Item 1. BUSINESS - --------------------------------------------------------------------------------
GENERAL
AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company which owns, directly or indirectly, all of the outstanding common stock of its domestic electric utility subsidiaries and varying percentages of other subsidiaries. Substantially all of the operating revenues of AEP and its subsidiaries are derived from the furnishing of electric service. In addition, in recent years AEP has been pursuing various unregulated business opportunities worldwide as discussed in New Business Development.
The service area of AEP's domestic electric utility subsidiaries covers portions of the states of Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. The generating and transmission facilities of AEP's subsidiaries are physically interconnected, and their operations are coordinated, as a single integrated electric utility system. Transmission networks are interconnected with extensive distribution facilities in the territories served. The electric utility subsidiaries of AEP, which do business as "American Electric Power," have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers.
At December 31, 1999, the subsidiaries of AEP had a total of 17,306 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are:
APCo (organized in Virginia in 1926) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 896,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying electric power at wholesale to other electric utility companies and municipalities in those states and in Tennessee. At December 31, 1999, APCo and its wholly owned subsidiaries had 3,290 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies: Carolina Power & Light Company, Duke Energy Corporation and VEPCo. A comparatively small part of the properties and business of APCo is located in the northeastern end of the Tennessee Valley. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 655,000 customers in Ohio, and in supplying electric power at wholesale to other electric utilities and to municipally owned distribution systems within its service area. At December 31, 1999, CSPCo had 1,466 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Approximately 80% of CSPCo's retail revenues are derived from the Columbus area. Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.
I&M (organized in Indiana in 1925) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 559,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric power at wholesale to other electric utility companies, rural electric cooperatives and municipalities. At December 31, 1999, I&M had 3,130 employees. Among the principal industries
served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company.
KEPCo (organized in Kentucky in 1919) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 171,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1999, KEPCo had 501 employees. In addition to its AEP System interconnections, KEPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KEPCo is also interconnected with TVA.
Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately 45,000 customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from APCo. At December 31, 1999, Kingsport Power Company had 62 employees.
OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 691,000 customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying electric power at wholesale to other electric utility companies and municipalities. At December 31, 1999, OPCo and its wholly owned subsidiaries had 3,941 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company.
Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 42,000 customers in northern West Virginia. Wheeling Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 1999, Wheeling Power Company had 74 employees.
Another principal electric utility subsidiary of AEP is AEGCo, which was organized in Ohio in 1982 as an electric generating company. AEGCo sells power at wholesale to I&M and KEPCo. AEGCo's agreement to sell power to VEPCo expired December 31, 1999. AEGCo has no employees.
See Item 2
Item 2 herein for a discussion of recovery of fuel costs.
OPCo
Under the terms of a stipulation agreement approved by the PUCO in November 1992, beginning December 1, 1994, the cost of coal burned at the Gavin Plant is subject to a 15-year predetermined price of $1.575 per million Btus with quarterly escalation adjustments. A 1995 PUCO-approved settlement agreement fixed the electric fuel component factor at 1.465 cents per kwh for the period June 1995 through November 1998. After the first to occur of either full recovery of these costs or November 2009, the price that OPCo can recover for coal from its affiliated Meigs mine which supplies the Gavin Plant will be limited to the lower of cost or the then-current market price. The agreements provide OPCo with the opportunity to recover any operating losses incurred under the predetermined or fixed price, as well as its investment in, and liabilities and closing costs associated with, its affiliated mining operations attributable to its Ohio jurisdiction, to the extent the actual cost of coal burned at the Gavin Plant is below the predetermined price.
As a result of the Ohio electric utility restructuring law discussed in Competition and Business Change--Ohio, beginning in 2001, fuel adjustment proceedings in Ohio cease, thus ending the recovery mechanism in the 1992 and 1995 agreements and specifically ceasing the escalation feature of the Gavin cap. Therefore, OPCo must now rely on the transition charge for recovery of the
deferred fuel cost regulatory asset balance after December 31, 2000.
The Muskingum mine, which supplied coal to the Muskingum River Plant Units 1-4, ceased operation in October 1999 with the exception of a limited amount of economically viable coal production ancillary to the reclamation activities. The Windsor mine, which supplies Cardinal Plant Unit 1, is scheduled to close in April 2000. The Meigs mine is scheduled to close in December 2001. These mines are closing, in part, as a result of compliance with the Phase II requirements of the Clean Air Act Amendments of 1990 (see Environmental and Other Matters -- Air Pollution Control -- Acid Rain). Unless future shutdown costs and/or the cost of coal production of OPCo's Muskingum, Windsor and Meigs mines, including amounts deferred, can be recovered, AEP's and OPCo's results of operations would be adversely affected.
FUEL SUPPLY
The following table shows the sources of power generated by the AEP System:
Variations in the generation of nuclear power are primarily related to refueling outages and, for 1997 through 1999, the shutdown of the Cook Plant to respond to issues raised by the NRC. See Cook Nuclear Plant -- Cook Plant Shutdown.
Coal
The Clean Air Act Amendments of 1990 provide for the issuance of annual allowance allocations covering sulfur dioxide emissions at levels below historic emission levels for many coal-fired generating units of the AEP System. Phase I of this program began in 1995 and Phase II begins in 2000, with both phases requiring significant changes in coal supplies and suppliers. The full extent of such changes, particularly in regard to Phase II, however, has not been determined. See Environmental and Other Matters -- Air Pollution Control -- Acid Rain for the current compliance plan.
In order to meet emission standards for existing and new emission sources, the AEP System companies will, in any event, have to obtain coal supplies, in addition to coal reserves now owned by System companies, through the acquisition of additional coal reserves and/or by entering into additional supply agreements, either on a long-term or spot basis, at prices and upon terms which cannot now be predicted.
No representation is made that any of the coal rights owned or controlled by the System will, in future years, produce for the System any major portion of the overall coal supply needed for consumption at the coal-fired generating units of the System. Although AEP believes that in the long run it will be able to secure coal of adequate quality and in adequate quantities to enable existing and new units to comply with emission standards applicable to such sources, no assurance can be given that coal of such quality and quantity will in fact be available. No assurance can be given either that statutes or regulations limiting emissions from existing and new sources will not be further revised in future years to specify lower sulfur contents than now in effect or other restrictions. See Environmental and Other Matters herein.
The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to rate-making principles by which such electric utilities would be compensated. In addition, the Federal Government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel-burning installations.
System companies have developed programs to conserve coal supplies at System plants which involve, on a progressive basis, limitations on sales of power and energy to neighboring utilities, appeals to customers for voluntary limitations of electric usage to essential needs, curtailment of sales to certain industrial customers, voltage reductions and, finally, mandatory reductions in cases where current coal supplies fall below minimum levels. Such programs have been filed and reviewed with
officials of Federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies.
The mining of coal reserves is subject to Federal requirements with respect to the development and operation of coal mines, and to state and Federal regulations relating to land reclamation and environmental protection, including Federal strip mining legislation enacted in August 1977. Continual evaluation and study is given to possible divestiture of coal properties in light of Federal and state environmental and mining laws and regulations.
Western coal purchased by System companies is transported by rail to an affiliated terminal on the Ohio River for transloading to barges for delivery to generating stations on the river. Subsidiaries of AEP lease approximately 4,055 coal hopper cars to be used in unit train movements, as well as 15 towboats, 451 jumbo barges and 145 standard barges. Subsidiaries of AEP also own or lease coal transfer facilities at various other locations.
The System generating companies procure coal from coal reserves which are owned or mined by subsidiaries of AEP, and through purchases pursuant to long-term contracts, or on a spot purchase basis, from unaffiliated producers. The following table shows the amount of coal delivered to the AEP System during the past five years, the proportion of such coal which was obtained either from coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts or through spot or short-term purchases, and the average delivered price of spot coal purchased by System companies:
The average cost of coal consumed during the past five years by all AEP System companies, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo is shown in the following tables:
The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric power, space limitations, the rate of consumption at particular plants, labor unrest and weather conditions which may interrupt deliveries. At December 31, 1999, the System's coal inventory was approximately 50 days of normal System usage. This estimate assumes that the total supply would be utilized by increasing or decreasing generation at particular plants.
The following tabulation shows the total consumption during 1999 of the coal-fired generating units of AEP's principal electric utility subsidiaries, coal requirements of these units over the remainder of their useful lives and the average sulfur content of coal delivered in 1999 to these units. Reference is made to Environmental and Other Matters for information concerning current emissions limitations in the AEP System's various jurisdictions and the effects of the Clean Air Act Amendments.
- ------------------------ (a) Reflects AEGCo's 50% interest in the Rockport Plant (b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and Zimmer Plants. (c) Includes I&M's 50% interest in the Rockport Plant.
AEGCo: See Fuel Supply -- I&M for a discussion of the coal supply for the Rockport Plant.
APCo: Substantially all of the coal consumed at APCo's generating plants is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis.
The average sulfur content by weight of the coal received by APCo at its generating stations approximated 0.8% during 1999, whereas the maximum sulfur content permitted, for emission standard purposes, for existing plants in the regions in which APCo's generating stations are located ranged between 0.78% and 2% by weight depending in some circumstances on the calorific value of the coal which can be obtained for some generating stations.
CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,150,000 tons per year through 2001. Some of this coal is washed to improve its quality and consistency for use principally at Unit 4 of the Conesville Plant.
CSPCo has been informed by CG&E and DP&L that, with respect to the CCD Group units partly owned but not operated by CSPCo, sufficient coal has been contracted for or is believed to be available for the approximate lives of the respective units operated by them. Under the terms of the operating agreements with respect to CCD Group units, each operating company is contractually responsible for obtaining the needed fuel.
I&M: I&M has two coal supply agreements with unaffiliated suppliers pursuant to which the suppliers are delivering low sulfur coal from surface mines in Wyoming, principally for consumption by the Rockport Plant. Under these agreements, the suppliers will sell to I&M, for consumption by I&M at the Rockport Plant or consignment to other System companies, coal with an average sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of heat input. One contract with remaining deliveries of 46,510,000 tons expires on
December 31, 2014 and another contract with remaining deliveries of 32,175,000 tons expires on December 31, 2004.
All of the coal consumed at I&M's Tanners Creek Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis.
KEPCo: Substantially all of the coal consumed at KEPCo's Big Sandy Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers pursuant to which KEPCo will receive approximately 2,300,000 tons of coal in 2000. To the extent that KEPCo has additional coal requirements, it may purchase coal from the spot market and/or suppliers under contract to supply other System companies.
OPCo: The coal consumed at OPCo's generating plants is obtained from both affiliated and unaffiliated suppliers. The coal obtained from unaffiliated suppliers is purchased under long-term contracts and/or on a spot purchase basis.
OPCo and certain of its coal-mining subsidiaries own or control coal reserves in the State of Ohio containing approximately 184,000,000 tons of clean recoverable coal and ranging in sulfur content between 3.4% and 4.5% sulfur by weight (weighted average, 3.8%), which reserves are presently being mined. OPCo and certain of its mining subsidiaries own an additional 113,000,000 tons of clean recoverable coal in Ohio which ranges in sulfur content between 2.4% and 3.4% sulfur by weight (weighted average 2.7%). Recovery of this coal would require substantial development.
OPCo and certain of its coal-mining subsidiaries also own or control coal reserves in the State of West Virginia which contain approximately 100,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 4.0% sulfur by weight (weighted average, 2.1%) of which approximately 23,000,000 tons can be recovered based upon existing mining plans and projections and employing current mining practices and techniques.
Nuclear
I&M has made commitments to meet certain of the nuclear fuel requirements of the Cook Plant. The nuclear fuel cycle consists of:
o Mining and milling of uranium ore to uranium concentrates.
o Conversion of uranium concentrates to uranium hexafluoride.
o Enrichment of uranium hexafluoride.
o Fabrication of fuel assemblies.
o Utilization of nuclear fuel in the reactor.
o Disposition of spent fuel.
Steps currently are being taken, based upon the planned fuel cycles for the Cook Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel. I&M has made and will make purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted.
For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012.
I&M's costs of nuclear fuel consumed do not assume any residual or salvage value for residual plutonium and uranium.
Nuclear Waste and Decommissioning
The Nuclear Waste Policy Act of 1982, as amended, establishes Federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste. Disposal costs are paid by fees assessed against owners of nuclear plants and deposited into the Nuclear Waste Fund created by the Act. In 1983, I&M entered into a contract with DOE for the disposal of spent nuclear fuel. Under terms of the contract, for the disposal of nuclear fuel consumed after April 6, 1983 by I&M's Cook Plant, I&M is paying to the fund a fee of one
mill per kilowatt-hour, which I&M is currently recovering from customers. For the disposal of nuclear fuel consumed prior to April 7, 1983, I&M must pay the U.S. Treasury a fee estimated at approximately $72,000,000, exclusive of interest of $127,000,000 at December 31, 1999. The aggregate amount has been recorded as long-term debt. Because of the current uncertainties surrounding DOE's program to provide for permanent disposal of spent nuclear fuel, I&M has not yet paid any of the pre-April 1983 fee. At December 31, 1999, funds collected from customers to pay the pre-April 1983 fee and accrued interest approximated the long-term liability. In November 1996, the IURC and MPSC issued orders approving flexible funding procedures in which any excess funds collected for pre-April 7, 1983 spent nuclear fuel disposal would be deposited into I&M's nuclear decommissioning trust funds.
On May 30, 1995, I&M and a group of unaffiliated utilities owning and operating nuclear plants filed a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court issue a declaration that the Nuclear Waste Policy Act of 1982 (NWPA) imposes on DOE an unconditional obligation to begin acceptance of spent nuclear fuel and high level radioactive waste by January 31, 1998. On July 23, 1996, the court ruled that the NWPA creates an obligation for DOE, reciprocal to the utilities' obligation to pay, to start disposing of the spent nuclear fuel and high level radioactive waste no later than January 31, 1998. The court remanded the case to DOE, holding that determination of a remedy was premature, since DOE had not yet defaulted on its obligations.
In December 1996, I&M received a letter from DOE advising that DOE anticipates that it will be unable to begin acceptance of spent nuclear fuel and high level radioactive waste for disposal in a repository or interim storage facility by January 31, 1998. On January 31, 1997, in anticipation of DOE's breach of their statutory and contractual obligations, I&M along with 35 unaffiliated utilities and 33 states filed joint petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court permit the utilities to suspend further payments into the nuclear waste fund, authorize escrow of the payments, and order further action on the part of DOE to meet its obligations under the NWPA. On November 12, 1997, the Court of Appeals issued a decision granting in part and denying in part the utilities' request for relief. The court ordered DOE to proceed with contractual remedies and to refrain from concluding that DOE's delay is unavoidable due to the lack of a repository or the lack of interim storage authority. The court, however, declined to order DOE to begin disposing of fuel. On January 31, 1998, the deadline for DOE's performance, the DOE failed to begin disposing of the utilities' spent nuclear fuel. DOE estimates its planned site for spent nuclear fuel will not be ready until at least 2010.
On June 8, 1998, I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150,000,000 due to the U.S. Department of Energy's partial material breach of its unconditional contractual deadline to begin disposing of spent nuclear fuel and high level nuclear waste generated by the Cook Nuclear Plant. Similar lawsuits have been filed by other utilities. On April 6, 1999, the court granted DOE's motion to dismiss a lawsuit file by an unaffiliated utility. On May 20, 1999, the other utility appealed this decision to the U.S. Court of Appeals for the Federal Circuit. I&M's case has been stayed pending final resolution of the other utility's appeal.
Studies completed in 1997 estimate decommissioning and low-level radioactive waste disposal costs for the Cook Plant to range from $700,000,000 to $1.152 billion in 1997 nondiscounted dollars. The wide range is caused by variables in assumptions, including the estimated length of time spent nuclear fuel must be stored at the Cook Plant subsequent to ceasing operations, which depends on future developments in the federal government's spent nuclear fuel disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent respective decommissioning study available at the time of the rate proceeding (the study range utilized in the Indiana rate case, I&M's primary jurisdiction, was $588,000,000 to $1.102
billion in 1991 dollars). I&M records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates which was $28,000,000 in 1999, $29,000,000 in 1998, and $28,000,000 in 1997. At December 31, 1999 and 1998, I&M had recognized a decommissioning liability of $501,000,000 and $446,000,000, respectively. I&M will continue to reevaluate periodically the cost of decommissioning and to seek regulatory approval to revise its rates as necessary.
Funds recovered through the rate-making process for disposal of spent nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning have been segregated and deposited in external funds for the future payment of such costs. Trust fund earnings decrease the amount to be recovered from ratepayers.
The ultimate cost of retiring I&M's Cook Plant may be materially different from the estimates contained in the site-specific study and the funding targets as a result of the:
o Type of decommissioning plan selected.
o Escalation of various cost elements (including, but not limited to, general inflation).
o Further development of regulatory requirements governing decommissioning.
o Limited availability to date of significant experience in decommissioning such facilities.
o Technology available at the time of decommissioning differing significantly from that assumed in these studies.
o Availability of nuclear waste disposal facilities.
Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly greater than current projections.
Low-Level Waste: The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the responsibility for the disposal of low-level waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. To facilitate this approach, the LLWPA authorized states to enter into regional compacts for low-level waste disposal subject to Congressional approval. The LLWPA also specified that, beginning in 1986, approved compacts may prohibit the importation of low-level waste from other regions, thereby providing a strong incentive for states to enter into compacts. Michigan, the state where the Cook Plant is located, was a member of the Midwest Compact, but its membership was revoked in 1991. As a result, Michigan is responsible for developing a disposal site for the low-level waste generated in Michigan.
Although Michigan amended its law regarding low-level waste site development in 1994 to allow a volunteer to host a facility, little progress has been made to date. A bill was introduced in 1996 to further address the issue but no action was taken. Development of required legislation and progress with the site selection process has been inhibited by many factors, and management is unable to predict when a new disposal site for Michigan low-level waste will be available.
On July 1, 1995, the disposal site in South Carolina reopened to accept waste from most areas of the U.S., including Michigan. This was the first opportunity for the Cook Plant to dispose of low-level waste since 1990. To the extent practicable, the waste formerly placed in storage and the waste presently generated are now being sent to the disposal site.
Energy Policy Act -- Nuclear Fees
The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the decontamination and decommissioning of uranium enrichment facilities formerly owned by DOE. Funding is to be provided from a combination of sources including assessments against electric utilities which purchased enrichment services from DOE facilities. I&M's remaining estimated liability is $32,000,000, subject to inflation adjustments, and is payable in annual assessments over the next seven years. I&M recorded a regulatory asset concurrent with the
recording of the liability. The payments are being recorded and recovered as fuel expense over a 15-year period ending in 2007.
I&M has joined with 25 other utility plaintiffs in filing a complaint in the U.S. District Court for the Southern District of New York seeking a declaratory judgment that the annual decontamination and decommissioning assessments are unconstitutional. I&M's claims for refund of previously paid assessments remain pending in the U.S. Court of Federal Claims. I&M is seeking to stay the Court of Federal Claims action pending the outcome of the District Court action.
ENVIRONMENTAL AND OTHER MATTERS
AEP's subsidiaries are subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions.
It is expected that costs related to environmental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries and that AEP's electric utility subsidiaries will be able to provide for required environmental controls. However, some customers may curtail or cease operations as a consequence of higher energy costs. There can be no assurance that all such costs will be recovered. Moreover, legislation recently adopted by certain states and proposed at the state and federal level governing restructuring of the electric utility industry may also affect the recovery of certain costs. See Competition and Business Change.
Except as noted herein, AEP's subsidiaries that own or operate generating, transmission and distribution facilities are in substantial compliance with pollution control laws and regulations.
Air Pollution Control
For the AEP System, compliance with the Clean Air Act (CAA) is requiring substantial expenditures that generally are being recovered through increases in the rates of AEP's operating subsidiaries. However, there can be no assurance that all such costs will be recovered. See Construction Program -- Construction Expenditures.
Acid Rain: The Acid Rain Program (Title IV) of the Clean Air Act Amendments of 1990 (CAAA) created an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of sulfur dioxide (SO(2)), measured in tons per year, on an aggregate basis. There are two phases of SO(2) control under the Acid Rain Program. Phase I, effective January 1, 1995, required SO(2) emission reductions from certain units that emitted SO(2) above a rate of 2.5 pounds per million Btu heat input in 1985.
Phase II, which affects all fossil fuel-fired steam generating units with capacity greater than 25 megawatts imposes more stringent SO(2) emission control requirements beginning January 1, 2000. If a unit emitted SO(2) in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the Phase II allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels.
In addition to regulating SO(2) emissions, Title IV of the CAAA regulates emissions of nitrogen oxides (NOx). Federal EPA has promulgated NOx emission limitations for all boiler types in the AEP System at levels significantly below original design. All emission limitations were to be achieved by January 1, 2000 on a unit-by-unit or System-wide average basis.
Title I National Ambient Air Quality Standards Attainment: The CAA contains additional provisions, other than the Acid Rain Program, which could require reductions in emissions of NOx and other pollutants from fossil fuel-fired power plants. See NOx SIP Call and Section 126 Petitions below.
In July 1997, Federal EPA revised the ozone and particulate matter National Ambient Air Quality Standards (NAAQS), creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter (PM(2.5)). Both of these new standards have the potential to affect adversely the operation of AEP System generating units. In May 1999, the U.S.
Court of Appeals for the District of Columbia Circuit remanded the ozone and PM(2.5) NAAQS to Federal EPA. Following denial of a request for rehearing and rehearing en banc by the Circuit Court, Federal EPA and several others filed petitions for a writ of certiorari with the U.S. Supreme Court on January 27, 2000.
In September 1998, Federal EPA issued revisions to the New Source Performance Standards applicable to new and modified fossil fuel-fired power plants. The emission limit is set at a level which will require the use of post combustion control equipment. The final rule effectively requires selective catalytic reduction or comparable technology to control NOx emissions from new or modified coal-fired boilers. On September 21, 1999, the U.S. Court of Appeals for the District of Columbia Circuit vacated the standard with respect to modified sources. On December 21, 1999, the court issued an opinion upholding the standard as it applies to new sources.
NOx SIP Call: On October 27, 1998, Federal EPA published in the Federal Register a final rule (NOx transport SIP call or NOx SIP Call) concluding that certain State Implementation Plans are deficient because they allow NOx emissions that contribute excessively to ozone non-attainment in downwind states. Federal EPA's NOx transport SIP call establishes state-by-state NOx emission budgets for the five-month ozone season to be met beginning May 1, 2003. The NOx budgets apply to 22 eastern states and the District of Columbia and are premised mainly on the assumption of controlling power plant NOx emissions projected for the year 2007 to 0.15 lb. per million Btu (approximately 85% below 1990 levels), although the reductions could be substantially greater for certain State Implementation Plans. The NOx transport SIP call purported to implement both the new eight-hour ozone standard and the one-hour ozone standard. Federal EPA subsequently stayed its reliance on the eight-hour standard for purposes of the NOx SIP Call. The SIP call was accompanied by a proposed Federal Implementation Plan, which could be implemented in any state that fails to submit an approvable SIP by September 1999. The NOx reductions called for by Federal EPA are targeted at coal-fired electric utilities and may adversely impact the ability of electric utilities to obtain new and modified source permits or to operate affected facilities without making significant capital expenditures. In October 1998, the AEP System operating companies joined with certain other utilities seeking a review of the final NOx SIP Call rule in the U.S. Court of Appeals for the District of Columbia Circuit.
In May 1999, the court issued a stay of the September 1999 SIP submittal date. On March 3, 2000, the court issued a decision upholding the major provisions of the NOx SIP Call rule. The court did not take any action to lift the stay of the SIP submittal date.
Preliminary estimates indicate that compliance with the revised NOx SIP Call rule could result in required capital expenditures as follows:
(IN MILLIONS) AEP System.......................... $1,600 AEGCo............................ 125 APCo............................. 365 CSPCo............................ 136 I&M.............................. 202 KEPCo............................ 106 OPCo............................. 624
Compliance costs cannot be estimated with certainty and the actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through regulated rates and/or reflected in the future market price of electricity if generation is deregulated, they could have a material adverse effect on results of operations, cash flows and possibly financial condition.
Section 126 Petitions: In August 1997, eight northeastern states (Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, and Vermont) filed petitions with Federal EPA under Section 126 of the CAA, claiming that NOx emissions from certain named sources in midwestern states, including all the coal-fired plants of AEP's operating subsidiaries, prevent those states from attaining the ozone NAAQS. Among other things, the petitioners
generally seek NOx emission reductions 85% below 1990 levels from the utility sources in midwestern states, as in the NOx SIP Call. On May 25, 1999, Federal EPA published in the Federal Register a final rule, which granted certain of these petitions. On January 18, 2000, Federal EPA revised and limited the rule to implementation of the one-hour ozone standard. The revised rule imposes reduction requirements comparable to the NOx SIP Call beginning May 1, 2003 for most of AEP's coal fired generating units. Certain AEP System companies and other utilities appealed the revised rule to the U.S. Court of Appeals for the District of Columbia Circuit on January 18, 2000.
In 1999, Delaware, the District of Columbia, Maryland and New Jersey filed additional Section 126 petitions seeking similar relief. No action has yet been taken on those petitions.
Hazardous Air Pollutants: Hazardous air pollutant emissions from utility boilers are potentially subject to control requirements under Title III of the CAAA. The CAAA specifically directed Federal EPA to study potential public health impacts of hazardous air pollutants emitted from electric utility steam generating units. Federal EPA was required to report the results of this study to Congress by November 1993 and to regulate emissions of these hazardous pollutants if necessary. On February 25, 1998, Federal EPA issued a final report to Congress citing as potential health and environmental threats, mercury and three other hazardous air pollutants present in power plant emissions. Noting uncertainty regarding health effects and the absence of control technology for mercury, no immediate regulatory action was proposed regarding emission reductions.
In addition, Federal EPA is required to study the deposition of hazardous pollutants in the Great Lakes, the Chesapeake Bay, Lake Champlain, and other coastal waters. As part of this assessment, Federal EPA is authorized to adopt regulations to prevent serious adverse effects to public health and serious or widespread environmental effects. In 1998, Federal EPA determined that the CAA, including the provisions discussed in the paragraph above, is adequate to address any adverse public health or environmental effects associated with the atmospheric deposition of hazardous air pollutants in the Great Lakes.
Federal EPA was also required to study mercury emissions and report its findings to Congress by 1994. Federal EPA presented that report to Congress in December 1997. The report identifies electric utilities as being the third leading emitter of mercury. Presently, mercury emissions from electric utilities are not regulated under the CAA. However, Federal EPA intends to engage in further studies of mercury emissions, which may lead to additional regulation in the future.
Permitting and Enforcement: The CAAA expanded the enforcement authority of the federal government by:
o Increasing the range of civil and criminal penalties for violations of the CAA and enhancing administrative civil provisions.
o Imposing a national operating permit system, emission fee program and enhanced monitoring, recordkeeping and reporting requirements.
Section 103 of the Comprehensive Environmental Response, Compensation, and Liability Act and Section 304 of the Emergency Planning and Community Right-to-Know Act require notification to state and federal authorities of releases of reportable quantities (RQs) of hazardous and extremely hazardous substances. A number of these substances are emitted by AEP's power plants and other sources. Until recently, emissions of these substances, whether expressly limited in a permit or otherwise subject to federal review or waiver (e.g., mercury), were deemed "federally permitted releases" which did not require emergency notification. On December 21, 1999, Federal EPA published interim guidance in the Federal Register, which provides that any hazardous substance or extremely hazardous substance not expressly and individually limited in a permit that is emitted at levels above an RQ must be reported. Specifically, constituents of regulated pollutants (e.g., metals contained in particulate matter) are not deemed to be federally permitted. Recognizing that this interim guidance would cause sources to reevaluate their air releases, Federal EPA issued a memorandum on
February 15, 2000 announcing its decision to exercise enforcement discretion for facilities that failed to report air releases prior to December 21, 1999. AEP is reevaluating its air releases and will provide supplemental information as appropriate.
Global Climate Change: In December 1997, delegates from 167 nations, including the United States, agreed to a treaty, known as the "Kyoto Protocol," establishing legally-binding emission reductions for gases suspected of causing climate change. If the U.S. becomes a party to the treaty it will be bound to reduce emissions of carbon dioxide (CO(2)), methane and nitrous oxides by 7% below 1990 levels and emissions of hydrofluorcarbons, perfluorocarbons and sulfur hexafluoride 7% below 1995 levels in the years 2008-2012. The Protocol was available for signature from March 16, 1998 to March 15, 1999 and requires ratification by at least 55 nations that account for at least 55% of developed countries' 1990 emissions of CO(2) to enter into force.
Although the United States has agreed to the treaty and signed it on November 12, 1998, President Clinton has indicated that he will not submit the treaty to the Senate for ratification until it contains requirements for "meaningful participation by key developing countries" and the rules, procedures, methodology and guidelines of the treaty's market-based policy instruments, joint implementation programs and compliance enforcement provisions have been negotiated. At the Fourth Conference of the Parties, held in Buenos Aires, Argentina, in November 1998, the parties agreed to a work plan to complete negotiations on outstanding issues with a view toward approving them at the Sixth Conference of the Parties to be held in November 2000.
Since the AEP System is a significant emitter of carbon dioxide, its results of operations, cash flows and financial condition could be adversely affected by the imposition of limitations on CO(2) emissions if compliance costs cannot be fully recovered from customers. In addition, any such severe program to reduce CO(2) emissions could impose substantial costs on industry and society and erode the economic base that AEP's operations serve. However, it is management's belief that the Kyoto Protocol is highly unlikely to be ratified or implemented in the U. S.
West Virginia SO(2) Limits: West Virginia promulgated SO(2) limitations, which Federal EPA approved in February 1978. The emission limitations for the Mitchell Plant have been approved by Federal EPA for primary ambient air quality (health-related) standards only. West Virginia is obligated to reanalyze SO(2) emission limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) standards. Because the CAA provides no specific deadline for approval of emission limits to achieve secondary ambient air quality standards, it is not certain when Federal EPA will take dispositive action regarding the Mitchell Plant.
On August 4, 1994, Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was operating in violation of the applicable federally enforceable SO(2) emission limit. On May 20, 1996, the Notice of Violation and an enforcement action subsequently filed by Federal EPA were resolved through the entry of a consent decree in the U.S. District Court for the Northern District of West Virginia. As of December 31, 1999, Kammer Plant had achieved compliance with an SO(2) emission limit of 2.7 lb. mm/Btu design heat input, pursuant to the provisions of the consent decree and the federally approved West Virginia State Implementation Plan.
Short Term SO(2) Limits: On January 2, 1997, Federal EPA proposed a new intervention level program under the authority of Section 303 of the CAA to address five minute peak SO(2) concentrations believed to pose a health risk to certain segments of the population. The proposal establishes a "concern" level and an "endangerment" level. States must investigate exceedances of the concern level and decide whether to take corrective action. If the endangerment level is exceeded, the state must take action to reduce SO(2) levels. The effects of this proposed intervention program on AEP operations cannot be predicted at this time.
Regional Haze: On July 1, 1999, Federal EPA finalized rules to regulate regional haze attributable to anthropogenic emissions. The primary goal of
the new regional haze program is to address visibility impairment in and around "Class I" protected areas, such as national parks and wilderness areas. Because regional haze precursor emissions are believed by Federal EPA to travel long distances, Federal EPA proposes to regulate such precursor emissions in every state. Under the proposal, each state must develop a regional haze control program that imposes controls necessary to steadily reduce visibility impairment in Class I areas on the worst days and that ensures that visibility remains good on the best days.
The AEP System is a significant emitter of fine particulate matter and its precursors that could be linked to the creation of regional haze. Federal EPA's regional haze rule may have an adverse financial impact on AEP as it may trigger the requirement to install costly new pollution control devices to control emissions of fine particulate matter and its precursors (including SO(2) and NOx). The actual impact of the regional haze regulations cannot be determined at this time. AEP System operating companies and other utilities filed a petition seeking a review of the regional haze rule in the U.S. Court of Appeals for the District of Columbia Circuit on August 30, 1999.
New Source Review: On July 21, 1992, Federal EPA published final regulations in the Federal Register governing application of new source rules to generating plant repairs and pollution control projects undertaken to comply with the CAA. Generally, the rule provides that plants undertaking pollution control projects will not trigger New Source Review requirements. The Natural Resources Defense Council and a group of utilities, including five AEP System companies, have filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. In July 1998, Federal EPA requested comment on proposed revisions to the New Source Review rules which would change New Source Review applicability criteria by eliminating exemptions contained in the current regulation.
New Source Review Litigation: In February 1999, Federal EPA (Regions III and V) issued a request under Section 114 of the CAA seeking documents and information regarding capital and maintenance expenditures at AEP's Cardinal, Gavin, Mitchell, Muskingum River and Sporn plants. Federal EPA conducted a review of the accounting records of AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo in the summer of 1998. Federal EPA subsequently issued Section 114 requests for Amos, Clinch River, Conesville, Kammer, Kanawha River and Tanners Creek plants. On November 3, 1999, the Department of Justice (DOJ), on Federal EPA's behalf, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges AEP made modifications to generating units at certain of its coal-fired generating plants over the course of the past 25 years that extend unit operating lives or restore or increase unit generating capacity without a preconstruction permit in violation of the CAA. The complaint named Cardinal, Mitchell, Muskingum River, Sporn and Tanners Creek plants. Federal EPA also issued Notices of Violation to AEP alleging similar violations at certain other AEP plants.
A number of unaffiliated utilities (one of which operates a unit which AEP owns a portion of) also received Notices of Violation, complaints or administrative orders. One of the unaffiliated utilities, Tampa Electric Company, has settled its litigation with the federal government.
The court has granted the states of Connecticut, New Jersey and New York leave to intervene in Federal EPA's action against AEP under the CAA. On March 17, 2000, the states of Maryland, Massachusetts, New Hampshire, Rhode Island and Vermont petitioned the court for leave to intervene in Federal EPA's action. AEP has not opposed these intervention requests and believes the court will grant them. On November 18, 1999, a number of environmental groups filed a lawsuit against power plants owned by AEP alleging similar violations to those in the Federal EPA complaint and Notices of Violation.
On March 1, 2000, DOJ filed an amended complaint that added allegations for certain of the AEP plants previously named in the complaint as well as counts for Amos, Clinch River, Conesville, Kammer and Kanawha River plants. The plants included in the amended complaint are named by the environmental groups plaintiff and, along with
Gavin, are also named by the intervenor states. In addition to the allegations regarding New Source Review and New Source Performance Standard violations, DOJ included allegations regarding visible particulate emission violations for Cardinal and Muskingum River plants in connection with Notices of Violation issued by Region V, Federal EPA, on November 30, 1999.
The CAA authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts Federal EPA's contentions, could be substantial.
In the event AEP does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed could materially adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, unbundled transition period generation rates, wires charges and future market prices for energy.
Water Pollution Control
The Clean Water Act prohibits the discharge of pollutants to waters of the United States from point sources except pursuant to an NPDES permit issued by Federal EPA or a state under a federally authorized state program.
Under the Clean Water Act, effluent limitations requiring application of the best available technology economically achievable are to be applied, and those limitations require that no pollutants be discharged if Federal EPA finds elimination of such discharges is technologically and economically achievable.
The Clean Water Act provides citizens with a cause of action to enforce compliance with its pollution control requirements. Since 1982, many such actions against NPDES permit holders have been filed. To date, no AEP System plants have been named in such actions.
All System generating plants are operating with NPDES permits. Under Federal EPA's regulations, operation under an expired NPDES permit is authorized provided an application is filed at least 180 days prior to expiration. Renewal applications are being prepared or have been filed for renewal of NPDES permits that expire in 2000.
The NPDES permits generally require that certain thermal impact study programs be undertaken. These studies have been completed for all System plants. Thermal variances are in effect for all plants with once-through cooling water. The thermal variances for Conesville and Muskingum River plants impose thermal management conditions that could result in load curtailment under certain conditions, but the cost impacts are not expected to be significant. Based on favorable results of in-stream biological studies, the thermal temperature limits for both Conesville and Muskingum River plants were raised in the renewed permits issued in 1996. Consequently, the potential for load curtailment and adverse cost impacts is further reduced.
Section 316(b) of the Clean Water Act requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. Under a court established schedule, Federal EPA is required to develop regulations defining adverse impacts and BTA by August 2001. As part of the rulemaking, Federal EPA has issued questionnaires to electric generating power plants, including AEP System plants, requesting information on impingement and entrainment of aquatic organisms from existing plant cooling water intakes. Federal EPA's rulemaking could result in a definition of BTA that would require retrofitting of certain plant intake structures. Such changes would involve costs for AEP System companies, but the significance of these costs cannot be determined at this time.
Certain mining operations conducted by System companies as discussed under Fuel Supply are also subject to federal and state water pollution control requirements, which may entail substantial expenditures for control facilities, not included at present in the System's construction cost estimates set forth herein.
The Federal Water Quality Act of 1987 requires states to adopt stringent water quality standards for a large category of toxic pollutants and to identify specialized control measures for dischargers to waters where it is shown through the use of total maximum daily loads (TMDLs) that water quality standards are not being met. Implementation of these provisions could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits are placed in NPDES permits.
In March 1995, Federal EPA finalized a set of rules that establish minimum water quality standards, anti-degradation policies and implementation procedures for more stringently controlling releases of toxic pollutants into the Great Lakes system. This regulatory package is called the Great Lakes Water Quality Initiative (GLWQI). The most direct compliance cost impact could be related to I&M's Cook Plant. Based on Federal EPA's current policy on intake credits and site specific variables and Michigan's implementation strategy, management does not presently expect the GLWQI will have a significant adverse impact on Cook Plant operations. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could be adversely affected, although the significance depends on the implementation strategy of those states.
Oil Pollution Act: The Oil Pollution Act of 1990 (OPA) defines certain facilities that, due to oil storage volume and location, could reasonably be expected to cause significant and substantial harm to the environment by discharging oil. Such facilities must operate under approved spill response plans and implement spill response training and drill programs. OPA imposes substantial penalties for failure to comply. AEP companies with oil handling and storage facilities meeting the OPA criteria have in place required response plans, training and drill programs.
Solid and Hazardous Waste
Section 311 of the Clean Water Act imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to report such spills. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) expanded the reporting requirements to cover the release of hazardous substances generally into the environment, including water, land and air. AEP's subsidiaries store and use some of these hazardous substances, including PCBs contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted.
CERCLA, RCRA and similar state laws provide governmental agencies with the authority to require clean-up of hazardous waste sites and releases of hazardous substances into the environment and to seek compensation for damages to natural resources. Since liability under CERCLA is strict, joint and several, and can be applied retroactively, AEP System companies which previously disposed of PCB-containing electrical equipment and other hazardous substances may be required to participate in remedial activities at such disposal sites should environmental problems result. OPCo is the only AEP System company which is a defendant in a cost-recovery lawsuit related to clean-up liability at a Federal EPA-identified CERCLA site. OPCo settled its alleged liability at this site under terms of a consent decree and is awaiting formal dismissal from the case.
AEP System companies are identified as Potentially Responsible Parties (PRPs) for four additional federal sites, including CSPCo at two sites and I&M at two sites. Management's present estimates do not anticipate material clean-up costs for identified sites for which AEP subsidiaries have been declared PRPs or are defendants in CERCLA cost recovery litigation. However, if for reasons not currently identified significant costs are incurred for clean-up, future results of operations and possibly financial condition could be adversely affected unless the costs can be recovered through rates.
Regulations issued by Federal EPA under the Toxic Substances Control Act govern the use, distribution and disposal of PCBs, including PCBs in electrical equipment. Deadlines for removing certain PCB-containing electrical equipment from service have been met.
In addition to handling hazardous substances, the System companies generate solid waste associated with the combustion of coal, the vast majority of which is fly ash, bottom ash and flue gas desulfurization wastes. These wastes presently are considered to be non-hazardous under RCRA and applicable state law and the wastes are treated and disposed of in surface impoundments or landfills in accordance with state permits or authorization or are beneficially utilized. As required by RCRA, Federal EPA evaluated whether high volume coal combustion wastes (such as fly ash, bottom ash and flue gas desulfurization wastes) should be regulated as hazardous waste. In August 1993, Federal EPA issued a regulatory determination that such high volume coal combustion wastes should not be regulated as hazardous waste. For low volume coal combustion wastes, such as metal and boiler cleaning wastes, which are traditionally co-managed with high volume wastes, Federal EPA will gather additional information and make a regulatory determination by April 2000. Until that time, these low volume wastes are provisionally excluded from regulation under the hazardous waste provisions of RCRA when mixed with and co-managed with high volume coal combustion wastes. If Federal EPA determines that certain low volume coal combustion wastes should be subject to RCRA Subtitle C hazardous waste regulations, AEP System companies may incur additional waste management expenses. The significance of these costs cannot be determined at this time.
All presently generated hazardous waste is being disposed of at permitted off-site facilities in compliance with applicable federal and state laws and regulations. For System facilities that generate such wastes, System companies have filed the requisite notices and are complying with RCRA and applicable state regulations for generators. Nuclear waste produced at the Cook Plant regulated under the Atomic Energy Act is excluded from regulation under RCRA.
Underground Storage Tanks: Federal EPA's technical requirements for underground storage tanks containing petroleum required retrofitting or replacement of an appreciable number of tanks. Compliance costs for tank replacement were not significant. Some limited site remediation associated with tank removal is ongoing, but these costs are not expected to be significant.
Electric and Magnetic Fields (EMF)
EMF is found everywhere there is electricity. Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, household wiring, and appliances.
A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, the majority of studies have indicated no such association.
The Energy Policy Act of 1992 established a coordinated Federal EMF research program which ended in 1998. The program funding was $65,000,000, half of which was provided by private parties including utilities. AEP contributed over $400,000 to this program. In 1999, the National Institute of Environmental Health Sciences (NIEHS), as required by the Act, provided a report to Congress summarizing the results of this program. The report concluded that "the probability that ...EMF is truly a health hazard is currently small" and that the evidence that exists for health effects is "insufficient to warrant aggressive regulatory actions." Nevertheless, the NIEHS identified several areas where further research might be warranted. AEP has supported EMF research through the years and continues to fund the Electric Power Research Institute's EMF research program, contributing over $400,000 to this program in 1999 and intending to contribute a similar amount in 2000. See Research and Development.
AEP's participation in these programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue. Residential customers of AEP are provided information and field measurements on request, although there is no scientific basis for interpreting such measurements.
A number of lawsuits based on EMF-related grounds have been filed against electric utilities. A suit was filed on May 23, 1990 against I&M involving claims that EMF from a 345 KV transmission line caused adverse health effects. On March 23, 1998 the court ruled that the plaintiffs failed to prove that I&M caused any of the injuries claimed by the plaintiffs. This part of the trial court's decision was upheld on appeal. Certain issues unrelated to health effects are pending at the trial court. No specific amount has been requested for damages in this case and no trial date has been set.
Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. No state which the AEP System serves has done so. In March 1993, The Ohio Power Siting Board issued its amended rules providing for additional consideration of the possible effects of EMF in the certification of electric transmission facilities. Applicants are required to address possible health effects and discuss the consideration of design alternatives with respect to estimates of EMF levels. These rules were reissued in 1998 with no change to EMF language.
Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from ratepayers.
RESEARCH AND DEVELOPMENT
AEP and its subsidiaries are involved in over 100 research projects which are directed toward:
o Developing more efficient methods of burning coal.
o Reducing the emissions resulting from the combustion of coal.
o Utilizing combustion by-products of coal.
o Exploring new methods of generating electricity.
o Exploring the application of new electrotechnologies.
o Improving the efficiency and reliability of power transmission, distribution and utilization.
AEP System operating companies are members of the Electric Power Research Institute (EPRI), an organization founded in 1973 that manages research and development initiatives, primarily on behalf of the U.S. electric utility industry. These initiatives include technical programs to improve power production, delivery and use. EPRI's more than 700 members represent over 90% of the kilowatt sales in the U.S., but also include competitive power producers, international organizations and others. Total AEP dues to EPRI were $14,000,000 for 1999, $15,400,000 for 1998 and $15,300,000 for 1997.
Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $17,000,000 for the year ended December 31, 1999, $24,100,000 for the year ended December 31, 1998 and $23,600,000 for the year ended December 31, 1997. This includes expenditures of $700,000 for 1999, $3,300,000 for 1998 and $4,600,000 for 1997 related to pressurized fluidized-bed combustion, a process in which sulfur is removed during coal combustion and nitrogen oxide formation is minimized.
Item 2. PROPERTIES - --------------------------------------------------------------------------------
At December 31, 1999, subsidiaries of AEP owned (or leased where indicated) generating plants with the net power capabilities (winter rating) shown in the following table:
- -------------------- (a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended. (b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo. (c) Represents CSPCo's ownership interest in generating units owned in common with CG&E and DP&L. (d) Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana under a 35-year lease with a provision for an additional 15-year extension at the election of I&M. (e) The scrubber facilities at the Gavin Plant are leased. The lease terminates in 2010 unless extended.
See Item 1 under Fuel Supply, for information concerning coal reserves owned or controlled by subsidiaries of AEP.
The following table sets forth the total overhead circuit miles of transmission and distribution lines of the AEP System, APCo,
CSPCo, I&M, KEPCo and OPCo and that portion of the total representing 765,000-volt lines:
- ---------------------- (a) Includes 766 miles of 345,000-volt jointly owned lines. (b) Includes lines of other AEP System companies not shown.
TITLES
The AEP System's electric generating stations are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of the System in the realty on which its facilities are located are considered by it to be adequate for its use in the conduct of its business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby. System companies generally have the right of eminent domain whereby they may, if necessary, acquire, perfect or secure titles to or easements on privately-held lands used or to be used in their utility operations.
Substantially all the physical properties of APCo, CSPCo, I&M, KEPCo and OPCo are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of each such company.
SYSTEM TRANSMISSION LINES AND FACILITY SITING
Legislation in the states of Indiana, Kentucky, Michigan, Ohio, Virginia, and West Virginia requires prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. Delays and additional costs in constructing facilities have been experienced as a result of proceedings conducted pursuant to such statutes, as well as in proceedings in which operating companies have sought to acquire rights-of-way through condemnation, and such proceedings may result in additional delays and costs in future years.
PEAK DEMAND
The AEP System is interconnected through 121 high-voltage transmission interconnections with 25 neighboring electric utility systems. The all-time and 1999 one-hour peak System demands were 25,940,000 and 23,392,000 kilowatts, respectively (which included 7,314,000 and 3,408,000 kilowatts, respectively, of scheduled deliveries to unaffiliated systems which the System might, on appropriate notice, have elected not to schedule for delivery) and occurred on June 17, 1994 and June 10, 1999, respectively. The net dependable capacity to serve the System load on such date, including power available under contractual obligations, was 23,457,000 and 23,919,000 kilowatts, respectively. The all-time and 1999 one-hour internal peak demands were 19,557,000 and 19,952,000 kilowatts, respectively, and occurred on February 5, 1996 and July 30, 1999, respectively. The net dependable capacity to serve the System load on such date, including power dedicated under contractual arrangements, was 23,765,000 and 23,829,000 kilowatts, respectively. The all-time one-hour integrated and internal net system peak demands and 1999 peak demands for AEP's generating subsidiaries are shown in the following tabulation:
HYDROELECTRIC PLANTS
AEP has 17 facilities, of which 16 are licensed through FERC. The license for the hydroelectric plant at Elkhart, Indiana expires in 2000. In 1995, a notice of intent to relicense the Elkhart project was filed. The application was filed in 1998. The license for the Mottville hydroelectric plant in Michigan expires in 2003. A notice of intent to relicense was filed in 1998.
COOK NUCLEAR PLANT
Unit 1 of the Cook Plant, which was placed in commercial operation in 1975, has a nominal net electric rating of 1,020,000 kilowatts. Unit 1's availability factor was -0-% during 1999 and -0-% during 1998. Unit 2, of slightly different design, has a nominal net electrical rating of 1,090,000 kilowatts and was placed in commercial operation in 1978. Unit 2's availability factor was -0-% during 1999 and -0-% during 1998. The Cook Plant was shut down in September 1997 to respond to issues raised regarding the operability of certain safety systems. See Cook Plant Shutdown.
Units 1 and 2 are licensed by the NRC to operate at 100% of rated thermal power to October 25, 2014 and December 23, 2017, respectively. However, for economic or other reasons, operation of the Cook Plant for the full term of its operating licenses cannot be assured.
Costs associated with the operation, maintenance and retirement of nuclear plants continue to be of greater significance and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. I&M may also incur costs and experience reduced output at its Cook Plant because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. Nuclear industry-wide and Cook Plant initiatives have contributed to slowing the growth of operating and maintenance costs. However, the ability of I&M to obtain adequate and timely recovery of costs associated with the Cook Plant, including replacement power, any unamortized investment at the end of the Cook Plant's useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. See Competition and Business Change.
Cook Plant Shutdown
On September 9 and 10, 1997, during a NRC architect engineer design inspection, questions regarding the operability of certain safety systems caused AEP operations personnel to shut down Units 1 and 2 of the Cook Plant. On September 19, 1997, the NRC issued a Confirmatory Action Letter requiring AEP to address the issues identified in the letter.
In April 1998 the NRC notified I&M that it had convened a Restart Panel for Cook Plant. In July 1998 the NRC provided a list of the required restart activities and in October the NRC expanded the list. In order to identify and resolve the issues necessary to restart the Cook units, AEP has been meeting with the Panel on a regular basis until the units are returned to service.
The NRC notified I&M, in a February 2, 2000, letter, that the Confirmatory Action Letter has been closed. Closing of the Confirmatory Action Letter is one of the key approvals needed for restart of the Cook Plant.
In July 1998 AEP received an "adverse trend letter" from the NRC indicating that NRC senior managers determined that there had been a slow decline in performance at the Cook Plant during the 18-month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities.
In October 1998 the NRC issued AEP a Notice of Violation and proposed a $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 1997 and April 1998. AEP paid the penalty.
Unit 2 of the Cook Plant is scheduled to restart in April 2000. Unit 1 is currently undergoing steam generator replacement, but restart work has begun
and will accelerate following Unit 2 start-up. Unit 1 restart is scheduled for September 2000. Any issues or difficulties encountered in the testing of equipment as part of the restart process could delay the scheduled restart dates. When maintenance and other activities required for restart are complete, AEP will seek concurrence from the NRC to return the Cook Plant to service.
Costs associated with the steam generator replacement for Unit 1 are estimated to be approximately $165,000,000, which will be accounted for as a capital investment unrelated to the restart. At December 31, 1999, $119,000,000 has been spent on the steam generator replacement.
The cost of electricity supplied to retail customers has increased due to the outage of the Cook Plant because higher cost coal-fired generation and coal-based purchased power has been substituted for the unavailable lower cost nuclear generation. With regulator approvals, actual replacement energy fuel costs that exceeded the costs reflected in billings were recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms.
Indiana Settlement: On March 30, 1999, the IURC approved a settlement agreement resolving all matters related to the recovery of replacement energy costs due to the extended Cook Plant outage. The settlement agreement provided for, among other things:
o Acredit of $55,000,000, including interest, to Indiana retail customers that was refunded through customer bills during the months of July, August and September 1999. The credit returned to customers Cook replacement fuel costs previously recovered.
o Authorization to defer any unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including the $55,000,000 credited to customers.
o Authorization to defer up to $150,000,000 in incremental operation and maintenance restart costs for the Cook Plant above the base rate level incurred during 1999.
o Amortization of the fuel recoveries and restart cost deferrals over a five-year period ending December 31, 2003.
o Subject to certain force majeure provisions, a freeze in base rates through December 31, 2003 and a cap on fuel recovery charges through March 1, 2004.
o Incremental nuclear decommissioning trust fund deposits of $2,500,000 annually over a five-year period ending December 31, 2003.
Michigan Settlement: On December 16, 1999, the MPSC approved a settlement agreement for two open Michigan power supply cost recovery reconciliation cases that resolves all issues related to the Cook Plant extended outage. The settlement agreement provides for the following:
o Limits I&M's ability to increase base rates and freezes the power supply cost recovery factor for five years.
o Permits the deferral of up to $50,000,000 in 1999 of jurisdictional non-fuel restart nuclear operation and maintenance expenses.
o Authorizes the amortization of power supply cost recovery revenues accrued from September 9, 1997 to December 31, 1999 and non-fuel nuclear operation and maintenance cost deferrals over a five-year period ending December 31, 2003.
Expenses to restart the Cook units are estimated to total approximately $574,000,000. Through December 31, 1999, $373,000,000 has been spent. The costs of the Cook outage and restart efforts will have a material adverse effect on future results of operations and possibly financial condition through 2003 and on cash flows through 2000. If the Cook units are not returned to service as scheduled, their continued outage would make the adverse effect greater on future results of operations, cash flows and financial condition.
Nuclear Incident Liability
The Price-Anderson Act limits public liability for a nuclear incident at any licensed reactor in the
United States to $9.9 billion. I&M has insurance coverage for liability from a nuclear incident at its Cook Plant. Such coverage is provided through a combination of private liability insurance, with the maximum amount available of $200,000,000, and mandatory participation for the remainder of the $9.9 billion liability, in an industry retrospective deferred premium plan which would, in case of a nuclear incident, assess all licensees of nuclear plants in the U.S. Under the deferred premium plan, I&M could be assessed up to $176,000,000 payable in annual installments of $20,000,000 in the event of a nuclear incident at Cook or any other nuclear plant in the U.S. There is no limit on the number of incidents for which I&M could be assessed these sums.
I&M also has property damage, decontamination and decommissioning insurance for loss resulting from damage to the Cook Plant facilities in the amount of $2.75 billion. Coverage is provided by Energy Insurance Bermuda (EIB) and Nuclear Electric Insurance Limited (NEIL). If EIB's and NEIL's losses exceed their available resources, I&M would be subject to a total retrospective premium assessment of up to $16,704,380. NRC regulations require that, in the event of an accident, whenever the estimated costs of reactor stabilization and site decontamination exceed $100,000,000, the insurance proceeds must be used, first, to return the reactor to, and maintain it in, a safe and stable condition and, second, to decontaminate the reactor and reactor station site in accordance with a plan approved by the NRC. The insurers then would indemnify I&M for decommissioning costs in excess of funds already collected for decommissioning and for property damage up to $3.0 billion less any amounts used for stabilization and decontamination. See Fuel Supply -- Nuclear Waste.
The NEIL extra-expense programs provide insurance to cover extra costs resulting from a prolonged accidental outage of a nuclear unit. I&M's policy insures against such increased costs up to approximately $3,500,000 per week (starting 12 weeks after the outage) for 52 weeks and $2,800,000 per week for the next 110 weeks, or 80% of those amounts per unit if both units are down for the same reason. If NEIL's losses exceed its available resources, I&M would be subject to a total retrospective premium assessment of up to $5,485,760.
POTENTIAL UNINSURED LOSSES
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP, I&M and other AEP System companies.
Item 3.
Item 3. LEGAL PROCEEDINGS - --------------------------------------------------------------------------------
On February 28, 1994, Ormet Corporation filed a complaint in the U.S. District Court, Northern District of West Virginia, against AEP, OPCo, the Service Corporation and two of its employees, Federal EPA and the Administrator of Federal EPA. Ormet is the operator of a major aluminum reduction plant in Ohio and was a customer of OPCo until December 31, 1999. See Certain Industrial Customers. Pursuant to the Clean Air Act Amendments of 1990, OPCo received SO2 Allowances for its Kammer Plant. See Environmental and Other Matters. Ormet's complaint sought a declaration that it is the owner of approximately 89% of the Phase I and Phase II SO2 allowances issued for use by the Kammer Plant. In March 1995, the District Court dismissed the complaint for lack of jurisdiction and, in October 1996, the U.S. Court of Appeals for the Fourth Circuit reversed this decision. In March 1999, the District Court granted the motion of OPCo and the Service Corporation for summary judgment and dismissed the case. Ormet filed an appeal in the U.S. Court of Appeals for the Fourth Circuit in March 1999. On November 30, 1999, the court held oral argument.
-------------------------
The Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions claimed by AEP relating to its corporate owned life insurance (COLI) program should not be allowed. As a result of a suit filed in U.S. District Court (discussed below) this request for ruling was withdrawn by the IRS agents. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through December 31, 1999 would reduce earnings (including interest) as follows:
(in millions) AEP System........................ $317 APCo........................... 79 CSPCo.......................... 43 I&M............................ 66 KEPCo.......................... 8 OPCo........................... 118
AEP made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of any additional above- market rate interest on the contested amount. The payments to the IRS are included on the consolidated balance sheet in other assets pending the resolution of this matter. AEP is seeking refund through litigation of all amounts paid plus interest.
In order to resolve this issue, AEP filed suit against the U.S. in the U.S. District Court for the Southern District of Ohio in March 1998. In 1999 a U.S. Tax Court judge decided in a case involving an unaffiliated company that a corporate taxpayer's COLI interest deduction should be disallowed. Notwithstanding the decision in this case, management has made no provision for any possible adverse earnings impact from this matter because it believes, and has been advised by outside counsel, that it has a meritorious position. In the event the resolution of this matter is unfavorable, it could have a material adverse impact on results of operations, cash flows and financial condition.
----------------------
See Item 1 for a discussion of certain environmental and rate matters.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - --------------------------------------------------------------------------------
AEP, APCO, I&M AND OPCO. None.
AEGCO, CSPCO AND KEPCO. Omitted pursuant to Instruction I(2)(c).
---------------------
EXECUTIVE OFFICERS OF THE REGISTRANTS
AEP. The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 1, 2000.
- ----------------------- (a) All of the executive officers listed above have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) during the past five years, except for Mr. Addis and Ms. Tomasky. Prior to joining the Service Corporation in February 1997 in his present position, Mr. Addis was Executive Vice President (1992-1993) and President (1993-January 1997) of Louis Dreyfus Electric Power, Inc. and President of Duke/Louis Dreyfus LLC (1995-January 1997). Mr. Addis became an executive officer of AEP effective January 1, 2000. Prior to joining the Service Corporation in July 1998 as Senior Vice President, Ms. Tomasky was a partner with the law firm of Hogan & Hartson (August 1997-July 1998) and General Counsel of the Federal Energy Regulatory Commission (May 1993-August 1997). Ms. Tomasky became an executive officer of AEP effective with her promotion to Executive Vice President on January 26, 2000. All of the above officers are appointed annually for a one-year term by the board of directors of AEP, the board of directors of the Service Corporation, or both, as the case may be.
APCO. The names of the executive officers of APCo, the positions they hold with APCo, their ages as of March 1, 2000, and a brief account of their business experience during the past five years appears below. The directors and executive officers of APCo are elected annually to serve a one-year term.
- ---------------------- (a) Positions are with APCo unless otherwise indicated.
OPCO. The names of the executive officers of OPCo, the positions they hold with OPCo, their ages as of March 1, 2000, and a brief account of their business experience during the past five years appear below. The directors and executive officers of OPCo are elected annually to serve a one-year term.
- --------------------- (a) Positions are with OPCo unless otherwise indicated.
PART II=========================================================================
Item 5.
Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS - --------------------------------------------------------------------------------
AEP. AEP Common Stock is traded principally on the New York Stock Exchange. The following table sets forth for the calendar periods indicated the high and low sales prices for the Common Stock as reported on the New York Stock Exchange Composite Tape and the amount of cash dividends paid per share of Common Stock.
At December 31, 1999, AEP had approximately 125,000 shareholders of record.
AEGCO, APCO, CSPCO, I&M, KEPCO AND OPCO. The information required by this item is not applicable as the common stock of all these companies is held solely by AEP.
Item 6.
Item 6. SELECTED FINANCIAL DATA - --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(a).
AEP. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the AEP 1999 Annual Report (for the fiscal year ended December 31, 1999).
APCO. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the APCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
CSPCO. Omitted pursuant to Instruction I(2)(a).
I&M. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the I&M 1999 Annual Report (for the fiscal year ended December 31, 1999).
KEPCO. Omitted pursuant to Instruction I(2)(a).
OPCO. The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the OPCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION - --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the AEGCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
AEP. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the AEP 1999 Annual Report (for the fiscal year ended December 31, 1999).
APCO. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the APCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
CSPCO. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the CSPCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
I&M. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the I&M 1999 Annual Report (for the fiscal year ended December 31, 1999).
KEPCO. Omitted pursuant to Instruction I(2)(a). Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the KEPCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
OPCO. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the OPCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - --------------------------------------------------------------------------------
AEGCO. The information required by this item is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the AEGCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
AEP. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the AEP 1999 Annual Report (for the fiscal year ended December 31, 1999).
APCO. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the APCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
CSPCO. The information required by this item is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the CSPCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
I&M. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the I&M 1999 Annual Report (for the fiscal year ended December 31, 1999).
KEPCO. The information required by this item is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the KEPCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
OPCO. The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Financial Condition in the OPCo 1999 Annual Report (for the fiscal year ended December 31, 1999).
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, KEPCO, AND OPCO. The information required by this item is incorporated herein by reference to the financial statements and supplementary data described under Item 14 herein.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE - --------------------------------------------------------------------------------
AEGCO, AEP, APCO, CSPCO, I&M, KEPCO AND OPCO. None.
PART III =======================================================================
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS - --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by reference to the material under Nominees for Director of the definitive proxy statement of AEP for the 2000 annual meeting of shareholders, to be filed within 120 days after December 31, 1999. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.
APCO. The information required by this item is incorporated herein by reference to the material under Election of Directors of the definitive information statement of APCo for the 2000 annual meeting of stockholders, to be filed within 120 days after December 31, 1999. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.
CSPCO. Omitted pursuant to Instruction I(2)(c).
I&M. The names of the directors and executive officers of I&M, the positions they hold with I&M, their ages as of March 1, 2000, and a brief account of their business experience during the past five years appear below. The directors and executive officers of I&M are elected annually to serve a one-year term.
- ----------------- (a) Positions are with I&M unless otherwise indicated. (b) Dr. Draper is a director of BCP Management, Inc., which is the general partner of Borden Chemicals and Plastics L.P., and CellNet Data Systems, Inc. and Mr. Lhota is a director of Huntington Bancshares Incorporated and State Auto Financial Corporation. (c) Dr. Draper and Messrs. Fayne, Lhota and Pena are directors of AEGCo, APCo, CSPCo, KEPCo and OPCo. Dr. Draper is also a director of AEP. Mr. Vipperman is a director of APCo, CSPCo, KEPCo and OPCo.
KEPCO. Omitted pursuant to Instruction I(2)(c).
OPCO. The information required by this item is incorporated herein by reference to the material under the heading Election of Directors of the definitive information statement of OPCo for the 2000 annual meeting of shareholders, to be filed within 120 days after December 31, 1999. Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.
Item 11.
Item 11. EXECUTIVE COMPENSATION - --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by reference to the material under Directors Compensation and Stock Ownership Guidelines, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 2000 annual meeting of shareholders to be filed within 120 days after December 31, 1999.
APCO. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of APCo for the 2000 annual meeting of stockholders, to be filed within 120 days after December 31, 1999.
CSPCO. Omitted pursuant to Instruction I(2)(c).
KEPCO. Omitted pursuant to Instruction I(2)(c).
OPCO. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of OPCo for the 2000 annual meeting of shareholders, to be filed within 120 days after December 31, 1999.
I&M. Certain executive officers of I&M are employees of the Service Corporation. The salaries of these executive officers are paid by the Service Corporation and a portion of their salaries has been allocated and charged to I&M. The following table shows for 1999, 1998 and 1997 the compensation earned from all AEP System companies by the chief executive officer and four other most highly compensated executive officers (as defined by regulations of the SEC) of I&M at December 31, 1999.
Summary Compensation Table
- ------------------------ (1) Amounts in the Bonus column reflect awards under the Senior Officer Annual Incentive Compensation Plan. Payments are made in March of the succeeding fiscal year for performance in the year indicated. Amounts for 1999 are estimates but should not change significantly.
Amounts in the Long Term Compensation column reflect performance share unit targets earned under the Performance Share Incentive Plan for three-year performance periods.
See below under Long Term Incentive Plans - Awards in 1999.
(2) Amounts in the All Other Compensation column include (i) AEP's matching contributions under the AEP Employees Savings Plan and the AEP Supplemental Savings Plan, a non-qualified plan designed to supplement the AEP Savings Plan, and (ii) subsidiary companies director fees. For 1998 and 1999, the amounts also include split-dollar insurance. Split-dollar insurance represents the present value of the interest projected to accrue for the employee's benefit on the current year's insurance premium paid by AEP. Cumulative net life insurance premiums paid are recovered by AEP at the later of retirement or 15 years. Detail of the 1999 amounts in the All Other Compensation column is shown below.
(3) Dr. Markowsky resigned effective February 1, 2000.
(4) No 1997 compensation information is reported for Messrs. Vipperman and Fayne because they were not executive officers in these years.
Long-Term Incentive Plans -- Awards In 1999
Each of the awards set forth below establishes performance share unit targets, which represent units equivalent to shares of Common Stock, pursuant to the Company's Performance Share Incentive Plan. Since it is not possible to predict future dividends and the price of AEP Common Stock, credits of performance share units in amounts equal to the dividends that would have been paid if the performance share unit targets were established in the form of shares of Common Stock are not included in the table.
The ability to earn performance share unit targets is tied to achieving specified levels of total shareholder return (TSR) relative to the S&P Electric Utility Index. Notwithstanding AEP's TSR ranking, no performance share unit targets are earned unless AEP shareholders realize a positive TSR over the relevant three performance period. The Human Resources Committee may, at its discretion, reduce the number of performance share unit targets otherwise earned. In accordance with the performance goals established for the periods set forth below, the threshold, target and maximum awards are equal to 25%, 100% and 200%, respectively, of the performance share unit targets. No payment will be made for performance below the threshold.
Payments of earned awards are deferred in the form of restricted stock units (equivalent to shares of AEP Common Stock) until officers have met the equivalent stock ownership target. Once officers meet and maintain their respective targets, they may elect either to continue to defer or to receive further earned awards in cash and/or Common Stock.
Retirement Benefits
The American Electric Power System Retirement Plan provides pensions for all employees of AEP System companies (except for employees covered by certain collective bargaining agreements), including the executive officers of the Company. The Retirement Plan is a noncontributory defined benefit plan.
The following table shows the approximate annual annuities under the Retirement Plan that would be payable to employees in certain higher salary classifications, assuming retirement at age 65 after various periods of service.
Pension Plan Table
The amounts shown in the table are the straight life annuities payable under the Retirement Plan without reduction for the joint and survivor annuity. Retirement benefits listed in the table are not subject to any deduction for Social Security or other offset amounts. The retirement annuity is reduced 3% per
year in the case of retirement between ages 55 and 62. If an employee retires after age 62, there is no reduction in the retirement annuity.
The Company maintains a supplemental retirement plan which provides for the payment of benefits that are not payable under the Retirement Plan due primarily to limitations imposed by Federal tax law on benefits paid by qualified plans. The table includes supplemental retirement benefits.
Compensation upon which retirement benefits are based, for the executive officers named in the Summary Compensation Table above, consists of the average of the 36 consecutive months of the officer's highest aggregate salary and Senior Officer Annual Incentive Compensation Plan awards, shown in the "Salary" and "Bonus" columns, respectively, of the Summary Compensation Table, out of the officer's most recent 10 years of service. As of December 31, 1999, the number of full years of service applicable for retirement benefit calculation purposes for such officers were as follows: Dr. Draper, seven years; Mr. Lhota, 34 years; Dr. Markowsky, 28 years; Mr. Vipperman, 37 years; and Mr. Fayne, 24 years.
Dr. Draper has a contract with the Company and AEP Service Corporation which provides him with a supplemental retirement annuity that credits him with 24 years of service in addition to his years of service credited under the Retirement Plan less his actual pension entitlement under the Retirement Plan and any pension entitlement from the Gulf States Utilities Company Trusteed Retirement Plan, a plan sponsored by his prior employer.
Eight AEP System employees (including Messrs. Fayne, Lhota and Vipperman and Dr. Markowsky) whose pensions may be adversely affected by amendments to the Retirement Plan made as a result of the Tax Reform Act of 1986 are eligible for certain supplemental retirement benefits. Such payments, if any, will be equal to any reduction occurring because of such amendments. Assuming retirement in 2000 of the executive officers named in the Summary Compensation Table (including Dr. Markowsky who resigned effective February 1, 2000), none of them would receive any supplemental benefits.
AEP made available a voluntary deferred-compensation program in 1982 and 1986, which permitted certain members of AEP System management to defer receipt of a portion of their salaries. Under this program, a participant was able to defer up to 10% or 15% annually (depending on the terms of the program offered), over a four-year period, of his or her salary, and receive supplemental retirement or survivor benefit payments over a 15-year period. The amount of supplemental retirement payments received is dependent upon the amount deferred, age at the time the deferral election was made, and number of years until the participant retires. The following table sets forth, for the executive officers named in the Summary Compensation Table, the amounts of annual deferrals and, assuming retirement at age 65, annual supplemental retirement payments under the 1982 and 1986 programs.
Severance Plan and Change-In-Control Agreements
SEVERANCE PLAN. In connection with the proposed merger with Central and South West Corporation, AEP's Board of Directors adopted a severance plan on February 24, 1999, effective March 1, 1999, that includes Dr. Markowsky and Messrs. Lhota, Vipperman and Fayne. The severance plan provides for payments and other benefits if, at any time before the second anniversary of the merger consummation date (or, if
the merger has not occurred, before the expiration of the severance plan which will occur upon the termination of the merger agreement), the officer's employment is terminated (i) by AEP without "cause" or (ii) by the officer because of a detrimental change in responsibilities or a reduction in salary or benefits. Under the severance plan, the officer will receive:
o A lump sum payment equal to three times the officer's annual base salary plus target annual incentive under the Senior Officer Annual Incentive Compensation Plan.
o Maintenance for a period of three additional years of all medical and dental insurance benefits substantially similar to those benefits to which the officer was entitled immediately prior to termination, reduced to the extent comparable benefits are otherwise received.
o Outplacement services not to exceed a cost of $30,000 or use of an office and secretarial services for up to one year.
AEP's obligation for the payments and benefits under the severance plan is subject to the waiver by the officer of any other severance benefits that may be provided by AEP. In addition, the officer agrees to refrain from the disclosure of confidential information relating to AEP.
Dr. Markowsky resigned effective February 1, 2000 and has received a lump sum payment in accordance with the terms of the severance plan.
CHANGE-IN-CONTROL AGREEMENTS. AEP has change-in-control agreements with Dr. Draper and Messrs. Lhota, Vipperman and Fayne. If there is a "change-in-control" of AEP and the employee's employment is terminated by AEP or by the employee for reasons substantially similar to those in the severance plan, these agreements provide for substantially the same payments and benefits as the severance plan with the following additions:
o Three years of service credited for purposes of determining non-qualified retirement benefits.
o Transfer to the employee of title to AEP's automobile then assigned to the employee.
o Payment, if required, to make the employee whole for any excise tax imposed by Section 4999 of the Internal Revenue Code.
"Change-in-control" means:
o The acquisition by any person of the beneficial ownership of securities representing 25% or more of AEP's voting stock.
o A change in the composition of a majority of the Board of Directors under certain circumstances within any two-year period.
o Approval by the shareholders of the liquidation of AEP, disposition of all or substantially all of the assets of AEP or, under certain circumstances, a merger of AEP with another corporation.
-----------------------------
Directors of I&M receive a fee of $100 for each meeting of the Board of Directors attended in addition to their salaries.
-----------------------------
The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity, transportation and handling of fuel, sales or rentals of property and interest or dividend payments on the securities held by the companies' respective parents.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - --------------------------------------------------------------------------------
AEGCO. Omitted pursuant to Instruction I(2)(c).
AEP. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers of the definitive proxy statement of AEP
for the 2000 annual meeting of shareholders to be filed within 120 days after December 31, 1999.
APCO. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 2000 annual meeting of stockholders, to be filed within 120 days after December 31, 1999.
CSPCO. Omitted pursuant to Instruction I(2)(c).
I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of I&M are directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock of I&M generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such shares.
The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of January 1, 2000, by each director and nominee of I&M and each of the executive officers of I&M named in the summary compensation table, and by all directors and executive officers of I&M as a group. It is based on information provided to I&M by such persons. No such person owns any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole voting power and investment power over the number of shares of AEP Common Stock and stock-based units set forth opposite his name. Fractions of shares and units have been rounded to the nearest whole number.
- ------------------------- (a) Includes share equivalents held in the AEP Employees Savings Plan in the amounts listed below:
With respect to the share equivalents held in the AEP Employees Savings Plan, such persons have sole voting power, but the investment/ disposition power is subject to the terms of the Plan. (b) This column includes amounts deferred in stock units and held under AEP's officer benefit plans. (c) Includes the following numbers of shares held in joint tenancy with a family member: Dr. Draper, 5,221; Mr. Drozda, 16; Mr. Lhota, 2,180; Mr. Vipperman, 71; and Mr. Wittkamper, 1,536. (d) Includes 6 and 21 shares held by family members of Mr. Drozda and Dr. Markowsky, respectively, over which beneficial ownership is disclaimed. (e) Does not include, for Messrs. Lhota and Vipperman, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs. Lhota and Vipperman share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares. (f) Represents less than 1% of the total number of shares outstanding
KEPCO. Omitted pursuant to Instruction I(2)(c).
OPCO. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of OPCo for the 2000 annual meeting of shareholders, to be filed within 120 days after December 31, 1999
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - --------------------------------------------------------------------------------
AEP, APCO, I&M AND OPCO. None.
AEGCO, CSPCO, AND KEPCO. Omitted pursuant to Instruction I(2)(c).
PART IV ========================================================================
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K - --------------------------------------------------------------------------------
(a) The following documents are filed as a part of this report:
1. FINANCIAL STATEMENTS:
The following financial statements have been incorporated herein by reference pursuant to Item 8.
(b) REPORTS ON FORM 8-K:
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
AEP GENERATING COMPANY
BY: /S/ A. A. PENA --------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
AMERICAN ELECTRIC POWER COMPANY, INC.
BY: /S/ H. W. FAYNE ---------------------------------- (H. W. FAYNE, VICE PRESIDENT AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
APPALACHIAN POWER COMPANY COLUMBUS SOUTHERN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY
BY: /S/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.
INDIANA MICHIGAN POWER COMPANY
BY: /S/ A. A. PENA -------------------------------------- (A. A. PENA, VICE PRESIDENT, TREASURER AND CHIEF FINANCIAL OFFICER)
Date: March 20, 2000
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.
INDEX TO FINANCIAL STATEMENT SCHEDULES
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INDEPENDENT AUDITORS' REPORT ........................................... S-2
The following financial statement schedules for the years ended December 31, 1999, 1998 and 1997 are included in this report on the pages indicated.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-3
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-3
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves ... S-3
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-4
KENTUCKY POWER COMPANY Schedule II-- Valuation and Qualifying Accounts and Reserves ... S-4
OHIO POWER COMPANY AND SUBSIDIARIES Schedule II-- Valuation and Qualifying Accounts and Reserves.... S-4
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INDEPENDENT AUDITORS' REPORT
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES:
We have audited the consolidated financial statements of American Electric Power Company, Inc. and its subsidiaries and the financial statements of certain of its subsidiaries, listed in Item 14 herein, as of December 31, 1999 and 1998, and for each of the three years in the period ended December 31, 1999, and have issued our reports thereon dated February 22, 2000 (March 3, 2000 as to Note 7 for American Electric Power Company, Inc. and its subsidiaries; Note 6 for Appalachian Power Company and its subsidiaries, Columbus Southern Power Company and its subsidiaries, Indiana Michigan Power Company and its subsidiaries, Kentucky Power Company and Ohio Power Company and its subsidiaries; and Note 3 for AEP Generating Company); such financial statements and reports are included in the respective 1999 Annual Report and are incorporated herein by reference. Our audits also included the financial statement schedules of American Electric Power Company, Inc. and its subsidiaries and of certain of its subsidiaries, listed in Item 14. These financial statement schedules are the responsibility of the respective Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the corresponding basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2000
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EXHIBIT INDEX
Certain of the following exhibits, designated with an asterisk(*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.R. 229.10(d) and 240.12b-32, are incorporated herein by reference to the documents indicated in brackets following the descriptions of such exhibits. Exhibits, designated with a dagger (++) are management contracts or compensatory plans or arrangements required to be filed as an exhibit to this form pursuant to Item 14(c) of this report.
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++Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.
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