 1998, the Company signed an agreement with Bechtel Generating Company, Inc. to acquire an ownership interest in 12 electric generating facilities, comprising a net equity interest of approximately 360 megawatts, and one interstate natural gas pipeline in the United States (the "Bechtel Asset Acquisition"). The closing of the Bechtel Asset Acquisition, which is subject to customary conditions including the obtaining of certain consents and regulatory approvals, is currently expected to occur in calendar 1998. Management anticipates accounting for these investments under the equity method.
In connection with the Bechtel Asset Acquisition, the Company plans to issue up to $250 million of senior notes in a Rule 144A offering with a covenant to register exchange notes with the U.S. Securities and Exchange Commission. These senior notes will be unsecured and will rank pari passu with the Company's $100 million of outstanding Senior Notes due 2004. The proceeds will be used by the Company to finance the Bechtel Asset Acquisition and to repay the outstanding borrowings under the Corporate Credit Facility. In connection with this anticipated debt offering, the Company executed an interest rate agreement in March 1998 covering a notional amount of $237 million for a period of four months to hedge against fluctuations in interest rates prior to the completion of the debt offering.
SCHEDULE I
COGENTRIX ENERGY, INC.
CONDENSED BALANCE SHEETS OF REGISTRANT
(DOLLARS IN THOUSANDS)
The accompanying notes are an integral part of these condensed financial statements.
SCHEDULE I
COGENTRIX ENERGY, INC.
CONDENSED STATEMENTS OF OPERATIONS OF REGISTRANT
(DOLLARS IN THOUSANDS)
The accompanying notes are an integral part of these condensed financial statements.
SCHEDULE I
COGENTRIX ENERGY, INC.
CONDENSED STATEMENTS OF CASH FLOWS OF REGISTRANT
(DOLLARS IN THOUSANDS)
The accompanying notes are an integral part of these condensed financial statements.
SCHEDULE I
COGENTRIX ENERGY, INC. NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
1. SIGNIFICANT ACCOUNTING POLICIES
Accounting for Subsidiaries -- Cogentrix Energy, Inc. has accounted for its investment in and earnings of its subsidiaries on the equity method in the condensed financial information.
Income Taxes -- The benefit for income taxes has been computed based on the Company's consolidated effective income tax rate.
Change of Fiscal Year -- Effective January 1, 1998, Cogentrix Energy, Inc. changed its fiscal year to commence on January 1 and conclude on December 31 of each year. Cogentrix Energy, Inc.'s fiscal year previously commenced each July 1, concluding on June 30 of the following calendar year.
Reclassification -- Certain amounts included in the condensed financial statements for the fiscal years ended June 30, 1997, 1996 and 1995 have been reclassified from their original presentation to conform with the presentation for the six-month period ended December 31, 1997.
2. LONG-TERM DEBT
Senior Notes
On March 15, 1994, Cogentrix Energy, Inc. issued $100 million of registered, unsecured senior notes due 2004 (the "Senior Notes") in a public debt offering. The Senior Notes were priced at par to yield 8.10%. In February 1994, the Company entered into a forward sale of ten-year U.S. Treasury Notes in order to protect against a possible increase in the general level of interest rates prior to the completion of the Senior Notes offering. This hedge transaction resulted in the recognition of a gain which has been deferred and included as part of the Senior Notes on the accompanying condensed balance sheets. This deferred gain will be recognized over the term of the Senior Notes, reducing the effective rate of interest on the Senior Notes to 7.5%. The Senior Notes require annual sinking fund payments beginning in March 2001.
Future maturities of long-term debt at December 31, 1997, excluding the unamortized balance of the deferred hedge gain, are as follows (dollars in thousands):
Corporate Credit Facility
In May 1997, Cogentrix Energy, Inc. entered into a credit agreement with Australia and New Zealand Banking Group Limited, as Agent, which provides for a $50,000,000 revolving credit facility (the "Corporate Credit Facility") with an initial term of three years (the "Revolving Term"). The Corporate Credit Facility provides for one-year extensions of the Revolving Term, subject to lender consent. The Corporate Credit Facility allows for direct advances or the issuance of letters of credit. The outstanding balance at the end of the Revolving Term is payable over two years in four equal semiannual repayments of direct advances or collateralization of letters of credit. Borrowings bear interest at LIBOR plus an applicable margin based on the credit rating on the Senior Notes. Commitment fees related to the Corporate Credit Facility are currently 30 basis points per annum, payable each quarter on the outstanding unused portion of the Corporate Credit Facility. As of December 31, 1997, Cogentrix Energy, Inc. had no borrowings or letters of credit outstanding.
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 directors and executive officers of the Company are as set forth below.
GEORGE T. LEWIS, JR., the founder of Cogentrix, has been Chairman of the Board and a Director of the Company since its formation in 1993 and Chief Executive Officer of the Company from December 1993 to August 1995, prior to which he was Chief Executive Officer and a Director of Cogentrix from 1983 to 1993, Chairman of the Board of Cogentrix since 1990 and President of Cogentrix from 1983 to 1989. Mr. Lewis previously served for over 18 years with Chas T. Main, Inc. ("Main"), an engineering firm headquartered in Boston. In 1971, he became a Senior Vice President responsible for that company's work with the utility industry. From 1978 through 1980, he headed Main's Southern District office located in Charlotte, North Carolina and directed Main's involvement in the area of coal-fired industrial power plants. In 1980, Mr. Lewis was promoted to Group Vice President and director and returned to Boston to assume responsibility for all corporate marketing and sales. In this capacity, he became convinced that cogeneration projects would become an emerging market and left Main to form Cogentrix.
DAVID J. LEWIS has been a Director of the Company since its formation and was appointed Vice Chairman of the Board and Chief Executive Officer in August 1995. Prior to August 1995, Mr. Lewis was Executive Vice President - --Marketing and Development, Chief Executive Officer -- Elect since June 1994, Group Senior Vice President -- Marketing and Development with Cogentrix since September 1993 and a Director of Cogentrix since 1988. From 1989 until September 1993, he was Senior Vice President -- CGX Environmental Systems and President and Chief Operating Officer -- CGX Environmental Systems Division of Cogentrix. From 1987 to 1989, he was Vice President -- Administration of Cogentrix, from 1986 to 1987, he was Resident Construction Manager and from 1985 to 1986, he was Assistant Construction Manager. Prior to joining Cogentrix in 1985, he was Operations Manager with Bartex Corporation, an export management company headquartered in Portland, Oregon. David Lewis is a son of George T. Lewis, Jr. and Betty G. Lewis.
MARK F. MILLER was appointed President, Chief Operating Officer and a Director of the Company in May 1997. Prior to joining the Company, Mr. Miller was Vice President for Northrop Grumman in Bethpage, New York. He joined Northrop Grumman in 1982 and held successive positions in the material, law and contracts departments before being named Vice President, Contracts and Pricing at Northrop's B-2 Division in 1991. In 1993, he became Vice President Business Management at the B-2 Division. In 1994, Northrop acquired the Grumman Corporation and Mr. Miller was named Vice President-Business Management for the newly formed Electronics and Systems Integration Division, a position he held until his move to Cogentrix. From 1980 to 1982, he was an Associate with the law firm of Dolack, Hansler.
BETTY G. LEWIS has been a Director of the Company since September 1994. Betty Lewis is the spouse of George T. Lewis, Jr.
JAMES E. LEWIS has been Executive Vice President and a Director of the Company since its formation, prior to which he was Executive Vice President of Cogentrix since November 1992 and a Director of Cogentrix since 1988. From 1991 to 1992, he was Senior Vice President of Operations responsible for the daily operations of the Company's facilities. From 1989 to 1991, Mr. Lewis was Vice President -- Utility Operations. Mr. Lewis joined Cogentrix in 1986 and in 1987, he was selected as Assistant Project Manager responsible for the construction of the Company's Portsmouth Facility. James Lewis is a son of George T. Lewis, Jr. and Betty G. Lewis.
ROBERT W. LEWIS has been a Director of the Company since its formation, prior to which he was a Director of Cogentrix since 1988. In April 1991, Mr. Lewis resigned from his positions of Vice Chairman and Secretary of Cogentrix which he had held since March 1991. Since his resignation as an officer, Mr. Lewis has served as a consultant to the Company. From October 1990 to March 1991, Mr. Lewis was Executive Vice President and Secretary. From March 1988 to October 1990, Mr. Lewis was Senior Vice President -- Corporate Development and Secretary, in which position Mr. Lewis was in charge of Cogentrix's development efforts. From March 1987 to March 1988, Mr. Lewis was Senior Vice President -- Administration and Secretary. From September 1983 to March 1987, Mr. Lewis was Vice President -- Administration and Secretary. Mr. Lewis joined Cogentrix in April 1983 and served as Secretary through September 1983. Robert Lewis is a son of George T. Lewis, Jr. and Betty G. Lewis.
DENNIS W. ALEXANDER has been Group Senior Vice President, General Counsel, Secretary and a Director since joining the Company in February 1994. Immediately prior to joining the Company, Mr. Alexander was Vice President/General Counsel of Wheelabrator Environmental Systems Inc., the waste-to-energy and cogeneration subsidiary of Wheelabrator Technologies Inc., an independent power and environmental services and products company, as well as Director, Environmental, Health and Safety Audit Program for Wheelabrator Technologies Inc. From 1988 to 1990, Mr. Alexander was Vice President/General Counsel -- Operations of Wheelabrator Environmental Systems Inc. and from 1986 to 1988 was Vice President/General Counsel of Wheelabrator Energy Systems, a cogeneration project development subsidiary. From 1984 to 1986, he served as Group General Counsel for The Signal Company and from 1980 to 1984 as Division General Counsel of Wheelabrator-Frye Inc., each a diversified public company.
W. E. BILL GARRETT has been a Director of the Company since its formation and became a Director of Cogentrix in September 1993. Mr. Garrett served on the staff of the National Geographic Society for 36 years -- the last 10 as Editor-in-Chief of the magazine. As a member of the Board of Trustees of the National Geographic Society and its Research and Exploration Committee, he was instrumental in the Society's emergence as the world's largest educational and scientific institution. He resigned in 1990 and became the President of the La Ruta Maya Conservation Foundation, which is involved in cultural and conservation work with the Maya Indians. Mexico, Guatemala and Italy have honored him with prestigious awards for his work in the region. Mr. Garrett currently serves on the boards of the National Capital Bicentennial Celebration, the American Land Conservancy, and Partners for Livable Communities.
JOHN A. TILLINGHAST was elected a Director of the Company on March 19, 1998, filling a position left vacant since the death of former board member T. Louis Austin, Jr. last year. Mr. Tillinghast has served since 1994 as President, Chairman and CEO of Great Bay Power Corporation, a public utility in Dover, New Hampshire. He also has served since 1997 as the President, Chairman and CEO of BayCorp Holdings, Ltd., the holding company for Great Bay Power Corporation. After graduating from Columbia University in 1949 with BS and MS degrees in mechanical engineering, Mr. Tillinghast began a 30-year career with American Electric Power Company, rising through the engineering ranks to become Vice Chairman of the Board in charge of engineering and construction. Prior to his current position at Great Bay Power Corporation, he served as Chairman of the Energy Engineering Board of the National Academy of Sciences, Director of the Edison Electric Institute and is a Fellow of the American Society of Mechanical Engineers. Mr. Tillinghast is registered as a professional engineer in nine states and holds two U.S. and seven foreign patents.
JAMES R. PAGANO has been Group Senior Vice President -- Chief Financial Officer of the Company since May 1997, prior to which he was Senior Vice President -- Project Finance since February 1995 and Vice President -- Project Finance since the Company's formation. Previously, Mr. Pagano was Vice President - -- Project Finance of Cogentrix since July 1993, Vice President -- Legal and Finance from July 1992 to July 1993, and from January 1992 to July 1992, Mr. Pagano was Vice President and Assistant General Counsel of Cogentrix. Prior to joining Cogentrix, he was Vice President of The Deerpath Group, Inc., a financial advisory firm. From 1987 to 1990, Mr. Pagano was an Associate with the law firm of Simpson Thacher & Bartlett.
B. YAMIN AFSHAR was appointed Senior Vice President - Marketing and Development of the Company in September 1997, prior to which he was Senior Vice President -- International Development since joining the Company in 1994. Mr. Afshar is responsible for identifying and managing the development of independent power opportunities for the Company. Prior to joining the Company, Mr. Afshar was employed by Parsons Main International, Inc. for more than 20 years. His experience includes extensive work in Asia, Latin America and the Middle East, developing and successfully negotiating contracts with suppliers and contractors relating to power projects abroad.
KARTAR B. SINGH has been Senior Vice President -- Estimating and Cost Scheduling of the Company since its formation, prior to which he held the same position of Cogentrix since 1988 and also the positions of Assistant to President from 1987 to 1991 and Assistant to Chairman from 1991. From 1983 to 1984, he was Chief Estimator and Project Manager. From 1979 to 1983, Mr. Singh was Chief Estimator and Chief Planning and Scheduling Engineer with Main. Mr. Singh has 32 years' experience in engineering, estimating, planning and scheduling and construction in the utility and industrial sector.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following table sets forth information for the calendar year ended December 31, 1997 and for the two fiscal years ended June 30, 1997 concerning the annual compensation paid or accrued by the Company to or for the account of each of the following: (i) the only person who served as the chief executive officer of the Company during the calendar year ended December 31, 1997 and (ii) the four most highly compensated executive officers of the Company incumbent at December 31, 1997, other than the chief executive officer, for the year then ended (collectively, the "Named Executive Officers").
SUMMARY COMPENSATION TABLE
(1) Amounts listed in this column include all fees for service on the Company's board of directors. (2) Amounts listed in this column reflect annual performance bonuses and annual distributions under the Profit-Sharing Plan and Facility Cash Flow Incentive Compensation Agreements discussed below. The amounts listed do not include the distributions made under such plan and agreements to the Named Executive Officers during any fiscal year in which such distribution was earned in the previous fiscal year. (3) The amounts shown in this column include (i) the Company's matching contributions on behalf of the Named Executive Officers to the Company's 401(k) savings plan in which all Company employees are eligible to participate and to a non-qualified Supplemental Retirement Savings Plan in which approximately 33 employees, including all of the Named Executive Officers participate, and (ii) the payments made to David J. Lewis, James E. Lewis and George T. Lewis, Jr. related to the termination of the facility cash flow incentive compensation agreements, net of the awards each of these Named Executive Officers would have otherwise received under these plans for the fiscal year ended June 30, 1997, which amounts are included under the column heading "Bonuses."
COMPENSATION PURSUANT TO INCENTIVE COMPENSATION PLANS
Profit-Sharing Plan
The Company has a non-qualified incentive compensation plan for the benefit of approximately 42 employees of the Company and its affiliates (the "Profit-Sharing Plan"). Under the Profit-Sharing Plan, the Company has entered into arrangements with each of its executive officers, which provide for annual cash compensation distribution awards to each participant equal to a designated percentage of the Company's adjusted net income before taxes each fiscal year plus the amount of any accrual for payments to be made under the Profit-Sharing Plan (the "Designated Percentage"), with the Designated Percentage determined annually at the discretion of the Company's Chief Executive Officer or Chief Operating Officer based on criteria they deem appropriate. No payments were made under the Profit-Sharing Plan for the fiscal year ended June 30, 1997. For the twelve-month period ended December 31, 1997, David J. Lewis earned $190,065, James E. Lewis earned $114,039, and James R. Pagano and Dennis W. Alexander each earned $95,033 under the Profit Sharing Plan, all of which was earned during the six-month period ended December 31, 1997.
In the event a participant in the Profit-Sharing Plan terminates his or her employment with the Company (for a reason other than death, total disability, retirement or termination by the Company for willful misconduct), the participant is entitled to receive a severance benefit equal to a percentage (ranging from 100% after six years of full-time employment to a maximum of 200% after ten years or more of full-time employment) of the most recent annual distribution to which the employee is then entitled. In the event of a participant's death or total disability, the participant (or his or her beneficiary) is entitled to receive from zero to five years of annual distribution awards thereafter, depending upon the participant's length of service with the Company.
Executive Incentive Bonus Plan
In addition to the annual cash compensation distribution awards payable under the Profit-Sharing Plan or the Facility Cash Flow Incentive Compensation Agreement described below, certain executive officers, including David J. Lewis, James E. Lewis, Mark F. Miller, Dennis W. Alexander and James R. Pagano may receive additional incentive cash compensation awards, determined on a sliding scale, if the Company achieves certain designated net income before income tax targets for a given fiscal year. No such additional incentive cash compensation awards were earned during the fiscal year ended June 30, 1997 or during the twelve-month period ended December 31, 1997.
Facility Cash Flow Incentive Compensation Agreements
The Company had entered into non-qualified incentive compensation agreements with three of the Named Executive Officers, David J. Lewis, James E. Lewis and George T. Lewis, Jr., each of whom is a director and a shareholder of the Company. Such agreements provided for each of these Named Executive Officers to receive through June 30, 2007, annual distributions equal to a designated percentage of the net cash flow for the fiscal year of one or both of two of the Company's facilities. In fiscal 1997, the Company terminated the facility cash flow incentive compensation agreements with these named executive officers. In connection with the termination of these plans, David J. Lewis, James E. Lewis and George T. Lewis, Jr. were paid $1,157,996, $1,119,816 and $1,247,259, respectively.
EMPLOYMENT AGREEMENTS WITH NAMED EXECUTIVE OFFICERS
David J. Lewis
In August 1995, the board of directors elected David J. Lewis Vice Chairman and Chief Executive Officer of the Company. George T. Lewis, Jr., the former Chief Executive Officer, will continue to serve as Chairman of the Board. The Company has an employment agreement with David J. Lewis through August 2000, which provides for a base annual salary. In addition to the base salary, Mr. Lewis is entitled to receive annual incentive compensation in an amount determined by the board of directors, which amount, when combined with the base salary payable to him, shall be at least sufficient to provide him with total annual compensation that is competitive with total annual compensation offered by other similarly situated companies to their employees in comparable positions.
The employment agreement is terminable upon notice given by the Company in the event a majority of the board of directors terminates Mr. Lewis's employment for cause. In addition, the Company may terminate the agreement at any time at its option in the event that the board determines in its reasonable, good faith judgment, and by a vote of at least two-thirds of the directors then in office, that the continued service of Mr. Lewis as Chief Executive Officer of the Company would not be in the best interest of the Company because there has occurred a continued failure by him (whether or not such failure resulted from his physical or mental incapacity) substantially to perform his duties, responsibilities or obligations as Chief Executive Officer after having been given written notice of such failure to perform and after having failed to improve such performance within the time period (which shall have been a reasonable time period) specified in such notice. Mr. Lewis may terminate his employment agreement at any time at his option in the event of a Change of Control (as defined) of the Company.
George T. Lewis, Jr.
In August 1995, the Company entered into a five-year employment and noncompetition agreement with George T. Lewis, Jr., a shareholder and Chairman of the Board. Under the terms of the agreement, Mr. Lewis is required to be fully available to the Company during customary business hours for consultations, either in person or by telephone, with respect to such of the Company's business and affairs as the Company may reasonably call on him to furnish. In addition, the restrictive covenants of the agreement substantially limit Mr. Lewis' ability to engage in consulting arrangements for other companies and prohibit his support of any company in the energy industry. Pursuant to the agreement, Mr. Lewis will receive base compensation, adjusted annually based on an inflationary index, as well as performance bonuses, the amount of which will be determined in accordance with Company policy by the Chief Executive Officer in consultation with the Chief Operating Officer. Mr. Lewis received base compensation of $646,000 for the year ended December 31, 1997.
In the event of Mr. Lewis' death or inability to provide services due to disability, the agreement shall terminate and the Company is obligated to continue making payments to him or to his estate for a period of six months after such termination. The Company may terminate this agreement for cause at any time, and Mr. Lewis may voluntarily terminate this agreement at any time. In either case, Mr. Lewis shall not be entitled to any further payments or benefits under the consulting agreement. In the event the Company terminates this agreement without cause, Mr. Lewis is entitled to receive all payments and benefits which would have been earned throughout the term of this consulting agreement.
Dennis W. Alexander
When he joined the Company in January 1994, the Company entered into an employment agreement with Dennis W. Alexander to serve as Senior Vice President, General Counsel and Secretary. The Agreement also provides that Mr. Alexander shall be a member of the Board of Directors. Under the employment agreement, Mr. Alexander is entitled to a minimum base annual salary of $180,000, subject to adjustment in future years. He is also entitled to participate in the Company's Profit Sharing Plan (at a level of no less than 0.3% of net income before taxes) and Executive Incentive Bonus Plan. The employment agreement is for a one year term that renews automatically at the end of each calendar year unless the Company previously exercises its right to terminate Mr. Alexander. The Company has the right to terminate Mr. Alexander upon 30 days' written notice (with a material change in his title, authority, duties or current compensation following a change in control of the Company constituting a de facto termination by the Company). In the event the Company terminates his employment, Mr. Alexander is entitled to receive (within 30 days of his termination) a severance payment in an amount equal to his total compensation received in the prior calendar year (including any fees he received for serving as a member of the Board of Directors).
DIRECTORS' COMPENSATION AND CONSULTING AGREEMENTS
Directors, including employee directors, receive an annual retainer of $25,000 for service on the board of directors. In addition, for each meeting attended, each director receives a fee of $1,000. During the year ended December 31, 1997, there were five meetings of the Company's board of directors.
The Company has entered into a consulting agreement with Mr. Garrett that provides for payment to him of $15,000 annually for consulting services to be rendered to the Company.
While he was employed as an executive officer, Cogentrix entered into a non-qualified incentive compensation agreement with Robert W. Lewis similar to the agreements described above under "Facility Cash Flow Incentive Compensation Agreements" providing for him to receive incentive compensation annually equal to a designated percentage of the net cash flow for the fiscal year of two of the Company's facilities. The Company's obligation to make such annual payments to him continues through June 30, 2007. The Company has agreed to pay him an annual minimum payment of $200,000 regardless of whether his actual annual distribution would yield such amount. Robert W. Lewis must repay to the Company, on or before January 31, 2008, an amount equal to the aggregate amount of minimum payments made in excess of the actual annual distributions which he was entitled to receive. The actual amount of the distribution Mr. Lewis received pursuant to his facility cash flow compensation agreement for the six-month period ended December 31, 1997 was $100,000.
If at any time through June 1, 2007 Mr. Lewis sells or transfers any of the shares of common stock of the Company held by him to anyone other than certain other members of the Lewis family without granting the Company a right of first refusal with respect to the shares sold or transferred, he will forfeit his right to the annual distributions under his facility cash flow incentive compensation agreement and the right to the annual minimum payment of $200,000.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All of the issued and outstanding shares of common stock of the Company are beneficially owned by George T. Lewis, Jr., Betty G. Lewis and their three sons: David J. Lewis, James E. Lewis and Robert W. Lewis. The number of shares and the percentage of the total number of shares beneficially owned by each are shown below.
(1) George T. Lewis, Jr.'s shares are held of record by a revocable grantor trust (the "Trust") that may be revoked by Mr. Lewis at any time prior to his death, in which event the shares held by the Trust would be transferred to him. Accordingly, he is deemed to be the beneficial owner of the shares held by the Trust. (2) The 73,320 shares shown as beneficially owned by Mr. Fennebresque are all held of record by the Trust described in Note 1 above. Mr. Fennebresque is deemed to be the beneficial owner of these shares, because he is the sole trustee of the Trust and, as such, has the power to vote and invest the shares held by the Trust. Since George T. Lewis, Jr. is also deemed to be the beneficial owner of these shares, they are also included in the amount shown for the number of shares beneficially owned by George T. Lewis, Jr.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The transactions described or referred to below were entered into between related parties. In connection with the public offering of the Company's Senior Notes conducted in March 1994, the Company's board of directors adopted a policy that all subsequent material transactions with related parties must be on terms no less favorable than could be obtained from third parties and that any variance from this policy is subject to approval by a majority of the Company's disinterested directors. The Indenture under which the Senior Notes were issued and the covenants of the Credit Facility place certain limitations on the Company's ability to enter into material transactions with related parties as well.
LEASES AND REAL PROPERTY TRANSACTIONS
Equipment Leasing Partners ("ELP"), a North Carolina general partnership consisting of four of the Company's shareholders, George T. Lewis, Jr., David J. Lewis, James E. Lewis and Robert W. Lewis, owns and leases certain equipment to the Company's project subsidiaries related to the operations of the plants. Each of the partners in ELP is a member of the
Company's board of directors. David J. Lewis, James E. Lewis and George T. Lewis, Jr. are also executive officers of the Company. Total rent paid by the Company to ELP under such equipment leases was $329,892 for the six-month period ended December 31, 1997, $1,021,400 for the fiscal year ended June 30, 1997, $1,112,000 for the fiscal year ended June 30, 1996 and $1,244,000 for the fiscal year ended June 30, 1995.
ELP also owns and leases to the Company the Company's executive offices under a long term lease with an initial term expiring in 2004. Total rent paid by the Company to ELP under such lease was $398,526 for the six-month period ended December 31, 1997, $834,000 for the fiscal year ended June 30, 1997, $817,000 in the fiscal year ended June 30, 1996, and $801,000 for the fiscal year ended June 30, 1995.
ELP leases the land on which the Company's executive offices are located under a long-term ground lease from an unrelated third party with an initial term expiring in 2047, all payments under which are guaranteed by Cogentrix. Total amounts paid by ELP under such lease were $56,000 for the six-month period ended December 31, 1997 and $112,000 for each of the years ended June 30, 1997, 1996 and 1995.
INDEBTEDNESS OF MANAGEMENT
The Company has from time to time made loans and advances to certain shareholders, each of whom is also a director of the Company. The largest aggregate amount of indebtedness outstanding exceeding $60,000 at any time during the six-month period ended December 31, 1997 for these shareholders and the outstanding balances at December 31, 1997 were as follows:
The loans to George T. Lewis, Jr. were made at interest rates equal in each case to the prime rate of certain designated banks plus one percent.
Cogentrix has also from time to time made loans to ELP for the purpose of financing purchases of equipment. These loans were made at variable rates of interest equal to the prime rate of designated banks plus approximately two percentage points. The largest aggregate amount of indebtedness of ELP to Cogentrix outstanding during the six-month period ended December 31, 1997 was $44,000. ELP had no indebtedness to Cogentrix as of December 31, 1997.
FACILITY CASH FLOW INCENTIVE COMPENSATION AGREEMENTS
The Company has entered into agreements with four of the beneficial owners of the Company's outstanding shares of common stock, three of whom are executive officers of the Company (the fourth being a former executive officer) and each of whom is a director, that provide for them to receive annual distributions equal to a designated percentage of the net cash flow for each fiscal year of one or both of two of the Company's facilities. During the fiscal year ended June 30, 1997, the Company terminated these agreements for the three executive officers. See "Executive Compensation --Compensation Pursuant to Incentive Compensation Plans -- Facility Cash Flow Incentive Compensation Agreements --Directors' Compensation and Consulting Agreements" herein.
SHAREHOLDER STOCK TRANSFER AGREEMENT
In August 1994, George T. Lewis, Jr. entered into an agreement with Betty G. Lewis ("Ms. Lewis") providing for, among other things, the transfer by George T. Lewis, Jr. of a portion of his shares of the Company's common stock to Ms. Lewis.
In accordance with the agreement, if Ms. Lewis desires to transfer or otherwise dispose of any of her shares of common stock of the Company, she must first offer to sell them to the Company at a price equal to a bona fide offer from an unrelated party. Any shares, the offer of sale of which is not accepted by the Company after receipt of the written offer, must be offered by Ms. Lewis at the same price to the other shareholders, who have the right to purchase such shares on a pro rata basis determined in accordance with the then current stock ownership of those shareholders. In the event neither the Company nor the other shareholders notify Ms. Lewis of its or their intention to purchase her shares within 15 days after receipt of the written offer, Ms. Lewis shall have the right for 90 days thereafter to consummate the sale of her shares with the unrelated party who provided the bona fide offer.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements, Financial Statement Schedules and Exhibits - The following documents are filed as part of this Form 10-K.
(1) Consolidated Financial Statements - See index on page 45.
(2) Financial Statement Schedules - See index on page 45.
(3) Index to Exhibits.
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(*) Portions of these agreements have been deleted pursuant to previously approved requests for confidential treatment. (**) Portions of these agreements have been deleted pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. (1) Incorporated by reference to Registration Statement on Form S-1 (File No. 33-74254) filed January 19, 1994. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (2) Incorporated by reference to Amendment No. 1 to Registration Statement on Form S-1 (File No. 33-74254) filed February 24, 1994. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (3) Incorporated by reference to Amendment No. 2 to Registration Statement on Form S-1 (File No. 33-74254) filed March 7, 1994. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (4) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed May 16, 1994. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (5) Incorporated by reference to the Form 10-K (File No. 33-74254) filed September 28, 1994. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (6) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed November 14, 1994. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (7) Incorporated by reference to the Form 8-K (File No. 33-74254) filed December 29, 1994. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (8) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed February 14, 1995. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above.
(9) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed May 16, 1995. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (10) Incorporated by reference to the Form 10-K (File No. 33-74254) filed September 28, 1995. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (11) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed November 14, 1995. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (12) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed May 3, 1996. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (13) Incorporated by reference to the Form 10-K (File No. 33-74254) filed October 10, 1996. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (14) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed February 14, 1997. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (15) Incorporated by reference to the Form 10-Q (File No. 33-74254) filed May 15, 1997. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above. (16) Incorporated by reference to the Form 10-K (File No. 33-74254) filed September 29, 1997. The number designating the exhibit on the exhibit index to such previously-filed report is enclosed in parentheses at the end of the description of the exhibit above.
(b) Reports on Form 8-K.
The Company filed a Current Report on Form 8-K, dated December 5, 1997, with respect to the official signing of three project documents with the Indian State of Karnataka related to the Mangalore Power Project, being co-developed in India by Cogentrix Energy, Inc. and China Light & Power (International), Ltd.
SIGNATURES.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
COGENTRIX ENERGY, INC. (Registrant)
Date: March 30, 1998 By: /s/ David J. Lewis ------------------------------------ David J. Lewis Vice Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of Registrant and in the capacities and on the dates indicated.