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 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 have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. As a result of the changing nature of the electric business (see Competition and Business Change), effective January 1, 1996, AEP's subsidiaries realigned into four functional business units: Power Generation; Nuclear Generation; Energy Delivery; and Corporate Development. In addition, the electric utility subsidiaries began to do business as "American Electric Power." The legal and financial structure of AEP and its subsidiaries, however, did not change.

At December 31, 1998, the subsidiaries of AEP had a total of 17,943 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 888,000 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, 1998, APCo and its wholly owned subsidiaries had 3,577 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 640,000 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, 1998, CSPCo had 1,528 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 554,000 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, 1998, I&M had 3,074 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 170,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1998, KEPCo had 541 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 44,000 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, 1998, Kingsport Power Company had 65 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 685,000 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, 1998, OPCo and its wholly owned subsidiaries had 4,170 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, 1998, Wheeling Power Company had 80 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, KEPCo and VEPCo. AEGCo has no employees.

See Item 2 for information concerning the properties of the subsidiaries of AEP.

The Service Corporation provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of the Service Corporation.

REGULATION

General

AEP and its subsidiaries are subject to the broad regulatory provisions of PUHCA administered by the SEC. The public utility subsidiaries' retail rates and certain other matters are subject to regulation by the public utility commissions of the states in which they operate. Such subsidiaries are also subject to regulation by

the FERC under the Federal Power Act in respect of rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.

Possible Change to PUHCA

The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system. In addition, PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions.

On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit authority over registered holding companies and their subsidiaries and oversight over affiliate transactions. This authority would be transferred to the FERC. Legislation was introduced in Congress in 1997 that would repeal PUHCA and transfer certain federal authority to the FERC as recommended in the SEC report as part of broader legislation regarding changes in the electric industry. Such legislation has been reintroduced in 1999. It is expected that a number of bills contemplating the restructuring of the electric utility industry will be introduced in the current Congress. See Competition and Business Change. If PUHCA is repealed, registered holding company systems, including the AEP System, will be able to compete in the changing industry without the constraints of PUHCA. Management of AEP believes that removal of these constraints would be beneficial to the AEP System.

PUHCA and the rules and orders of the SEC currently require that transactions between associated companies in a registered holding company system be performed at cost with limited exceptions. Over the years, the AEP System has developed numerous affiliated service, sales and construction relationships and, in some cases, invested significant capital and developed significant operations in reliance upon the ability to recover its full costs under these provisions.

Legislation has been introduced in Congress to repeal PUHCA or modify its provisions governing intra-system transactions. The effect of repeal or amendment of PUHCA on AEP's intra-system transactions depends on whether the assurance of full cost recovery is eliminated immediately or phased-in and whether it is eliminated for all intra-system transactions or only some. If the cost recovery assurance is eliminated immediately for all intra-system transactions, it could have a material adverse effect on results of operations and financial condition of AEP and OPCo.

Conflict of Regulation

Public utility subsidiaries of AEP can be subject to regulation of the same subject matter by two or more jurisdictions. In such situations, it is possible that the decisions of such regulatory bodies may conflict or that the decision of one such body may affect the cost of providing service and so the rates in another jurisdiction. In a case involving OPCo, the U.S. Court of Appeals for the District of Columbia held that the determination of costs to be charged to associated companies by the SEC under PUHCA precluded the FERC from determining that such costs were unreasonable for ratemaking purposes. The U.S. Supreme Court also has held that a state commission may not conclude that a FERC approved wholesale power agreement is unreasonable for state ratemaking purposes. Certain actions that would overturn these decisions or otherwise affect the jurisdiction of the SEC and FERC are under consideration by the U.S. Congress and these regulatory bodies. Such conflicts of jurisdiction often result in litigation and, if resolved adversely to a public utility subsidiary of AEP, could have a material adverse effect on the results of operations or financial condition of such subsidiary or AEP.

                                                                                                                    AEP
                                           AEGCO       APCO       CSPCO        I&M        KEPCO        OPCO     SYSTEM (a)
                                          --------  ----------  ----------  ----------    --------  ----------   ----------
                                                                          (IN THOUSANDS)
Retail
   Residential
      Without Electric Heating.........     $    0   $ 230,160   $ 335,270   $ 265,442    $ 40,190   $ 287,219  $ 1,179,792
      With Electric Heating............          0     328,623     104,905     108,950      64,516     139,052      781,659
                                          --------  ----------  ----------  ----------    --------  ----------   ----------
          Total Residential............          0     558,783     440,175     374,392     104,706     426,271    1,961,451
   Commercial..........................          0     284,206     394,363     290,149      60,115     276,135    1,343,426
   Industrial..........................          0     381,733     148,463     370,329      94,186     670,757    1,727,109
   Miscellaneous.......................          0      34,505      17,115       6,849         877       8,230       71,240
                                          --------  ----------  ----------  ----------    --------  ----------   ----------
         Total Retail..................          0   1,259,227   1,000,116   1,041,719     259,884   1,381,393    5,103,226
Wholesale (sales for resale)...........    223,821     350,014     145,376     321,771      87,401     644,058    1,005,481
                                          --------  ----------  ----------  ----------    --------  ----------   ----------
         Total from KWH Sales..........    223,821   1,609,241   1,145,492   1,363,490     347,285   2,025,451    6,108,707
Provision for Revenue Refunds..........          0     (7,796)           0           0           0           0     (10,044)
                                          --------  ----------  ----------  ----------    --------  ----------   ----------
         Total Net of Provision for
             Revenue Refunds...........    223,821   1,601,445   1,145,492   1,363,490     347,285   2,025,451    6,098,663
Other Operating Revenues...............        325      70,799      42,253      42,304      15,714      80,096      247,239
                                          --------  ----------  ----------  ----------    --------  ----------   ----------
         Total Electric Operating
Revenues...............................   $224,146  $1,672,244  $1,187,745  $1,405,794    $362,999  $2,105,547   $6,345,902
                                          ========  ==========  ==========  ==========    ========  ==========   ==========

(a) Includes revenues of other subsidiaries not shown and elimination of intercompany transactions.

SALE OF POWER

AEP's electric utility subsidiaries own or lease generating stations with total generating capacity of 23,759 megawatts. See Item 2 for more information regarding the generating stations. They operate their generating plants as a single interconnected and coordinated electric utility system and share the costs and benefits in the AEP System Power Pool. Most of the electric power generated at these stations is sold, in combination with transmission and distribution services, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates and Regulation. Some of the electric power is sold at wholesale to non-affiliated companies.

AEP System Power Pool

APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with the System's generating plants. This sharing is based upon each company's "member-load-ratio," which is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO2 Allowances associated with transactions under the Interconnection Agreement.

Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System's traditional marketing area and are typically settled by entering into offsetting contracts. The regulated physical forward contracts are recorded on a net basis in the month when the contract settles.

In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. These non-regulated trading activities are accounted for on a mark-to-market basis.

The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and Interim Allowance Agreement during the years ended December 31, 1996, 1997 and 1998:

                        1996          1997        1998(a)
                        ----          ----        -------
                                (IN THOUSANDS)

APCo..............   $(258,000)     $(237,000)   $(142,500)
CSPCo.............    (145,000)      (138,000)    (146,800)
I&M...............     121,000         67,000     ( 86,100)
KEPCo.............       2,000         20,000       34,000
OPCo..............     280,000        288,000      341,400

-------------------------

(a) Includes credits and charges from allowance transfers related to the transactions.

Wholesale Sales of Power to Non-Affiliates

AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo also sell electric power on a wholesale basis to non-affiliated electric utilities and power marketers. Such sales are either made by the AEP System Power Pool and then allocated among APCo, CSPCo, I&M, KEPCo and OPCo based on member-load-ratios or made by individual companies pursuant to various long-term power agreements. The following table shows the net realization (revenue less operating, maintenance, fuel and federal income tax expenses) of the various companies from such sales during the years ended December 31, 1996, 1997 and 1998:

                       1996(a)     1997(a)      1998(a)
                       -------     -------      -------
                                 (IN THOUSANDS)

AEGCo(b)............  $ 26,300    $ 26,200     $ 23,500
APCo(c).............    36,800      37,500       40,700
CSPCo(c)............    18,100      18,300       23,000
I&M(c)(d)...........    43,000      42,400       47,800
KEPCo(c)............     7,600       7,700        8,700
OPCo(c).............    30,200      30,200       36,900
                      --------    -------      --------
Total System........  $162,000    $162,300     $180,600
                      ========    ========     ========

-----------------------

(a) Such sales do not include wholesale sales to full/partial requirement customers of AEP System companies. See the discussion below.

(b) All amounts for AEGCo are from sales made pursuant to a long-term power agreement. See AEGCo -- Unit Power Agreements.

(c) All amounts, except for I&M, are from System sales which are allocated among APCo, CSPCo, I&M, KEPCo and OPCo based upon member-load-ratio. All System sales made in 1996, 1997 and 1998 were made on a short-term basis, except that $33,300,000, $25,900,000 and $38,300,000 respectively, of the contribution to operating income for the total System were from long-term System sales.

(d) In addition to its allocation of System sales, the 1996, 1997 and 1998 amounts for I&M include $20,900,000, $21,100,000 and $21,800,000 from a long-term agreement to sell 250 megawatts of power scheduled to terminate in 2009.

The AEP System has long-term system agreements to sell the following to unaffiliated utilities: (1) 205 megawatts of electric power through August 2010; and (2) 50 megawatts of electric power through August 2001.

In addition to long-term and short-term sales, APCo, CSPCo, I&M, KEPCo and OPCo serve unaffiliated wholesale customers that are full/partial requirement customers. The aggregate maximum demand for these customers in 1998 was 611, 109, 451, 18 and 140 megawatts for APCo, CSPCo, I&M, KEPCo and OPCo, respectively. Although the terms of the contracts with these customers vary, they generally can be terminated by the customer upon one to four years' notice. Since 1996, customers have given notices of termination, effective in 1999 and 2000, for 405, 63 and 131 megawatts for APCo, I&M and OPCo, respectively.

Several wholesale customers, some of whom had previously given notice of termination, have entered into long-term contracts, ranging from five to seven years, with the AEP System. The expected demand under these contracts aggregates approximately 245 megawatts.

In June 1993, certain municipal customers of APCo filed an application with the FERC for transmission service in order to reduce by 50 megawatts the power these customers then purchased under existing Electric Service Agreements (ESAs) and to purchase power from a third party. APCo maintains that its agreements with these customers were full-requirements contracts which precluded the customers from purchasing power from third parties until 1998. On February 10, 1994, the FERC issued an order finding that the ESAs are not full requirements contracts and that the ESAs give these municipal wholesale customers the option of substituting alternative sources of power for energy purchased from APCo. On May 24, 1994, APCo appealed the February 10, 1994 order of the FERC to the U.S. Court of Appeals for the District of Columbia Circuit. On July 1, 1994, the FERC ordered the requested transmission service and granted a complaint filed by the municipal customers directing certain modifications to the ESAs in order to accommodate their power purchases from the third party. Following FERC's denial of APCo's requests for rehearing, on December 20, 1995, APCo appealed the July 1, 1994 orders to the U.S. Court of Appeals for the District of Columbia. Effective August 1994, these municipal customers reduced their purchases by 40

megawatts. Certain of these customers further reduced their purchases by an additional 21 megawatts effective February 1996. On December 17, 1996, the U.S. Court of Appeals reversed the FERC's order directing APCo to provide transmission service and remanded the case to the FERC, where it remains pending. The customers terminated their contracts with APCo in 1998.

TRANSMISSION SERVICES

AEP's electric utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 for more information regarding the transmission and distribution lines. AEP's electric utility subsidiaries operate their transmission lines as a single interconnected and coordinated system and share the cost and benefits in the AEP System Transmission Pool. Most of the transmission and distribution services is sold, in combination with electric power, to retail customers of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which they operate. See Rates and Regulation. As discussed below, some transmission services also are separately sold to non-affiliated companies.

AEP System Transmission Pool

APCo, CSPCo, I&M, KEPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kv and above) and certain facilities operated at lower voltages (138 kv and above). Like the Interconnection Agreement, this sharing is based upon each company's "member-load-ratio." See Sale of Power.

The following table shows the net credits or (charges) allocated among the parties to the Transmission Agreement during the years ended December 31, 1996, 1997 and 1998:

                     1996            1997         1998
                     ----            ----         ----
                                (IN THOUSANDS)

APCo..........     $( 6,500)    $ ( 8,400)      $  2,400
CSPCo.........      (30,600)      (29,900)       (35,600)
I&M...........       46,300        46,100         44,100
KEPCo.........        3,300         2,700          6,000
OPCo..........      (12,500)      (10,500)       (16,900)

                             1996       1997        1998
                             ----       ----        ----
                                   (IN THOUSANDS)

APCo....................    $ 13,800   $ 18,000     $30,600
CSPCo...................       8,000     10,200      18,100
I&M.....................       7,700     10,500      19,200
KEPCo...................       2,800      3,900       6,400
OPCo....................      17,800     27,200      42,100
                            --------   --------    --------
Total System............    $ 50,100   $ 69,800    $116,400
                            ========   ========    ========

The AEP System has contracts with non-affiliated companies for transmission of approximately 5,000 megawatts of electric power on an annual or longer basis.

On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System ("OASIS") which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct which prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service.

On July 9, 1996, the AEP System companies filed a tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues, which are still pending before FERC.

During 1996 and 1997 AEP engaged in discussions with several utilities regarding the creation of an independent system operator to operate the transmission system in the Midwestern region of the United States. In January 1998, nine utilities or utility systems filed with the FERC a proposal to form the Midwest Independent Transmission System Operator, Inc. ("Midwest ISO"). AEP was not a participant in that filing and elected not to join the Midwest ISO as a transmission owner member. AEP has since joined the Midwest ISO as a non-owner member.

AEP is currently engaged in discussions with Consumers Energy Company, FirstEnergy Corp. and VEPCo regarding the development of a Regional Transmission Organization ("RTO") which may take the form of an independent system operator ("ISO") or an independent transmission company ("Transco"), depending upon the occurrence of certain conditions. The parties envision that the Transco, if formed, would operate transmission assets that it would own, and also would operate other owners' transmission assets on a contractual basis. The discussions are also open to interested stakeholders. The discussions are expected to culminate in a FERC filing during the first part of 1999. See Competition and Business Change -- AEP Position on Competition.

OVEC

AEP, CSPCo and several unaffiliated utility companies jointly own OVEC, which supplies the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE. The aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. The DOE demand under OVEC's power agreement, which is subject to change from time to time, is 1,402,000 kilowatts. On April 1, 1999, it is scheduled to increase to approximately 1,900,000 kilowatts. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. APCo, CSPCo, I&M and OPCo, as sponsoring companies, are entitled to receive from OVEC, and are obligated to pay for, the power not required by DOE in proportion to their power participation ratios, which averaged 42.1% in 1998. The power agreement with DOE terminates on December 31, 2005, subject to early termination by DOE on not less than three years notice. The power agreement among OVEC and the sponsoring companies expires by its terms on March 12, 2006.

BUCKEYE

Contractual arrangements among OPCo, Buckeye and other investor-owned electric utility companies in Ohio provide for the transmission and delivery, over facilities of OPCo and of other investor-owned utility companies, of power generated by the two units at the Cardinal Station owned by Buckeye and back-up power to which Buckeye is entitled from OPCo under such contractual arrangements, to facilities owned by 26 of the rural electric cooperatives which operate in the State of Ohio at 318 delivery points. Buckeye is entitled under such arrangements to receive, and is obligated to pay for, the excess of its maximum one-hour coincident peak demand plus a 15% reserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station. Such demand, which occurred on January 16, 1997, was recorded at 1,178,460 kilowatts.

CERTAIN INDUSTRIAL CUSTOMERS

Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum Corporation), and Ormet Corporation operate major aluminum reduction plants in the Ohio River Valley at Ravenswood, West Virginia, and in the vicinity of Hannibal, Ohio, respectively. The power requirements of such plants presently are approximately 357,000 kilowatts for Century and 537,000 kilowatts for Ormet. OPCo is providing electric service to Century pursuant to a contract approved by the PUCO for the period July 1, 1996 through July 31, 2003.

On November 14, 1996, the PUCO approved (1) an interim agreement pursuant to which OPCo will continue to provide electric service to Ormet for the period December 1, 1997 through December 31, 1999 and (2) a joint petition with an electric cooperative to transfer the right to serve Ormet to the electric cooperative after December 31, 1999. As part of the territorial transfer, OPCo and Ormet entered into an agreement which contains penalties and other provisions designed to avoid having OPCo provide involuntary back-up power to Ormet. See Legal Proceedings for a discussion of litigation involving Ormet.

AEGCO

Since its formation in 1982, AEGCo's business has consisted of the ownership and financing of its 50% interest in the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating revenues of AEGCo are derived from the sale of capacity and energy associated with its interest in the Rockport Plant to I&M, KEPCo and VEPCo, pursuant to unit power agreements. Pursuant to these unit power agreements, AEGCo is entitled to recover its full cost of service from the purchasers and will be entitled to recover future increases in such costs, including increases in fuel and capital costs. See Unit Power Agreements. Pursuant to a capital funds agreement, AEP has agreed to provide cash capital contributions, or in certain circumstances subordinated loans, to AEGCo, to the extent necessary to enable AEGCo, among other things, to provide its proportionate share of funds required to permit continuation of the commercial operation of the Rockport Plant and to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party. See Capital Funds Agreement.

Unit Power Agreements

A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances.

Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires on December 31, 2004.

A unit power agreement among AEGCo, I&M, VEPCo, and APCo provides for, among other things, the sale of 70% of the power and energy available to AEGCo from Unit 1 of the Rockport Plant to VEPCo by AEGCo from January 1, 1987 through December 31, 1999. VEPCo has agreed to pay to AEGCo in consideration for the right to receive such power those amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. Approximately 32% of AEGCo's operating revenue in 1998 was derived from its sales to VEPCo.

Capital Funds Agreement

AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full.

INDUSTRY PROBLEMS

The electric utility industry, including the operating subsidiaries of AEP, has encountered at various times in the last 15 years significant problems in a number of areas, including: delays in and limitations on the recovery of fuel costs from customers; proposed legislation, initiative measures and other actions designed to prohibit construction and operation of certain types of power plants and transmission lines under certain conditions and to eliminate or reduce the extent of the coverage of fuel adjustment clauses; inadequate rate increases and delays in obtaining rate increases; jurisdictional disputes with state public utilities commissions regarding the interstate operations of integrated electric systems; requirements for additional expenditures for pollution control facilities; increased capital and operating costs; construction delays due, among other factors, to pollution control and environmental considerations and to material, equipment and fuel shortages; the economic effects on net income (which when combined with other factors may be immediate and adverse) associated with placing large generating units and related facilities in commercial operation, including the commencement at that time of substantial charges for depreciation, taxes, maintenance and other operating expenses, and the cessation of AFUDC with respect to such units; uncertainties as to conservation efforts by customers and the effects of such efforts on load growth; depressed economic conditions in certain regions of the United States; increasingly competitive conditions in the wholesale and retail markets; availability of capacity; proposals to deregulate certain portions of the industry and revise the rules and responsibilities under which new generating capacity is supplied; and substantial increases in construction costs and difficulties in financing due to high costs of capital, uncertain capital markets, charter and indenture limitations restricting conventional financing, and shortages of cash for construction and other purposes.

SEASONALITY

Sales of electricity by the AEP System tend to increase and decrease because of the use of electricity by residential and commercial customers for cooling and heating and relative changes in temperature.

FRANCHISES

The operating companies of the AEP System hold franchises to provide electric service in various municipalities in their service areas. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business.

COMPETITION AND BUSINESS CHANGE

General

The public utility subsidiaries of AEP, like other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers. Proposals are being made that would also require electric utilities to sell distribution services separately. These proposals generally allow competition in the generation and sale of electric power, but not in its transmission and distribution.

Competition in the generation and sale of electric power will require resolution of complex issues, including who will pay for the unused generating plant of, and other stranded costs incurred by, the utility when a customer stops buying power from the utility; will all customers have access to the benefits of competition; how will the rules of competition be established; what will happen to conservation and other regulatory-imposed programs; how will the reliability of the transmission system be ensured; and how will the utility's obligation to serve be changed. As a result, it is not clear how or when competition in generation and sale of electric power will be instituted. However, if competition in generation and sale of electric power is instituted, the public utility subsidiaries of AEP believe that they have a favorable competitive position because of their relatively low costs. If stranded costs are not recovered from customers, however, the public utility subsidiaries of AEP, like all electric utilities, will be required by existing accounting standards to recognize any stranded investment losses.

AEP Position on Competition

In October 1995, AEP announced that it favored freedom for customers to purchase electric power from anyone that they choose. Generation and sale of electric power would be in the competitive marketplace. To facilitate reliable, safe

and efficient service, AEP supports creation of independent system operators to operate the transmission system in a region of the United States. In addition, AEP supports the evolution of regional power exchanges which would establish a competitive marketplace for the sale of electric power. Transmission and distribution would remain monopolies and subject to regulation with respect to terms and price. Regulators would be able to establish distribution service charges which would provide, as appropriate, for recovery of stranded costs and regulatory assets. AEP's working model for industry restructuring envisions a progressive transition to full customer choice. Implementation of these measures would require legislative changes and regulatory approvals.

Wholesale

The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition to sell available power on a wholesale basis, primarily to other public utilities and also to power marketers. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market (a) through amendments to PUHCA, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Federal Power Act, authorizing the FERC under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services for other utilities and entities generating electric power. The principal factors in competing for such sales are price (including fuel costs), availability of capacity and reliability of service. The public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. However, because of the availability of capacity of other utilities and the lower fuel prices in recent years, price competition has been, and is expected for the next few years to be, particularly important.

FERC orders 888 and 889, issued in April 1996, provide that utilities must functionally unbundle their transmission services, by requiring them to use their own tariffs in making off-system and third-party sales. See Transmission Services. The public utility subsidiaries of AEP have functionally separated their wholesale power sales from their transmission functions, as required by orders 888 and 889.

Retail

The public utility subsidiaries of AEP generally have the exclusive right to sell electric power at retail within their service areas. However, they do compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to self-generation, the public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.

Significant changes in the global economy in recent years have led to increased price competition for industrial companies in the United States, including those served by the AEP System. Such industrial companies have requested price reductions from their suppliers, including their suppliers of electric power. In addition, industrial companies which are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, various off-peak or interruptible supply options and believe that, as low cost suppliers of electric power, they should be less likely to be materially adversely affected by this competition and may be benefited by attracting new industrial customers to their service territories.

The legislatures and/or the regulatory commissions in many states are considering or have adopted "retail customer choice" which, in general terms, means the transmission by an electric utility of electric power generated by an entity of the customer's choice over its transmission and distribution system to a retail customer in such utility's

service territory. A requirement to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer. Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. If competition develops in retail power generation, the public utility subsidiaries of AEP believe that they should have a favorable competitive position because of their relatively low costs.

Federal: Legislation to provide for retail competition among electric energy suppliers has been introduced in both the U.S. Senate and House of Representatives.

Indiana: In January 1999, Senate Bill 648 was introduced in the Indiana Senate on behalf of a group of industrial customers. The bill would allow retail electric customers to choose their electricity supply companies after December 31, 2000. The bill would provide that the IURC would determine each utility's net stranded costs, which would be recovered by a transition charge in effect until no later than December 31, 2005. The bill was not reported out of committee and attempts by the sponsors to amend the bill were unsuccessful. AEP continues to work with other utilities in Indiana to develop a consensus on customer-choice legislation that can be enacted into law in Indiana. The outcome of this effort is uncertain.

Kentucky: During the 1998 Regular Session of the Kentucky legislature, the Electric Utility Restructuring Task Force was established by resolution. The 20-member Task Force includes ten members of the General Assembly and ten officials from the Governor's office. The Task Force began monthly meetings in August 1998. At the January 1999 meeting, AEP, the other Kentucky investor-owned public utilities and the Kentucky electric cooperatives were requested to file with the Task Force a description of their non-traditional, unregulated businesses. The final report of the Task Force is due in November 1999, prior to the next regularly scheduled legislative session in 2000.

A second Task Force was also established to study the effects of utility restructuring on taxes. This Task Force also has been meeting monthly and will report its findings in November 1999. Several advisory committees have been formed to assist this Task Force in gathering and studying information. The Kentucky investor-owned utilities, including AEP, are represented on each of those committees. At the January meeting, the Task Force voted to retain a consulting firm with extensive experience in utility tax issues to facilitate the proceedings.

The KPSC Chairwoman leads 23 state public utility commissions in a coalition entitled Low Cost States Initiative. The coalition's stated purpose is to ensure that the U.S. Congress gives equal consideration to the issues facing low-cost states. The coalition is focusing on the following five issues:

o A National Voice.

o Low Rates.

o Rural Electricity Rates.

o Stranded Costs and Benefits.

o Economic Development.

Michigan: In June 1995, the MPSC issued an order approving an experimental five-year retail wheeling program and ordered Consumers Energy Company (Consumers) and Detroit Edison Company (Detroit Edison), unaffiliated utilities, to make retail delivery services available to a group of industrial customers, in the amount of 60 megawatts and 90 megawatts, respectively. The experiment, which commences when each utility needs new capacity, seeks to determine whether a retail wheeling program best serves the public interest. During the experiment, the MPSC will collect information regarding the effects of retail wheeling. Consumers, Detroit Edison and other parties have appealed the MPSC's order to the Michigan Supreme Court.

In January 1996, the Governor of Michigan endorsed a proposal of the Michigan Jobs Commission to promote competition and customer choice in energy and requested that the MPSC review the existing statutory and regulatory framework governing Michigan utilities in light of increasing competition in the utility industry. In December 1996, the MPSC staff issued a report on electric industry restructuring which recommended

a phase-in program from 1997 through 2004 of direct access to electricity suppliers applicable to all customers. On June 5, 1997, the MPSC entered an order requiring electric utilities (including I&M) to phase in retail open access for customers, with full customer choice by 2002 (MPSC Order). Under the MPSC Order, customer choice is phased in from 1997 through 2001, at the rate of 2.5% of each utility's customer load per year, with all customers becoming eligible to choose their electric supplier effective January 1, 2002. The MPSC Order essentially adopted the December 1996 MPSC staff report that recommended full recovery of stranded costs of utilities, including nuclear generating investment, through the use of a transition charge applicable to customers exercising choice. While concluding that securitization of stranded costs would be feasible, the MPSC Order stated that legislative authorization is required prior to the implementation of any securitization program.

As required by the MPSC Order, in July 1997, I&M filed a proposed open access distribution tariff phasing in customer choice for all customer classes. However, the MPSC has closed the relevant docket and taken no action with regard to AEP's filing. The MPSC has approved, by orders dated January 14, 1998, February 11, 1998 and March 8, 1999, after contested proceedings and with modifications, filings made by Consumers and Detroit Edison. Detroit Edison, the Michigan Attorney General and other parties have appealed the MPSC's orders to the Michigan Court of Appeals.

Ohio: In March 1998, twin proposals on electric industry restructuring were introduced in the Ohio House and Senate. Among other provisions, the bills proposed a fully competitive marketplace in the year 2000, with no phase-in period. The bills were the subject of hearings in the Senate Ways and Means Committee and the House Public Utilities Committee in April-May 1998. However, no additional action was taken with respect to the bills by the end of the legislative session on December 31, 1998.

In August 1998, four of Ohio's investor-owned electric utilities - AEP, Cinergy Corp., FirstEnergy and DP&L - announced that they had reached a consensus on a basic alternative framework to deregulate Ohio's electric industry. The proposal called for:

o The introduction of customer choice on January 1, 2001.

o A freeze on rates during a five-year transition period.

o Changes in utility taxes to achieve, among other things, equalized treatment of in-state and out-of-state electricity suppliers.

o An opportunity to recover stranded costs during a five-year transition period.

In September 1998, the leaders of the House and Senate called for a series of "working study group" meetings involving the various stakeholder groups. The study group's members were encouraged to reconcile their differences and develop a consensus position on industry restructuring. The working study group continues to hold periodic meetings.

On January 20, 1999, two new "placeholder" bills were introduced in the Ohio House and Senate declaring the legislature's public policy with respect to electric industry restructuring. On March 8, 1999, a legislative working group released a Summary of Proposed Major Provisions of Electric Restructuring Legislation. It is expected that these provisions will be incorporated into more extensive legislative proposals expected to supplant the placeholder bills. Legislative leaders have publicly indicated their desire to pass restructuring legislation during the current legislative session.

Virginia: On February 25, 1999, the legislature passed an electric utility industry restructuring bill and tax reform bill. The restructuring bill requires Virginia utilities to join or establish a regional transmission entity by January 2001, to which such utilities shall transfer the management and control of their transmission systems. The bill provides for a transition to retail customer choice from January 1, 2002 through January 1, 2004. The Virginia SCC can delay or accelerate the implementation of choice based on considerations of reliability, safety, communications or market power, but in no event shall any delay extend the implementation of customer choice beyond January 1, 2005. With limited exceptions, the generation of electricity will no longer be subject to regulation.

The bill provides for capped rates, effective January 1, 2001, for a period of time ending as late as July 1, 2007. The capped rates may be terminated

after January 1, 2004, upon petition of the Virginia SCC by the utility and a finding by the Virginia SCC that an effective competitive market exists. If capped rates continue beyond January 1, 2004, the bill provides for a one-time change in the non-generation components of such rates upon approval by the Virginia SCC. The Virginia SCC also may adjust the capped rates in connection with the utility's recovery of fuel costs, changes in taxation by Virginia, and any financial distress of the utility beyond the utility's control.

The restructuring bill provides for recovery of just and reasonable net stranded costs to the extent that such costs exceed zero in total value for any incumbent electric utility through either capped rates or the imposition of a wires charge upon customers who may depart the incumbent in favor of an alternative supplier prior to the termination of the rate cap.

A ten-member legislative task force, to serve from July 1, 1999 through July 1, 2005, will monitor the work of the Virginia SCC, determine the discontinuance of capped rates and review related matters. The task force will report annually to the Governor and legislature.

The tax bill provides for replacement of gross receipts and certain other taxes by (i) a consumption tax levied upon customers on the basis of kilowatt-hour usage and (ii) a state corporate net income tax. The intention of the tax bill is to achieve approximate revenue neutrality for Virginia.

West Virginia: In December 1996, the West Virginia PSC issued an order initiating a general investigation into the restructuring of the regulated electric industry. The Task Force established by the West Virginia PSC to study electric industry restructuring issued its Initial Report in October 1997 and Supplemental Report on Recommended Legislation in January 1998. On March 14, 1998, the West Virginia Legislature passed restructuring legislation authorizing the West Virginia PSC to proceed with the development of a plan for electric industry restructuring, if restructuring is determined by the West Virginia PSC to be in the public interest. Any plan developed and proposed by the West Virginia PSC must be approved by the West Virginia Legislature before such plan can be made effective. Following the passage of the restructuring legislation, the West Virginia PSC closed the 1996 general investigation and commenced a new proceeding to carry out its obligations under the legislation.

On April 20, 1998, the West Virginia PSC initiated a general investigation to determine whether West Virginia should adopt a restructuring plan. Workshops were held throughout the summer of 1998 and on November 24, 1998, the West Virginia PSC held a hearing at which the West Virginia PSC was advised that the participants involved in the general investigation had been unable to reach a consensus on a restructuring plan. The West Virginia PSC then issued a procedural order on December 23, 1998, establishing dates beginning in June 1999 for pre-filed testimony, responsive testimony, hearing dates and briefs regarding the issues of codes of conduct, universal service, class subsidies and generation plant valuation.

Possible Strategic Responses

In response to the competitive forces and regulatory changes being faced by AEP and its public utility subsidiaries, as discussed under this heading and under Regulation, AEP and its public utility subsidiaries have from time to time considered, and expect to continue to consider, various strategies designed to enhance their competitive position and to increase their ability to adapt to and anticipate changes in their utility business. These strategies may include business combinations with other companies, internal restructurings involving the complete or partial separation of their generation, transmission and distribution businesses, acquisitions of related or unrelated businesses, and additions to or dispositions of portions of their franchised service territories. AEP and its public utility subsidiaries may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding one or more of these potential strategies. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to its ultimate effect on the financial condition or competitive position of AEP and its public utility subsidiaries.

NEW BUSINESS DEVELOPMENT

AEP has expanded its business to non-regulated energy activities through several subsidiaries, including AEP Energy Services, Inc. (AEPES), AEP Resources, Inc. (Resources), AEP Resources Service Company (RESCo) and AEP Communications, LLC (AEP Communications).

AEPES

AEPES markets and trades natural gas and provides gas storage and transportation services.

Resources

Resources' primary business is development of, and investment in, exempt wholesale generators, foreign utility companies, qualifying cogeneration facilities and other energy-related domestic and international investment opportunities and projects. Resources has business development offices in London, Beijing, Singapore, Sydney, Toronto, Washington and Houston.

Resources has a 50% interest in Yorkshire Electric Group plc (Yorkshire Electricity) with an indirect wholly-owned subsidiary of New Century Energies, Inc. Yorkshire Electricity is a United Kingdom independent regional electricity company. It is principally engaged in the distribution of electricity to 2.2 million customers in its authorized service territory which is comprised of 3,860 square miles and located centrally in the east coast of England.

Resources' indirect subsidiary, AEP Pushan Power LDC, has a 70% interest in Nanyang General Light Electric Co., Ltd. (Nanyang Electric), a joint venture organized to develop and build two 125 megawatt coal-fired generating units near Nanyang City in the Henan Province of The Peoples Republic of China. Nanyang Electric was established in 1996 by AEP Pushan Power LDC, Henan Electric Power Development Co. (15% interest) and Nanyang City Hengsheng Energy Development Company Limited (formerly Nanyang Municipal Finance Development Co.) (15% interest). Funding for the construction of the generating units has commenced and will continue through completion. Unit 1 went into service in February 1999 and Unit 2 is expected to go into service in the third quarter of 1999. Resources' share of the total cost of the project of $190,000,000 is estimated to be approximately $110,000,000.

In March 1998, Resources, through AEP Resources Australia Pty., Ltd., a special purpose subsidiary of Resources, acquired a 20% interest in Pacific Hydro Limited for $10,000,000. Pacific Hydro is principally engaged in the development and operation of, and ownership of interests in, hydroelectric facilities in the Asia Pacific region. Currently, Pacific Hydro has interests in six hydroelectric units that operate or are under construction in Australia and the Philippines. The hydroelectric facilities in which Pacific Hydro had interests as of December 31, 1998 (including those under construction) had total design capacity of approximately 178 megawatts.

In December 1998, Resources, through wholly-owned subsidiaries, acquired CitiPower Pty., an electric distribution and retail sales company in Victoria, Australia, for $1,100,000,000. CitiPower serves approximately 240,000 customers in the city of Melbourne. With about 3,100 miles of distribution lines in a service area that covers approximately 100 square miles, CitiPower distributes about 4,800 gigawatt-hours annually.

In December 1998, Resources acquired from Equitable Resources, Inc. midstream gas operations for approximately $340,000,000 including working capital funds. The gas trading and marketing group included in this purchase was acquired by AEPES. Assets acquired include:

o A 2,000-mile intrastate pipeline system in Louisiana.

o Four natural gas processing plants that straddle the pipeline.

o Jefferson Island storage facility, including an existing salt dome storage cavern and a second cavern under construction, both directly connected to the Henry Hub, the most active gas trading area in North America.

The pipeline and storage facility are interconnected to 15 interstate and 23 intrastate pipelines.

RESCo

RESCo offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally.

AEP Communications

AEP Communications markets energy information, wireless tower infrastructure and fiber optic services. In 1998, AEP Communications launched DatapultSM, a portfolio of energy information data and analysis tools designed to help customers identify energy- and cost-saving opportunities. AEP Communications also is expanding its fiber optic network and marketing dedicated telecommunications bandwidth to other carriers.

AEP Power Marketing

In July 1996, AEP Power Marketing, Inc. (AEPPM), a wholly-owned subsidiary of AEP, requested authority from FERC to market electric power at wholesale at market-based rates. In September 1996, the FERC accepted the filing, conditioned upon, among other things, the utility subsidiaries of AEP refraining from (1) selling nonpower goods or services to any affiliate at a price below its cost or market price, whichever is higher, and (2) purchasing nonpower goods or services from any affiliate at a price above market price. AEPPM requested FERC to clarify that the applicability of this condition relates only to transactions between AEP utility subsidiaries and AEPPM. In 1998, FERC granted the requested clarification. AEPPM has not entered into any transactions to date. However, the AEP System is engaged in regulated power marketing and trading within its traditional marketing area through its Power Pool and in non-regulated financial derivative power trading activities conducted by the Power Pool but recorded in non-operating income by the AEP Power Pool member companies.

SEC Limitations

AEP has received approval from the SEC under PUHCA to issue and sell securities in an amount up to 100% of its average quarterly consolidated retained earnings balance (such average balance was approximately $1,674,000,000 for the twelve months ended December 31, 1998) for investment in exempt wholesale generators and foreign utility companies. Resources expects to continue its pursuit of new and existing energy generation and delivery projects worldwide.

SEC Rule 58 permits AEP and other registered holding companies to invest up to 15% of consolidated capitalization in energy-related companies. AEPES, an energy-related company under Rule 58, is authorized to engage in energy-related activities, including marketing electricity, gas and other energy commodities.

Risk

These continuing efforts to invest in and develop new business opportunities offer the potential of earning returns which may exceed those of traditional AEP rate-regulated operations. However, they also involve a higher degree of risk which must be carefully considered and assessed. AEP may make additional substantial investments in these and other new businesses.

Reference is made to Market Risks under Item 7A herein for a discussion of certain market risks inherent in AEP business activities.

PROPOSED AEP-CSW MERGER

AEP and CSW entered into an Agreement and Plan of Merger, dated as of December 21, 1997, pursuant to which CSW would, on the closing date, merge with and into a wholly owned merger subsidiary of AEP with CSW being the surviving corporation. As a result of the merger, each outstanding share of common stock, par value $3.50 per share, of CSW (other than shares owned by AEP or CSW) shall be converted into the right to receive 0.6 of a share of common stock, par value $6.50 per share, of AEP. Based on the price of AEP's common stock on December 19, 1997, the transaction would be valued at $6.6 billion. The combined company will be named American Electric Power Company, Inc. and will be based in Columbus, Ohio.

Consummation of the merger is subject to certain conditions, including the receipt of required regulatory approvals. Assuming the receipt of all required approvals, completion of the merger is anticipated to occur by the end of 1999.

CSW is a global, diversified public utility holding company based in Dallas, Texas. CSW owns four domestic electric utility subsidiaries serving 1.7 million customers in portions of the

states of Texas, Oklahoma, Louisiana and Arkansas and a regional electricity company in the United Kingdom. CSW also owns other international energy operations and non-regulated subsidiaries involved in energy-related investments, energy efficiency services and financial transactions.

CONSTRUCTION PROGRAM

New Generation

The AEP System is continuously involved in assessing the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment and planning process, assumptions are continually being reviewed as new information becomes available, and assessments and plans are modified, as appropriate. Thus, System reinforcement plans are subject to change, particularly with the anticipated restructuring of the electric utility industry and the move to increasing competition in the marketplace. See Competition and Business Change.

Committed or anticipated capability changes to the AEP System's generation resources include:

o Rerating of the Smith Mountain pumped storage hydroelectric plant (36-megawatt increase).

o Purchase from an independent power producer's hydro project with an expected capacity value of 28 megawatts.

o Expiration of the Rockport Unit 1 sale of 455 megawatts to VEPCo on December 31, 1999 (see AEGCo).

Apart from these changes and temporary power purchases that can be arranged, there are no specific commitments for additions of new generation resources on the AEP System. In this regard, the most recent resource plan filed by AEP's electric utility subsidiaries with various state commissions indicates no need for new generation resources until beyond the year 2003. When the time for commitment to additional generation resources approaches, all means for adding such resources, including self-build and external resource options, will be considered. However, given the restructuring that is expected to take place in the industry, the extent of the need of AEP's operating companies for any additional generation resources in the foreseeable future is highly uncertain.

Proposed Transmission Facilities

On September 30, 1997, APCo refiled applications in Virginia and West Virginia for certificates to build the Wyoming-Cloverdale 765,000-volt line. The preferred route for this line is approximately 132 miles in length, connecting APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale Station near Roanoke, Virginia. APCo's estimated cost is $263,300,000.

APCo announced this project in 1990. Since then it has been in the process of trying to obtain federal permits and state certificates. At the federal level, the U.S. Forest Service (Forest Service) is directing the preparation of an Environmental Impact Statement (EIS), which is required prior to granting permits for crossing lands under federal jurisdiction. Permits are needed from the (i) Forest Service to cross federal forests, (ii) Army Corps of Engineers to cross the New River and a watershed near the Wyoming Station, and (iii) National Park Service or Forest Service to cross the Appalachian National Scenic Trail.

In June 1996, the Forest Service released a Draft EIS and preliminarily identified a "No Action Alternative" as its preferred alternative. If this alternative were incorporated into the Final EIS, APCo would not be authorized to cross federal forests administered by the Forest Service. The Forest Service stated that it would not prepare the Final EIS until after Virginia and West Virginia determined need and routing issues.

West Virginia: On May 27, 1998, the West Virginia PSC issued an order granting APCo's application for a certificate with respect to the preferred route for the Wyoming-Cloverdale 765,000-volt line.

Virginia: By Hearing Examiner's Ruling of June 9, 1998, the procedural schedule for the certificate in Virginia was suspended for 90 days to allow APCo to conduct additional studies. On August 21, 1998, APCo filed a report stating that a two-phased alternative project could provide electrical transmission reinforcement comparable to the Wyoming-Cloverdale line.

By Hearing Examiner's Ruling of September 22, 1998, the proceeding was continued and APCo was directed to study the first phase of the alternative

project, involving a line running from Wyoming Station in West Virginia to APCo's existing Jacksons Ferry Station in Virginia or any point on the Jacksons Ferry-Cloverdale 765kV transmission line. APCo estimates that the Wyoming-Jacksons Ferry line would be between 82-100 miles in length, including 32 miles in West Virginia previously certified. APCo must file its study by June 1, 1999. The Hearing Examiner also ordered APCo and the Virginia SCC Staff to provide at the evidentiary hearing information on generation alternatives, specifically natural gas generation, to APCo's proposed transmission line.

If the Virginia SCC grants a certificate for the Wyoming-Jacksons Ferry line, APCo will have to amend its certificate from West Virginia.

Proposed Completion Schedule: If the Virginia SCC and West Virginia PSC issue the required certificates, APCo will cooperate with the Forest Service to complete the EIS process and obtain the federal permits. Management estimates that neither project can be completed before the winter of 2003-2004. However, given the findings in the Draft EIS, APCo cannot presently predict the schedule for completion of the state and federal permitting process.

                     1996      1997     1998        1999
                    ACTUAL    ACTUAL   ACTUAL     ESTIMATE
                    ------    ------   ------     --------
                               (IN THOUSANDS)

AEP System (a)..   $578,000  $762,000   $792,100   $820,100

   AEGCo........      2,200     3,900      6,600      6,300

   APCo.........    192,900   218,100    204,900    254,600

   CSPCo........     93,600   108,900    115,300     94,500

   I&M..........     90,500   123,400    148,900    151,800

   KEPCo........     75,800    66,700     43,800     42,500

   OPCo.........    113,800   172,700    185,200    201,000


-----------------------

(a) Includes expenditures of other subsidiaries not shown.

Reference is made to the footnotes to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years.

The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program.

From time to time, as the System companies have encountered the industry problems described above, such companies also have encountered limitations on their ability to secure the capital necessary to finance construction expenditures.

Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1996, 1997 and 1998 and the current estimate for 1999 are shown below. Substantial expenditures in addition to the amounts set forth below may be required by the System in future years in connection with the modification and addition of facilities at generating plants for environmental quality controls in order to comply with air and water quality standards which have been or may be adopted.

                      1996      1997      1998       1999
                     ACTUAL    ACTUAL    ACTUAL    ESTIMATE
                     ------    ------    ------    --------
                                 (IN THOUSANDS)

AEGCo.............  $     0  $     0   $   800   $     0

APCo..............   10,500    9,100    25,000    36,100

CSPCo.............    1,800    1,300     5,300     3,600

I&M...............        0      100    13,000     6,700

KEPCo.............      100    1,300     4,600       400

OPCo..............    1,600   11,800    27,100    32,100

   AEP System.....  $14,000  $23,600   $75,800   $78,900
                    =======  =======   =======   =======

FINANCING

It has been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available internally generated funds by initially issuing unsecured short-term debt, principally commercial paper and bank loans, at times up to levels authorized by regulatory agencies, and then to reduce the short-term debt with the proceeds of subsequent sales by such subsidiaries of long-term debt securities and cash capital contributions by AEP. It has been the practice of AEP, in turn, to finance cash capital contributions to the common stock equities of its subsidiaries by issuing unsecured short-term debt, principally commercial paper, and then to sell additional shares of Common Stock of AEP for the purpose of retiring the short-term debt previously incurred. In 1998, AEP issued approximately 1,193,000 shares of Common Stock pursuant to its Dividend Reinvestment and Stock Purchase Plan. Although prevailing interest costs of short-term bank debt and commercial paper generally have been lower than prevailing interest costs of long-term debt securities, whenever interest costs of short-term debt exceed costs of long-term debt, the companies might be adversely affected by reliance on the use of short-term debt to finance their construction and other capital requirements.

During the period 1996-1998, net external funds from financings and capital contributions by AEP amounted, with respect to APCo and KEPCo, to approximately 23% and 75%, respectively, of the aggregate construction expenditures shown above. During this same period, the amount of funds used to retire long-term and short-term debt and preferred stock of AEGCo, CSPCo and OPCo exceeded the amount of funds from financings and capital contributions by AEP.

The ability of AEP and its subsidiaries to issue short-term debt is limited by regulatory restrictions and, in the case of most of the operating subsidiaries, by provisions contained in certain debt and other instruments. The approximate amounts of short-term debt which the companies estimate that they were permitted to issue under the most restrictive such restriction, at January 1, 1999, and the respective amounts of short-term debt outstanding on that date, on a corporate basis, are shown in the following tabulation:

                                                                                                                TOTAL AEP
              SHORT-TERM DEBT                     AEP     AEGCO     APCO     CSPCO     I&M     KEPCO     OPCO   SYSTEM(a)
              ---------------                     ---     -----     ----     -----     ---     -----     ----   ---------
                                                                             (IN MILLIONS)

Amount authorized...........................     $500       $80     $325     $300    $300      $150      $400     $2,115
                                                 ====       ===     ====     ====    ====      ====      ====     ======
Amount outstanding:
      Notes payable.........................     $ --        $24    $ 34     $ --    $ --      $  5      $ --     $  197
      Commercial paper......................       78         --      42       52     109        15       123        419
                                                 ----        ---    ----     ----    ----      ----      ----     ------
                                                 $ 78        $24    $ 76     $ 52    $109      $ 20      $123     $  616
                                                 ====        ===    ====     ====    ====      ====      ====     ======

(a) Includes short-term debt of other subsidiaries not shown.

Reference is made to the footnotes to the financial statements incorporated by reference in Item 8 for further information with respect to unused short-term bank lines of credit.

In order to issue additional first mortgage bonds, it is necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage requirements contained in their respective mortgages. The most restrictive of these provisions generally requires, for the issuance of first mortgage bonds for purposes other than the refunding of outstanding first mortgage bonds, a minimum, before income tax, earnings coverage of twice the pro forma annual interest charges on first mortgage bonds for a period of twelve consecutive calendar months within the fifteen calendar months immediately preceding the proposed new issue. In computing such coverages, the companies include as a component of earnings revenues collected subject to refund (where applicable) and, to the extent not limited by the instrument under which the computation is made, AFUDC, including amounts positioned and classified as an allowance for borrowed funds used during construction. These coverage provisions have at certain times restricted the ability of one or more of the above subsidiaries of AEP to issue senior securities.

The respective mortgage coverages of APCo, CSPCo, I&M, KEPCo and OPCo under their respective mortgage provisions, calculated on the foregoing basis and in accordance with the respective amounts then recorded in the accounts of the companies, were at least those stated in the following table:

                                       1996    1997    1998
                                       ----    ----    ----
APCo
      Mortgage coverage.............   3.98    3.72    3.88
CSPCo
      Mortgage coverage.............   4.44    4.95    6.36
I&M
      Mortgage coverage.............   6.66    7.57    6.39
KEPCo
      Mortgage coverage.............   3.22    4.23    4.40
OPCo
      Mortgage coverage.............   8.27    9.74    9.40

Although certain other subsidiaries of AEP either are not subject to any coverage restrictions or are not subject to restrictions as constraining as those to which APCo, CSPCo, I&M, KEPCo and OPCo are subject, their ability to finance substantial portions of their construction programs may be subject to market limitations and other constraints unless other assurances are furnished.

AEP believes that the ability of some of its subsidiaries to issue short- and long-term debt securities in the amounts required to finance their business may depend upon the timely approval of rate increase applications. If one or more of the subsidiaries are unable to continue the issuance and sale of securities on an orderly basis, such company or companies will be required to consider the curtailment of construction and other outlays or the use of alternative financing arrangements, if available, which may be more costly.

AEP's subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as leasing arrangements, including the leasing of utility assets, coal mining and transportation equipment and facilities and nuclear fuel. Pollution control revenue bonds have been used in the past and may be used in the future in connection with the construction of pollution control facilities; however, Federal tax law has limited the utilization of this type of financing except for purposes of certain financing of solid waste disposal facilities and of certain refunding of outstanding pollution control revenue bonds issued before August 16, 1986.

New projects undertaken by AEP Resources and its subsidiaries are generally financed through equity funds provided by AEP, non-recourse debt incurred on a project-specific basis, debt issued by AEP Resources or through a combination thereof. See New Business Development and Item 7 for additional information concerning AEP Resources and its subsidiaries.

RATES AND REGULATION

General

The rates charged by the electric utility subsidiaries of AEP are approved by the FERC or one of the state utility commissions as applicable. The FERC regulates wholesale rates and the state commissions regulate retail rates. In recent years the number of rate increase applications filed by the operating subsidiaries of AEP with their respective state commissions and the FERC has decreased. Under current rate regulation, if increases in operating, construction and capital costs exceed increases in revenues resulting from previously granted rate increases and increased customer demand, then it may be appropriate for certain of AEP's electric utility subsidiaries to file rate increase applications in the future.

Generally the rates of AEP's operating subsidiaries are determined based upon the cost of providing service including a reasonable return on investment. Certain states served by the AEP System allow alternative forms of rate regulation in addition to the traditional cost-of-service approach. However, the rates of AEP's operating subsidiaries in those states continue to be cost-based. The IURC may approve alternative regulatory plans which could include setting customer rates based on market or average prices, price caps, index-based prices and prices based on performance and efficiency. The Virginia SCC may approve (i) special rates, contracts or incentives to individual customers or classes of customers and (ii) alternative forms of regulation including, but not limited to, the use of price regulation, ranges of authorized returns, categories of services and price indexing.

All of the seven states served by the AEP System, as well as the FERC, either permit the incorporation of fuel adjustment clauses in a utility company's rates and tariffs, which are designed to

permit upward or downward adjustments in revenues to reflect increases or decreases in fuel costs above or below the designated base cost of fuel set forth in the particular rate or tariff, or permit the inclusion of specified levels of fuel costs as part of such rate or tariff.

AEP cannot predict the timing or probability of approvals regarding applications for additional rate changes, the outcome of action by regulatory commissions or courts with respect to such matters, or the effect thereof on the earnings and business of the AEP System. In addition, current rate regulation may be subject to significant revision. See Competition and Business Change.

Investigations of June 1998 Pricing Abnormalities

During the week of June 22-26, 1998, wholesale electric power markets in the Midwest exhibited unprecedented price volatility due to several market factors, including an extended period of unseasonably hot weather, scheduled and unplanned generating unit outages, transmission constraints, and defaults by certain power marketers on their supply obligations. The simultaneous culmination of these events resulted in temporary but extreme price spikes in the hourly and daily markets.

As a result of this situation, the FERC, IURC and PUCO initiated separate investigations into the price increase. After completing their reviews, these commissions concluded that the pricing abnormalities were due to the unusual conditions that occurred during that time. The FERC Staff report issued in September 1998 did not find evidence that firm service to consumers was compromised anywhere in the Midwest during the period of the pricing abnormalities. The FERC reserved the right to conduct further investigations on a company-specific basis. AEP is unable to predict what, if any, further action may be taken by the FERC in respect of this matter. No assurance can be given that the FERC will not take enforcement action in this connection.

APCo

FERC: On February 14, 1992, APCo filed with the FERC applications for an increase in its wholesale rates to Kingsport Power Company and non-affiliated customers in the amounts of approximately $3,933,000 and $4,759,000, respectively. APCo began collecting the rate increases, subject to refund, on September 15, 1992. In addition, the Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106), which requires employers, beginning in 1993, to accrue for the costs of retiree benefits other than pensions. These rates include the higher level of SFAS 106 costs.

On November 9, 1993, the administrative law judge (ALJ) issued an initial decision affirming the terms of APCo's filing except for APCo's requested return on common equity of 12.75% which the ALJ found should be 10.1%. On June 29, 1998, the FERC issued its order affirming the ALJ's decision except the return on common equity, which the FERC approved at 9.95%. On July 29, 1998, APCo filed with the FERC a request for rehearing of the FERC's order.

At December 31, 1998, APCo had accrued a refund liability, including interest, of $42,800,000.

Virginia: In June 1997, APCo filed an application with the Virginia SCC for approval of an alternative regulatory plan (Plan) and proposed, among other things, an increase of $30,500,000 in base rates on an annual basis to be effective July 13, 1997. On July 10, 1997, the Virginia SCC issued an order suspending implementation of the proposed rates until November 11, 1997 when these rates were placed into effect subject to refund.

On February 18, 1999, the Virginia SCC approved a stipulation and settlement agreement among APCo, the Virginia SCC Staff and consumer and major industrial customer representatives that provides for the following:

o Elimination of the $30,500,000 annual increase in base rates that has been collected subject to refund since mid-November 1997.

o During the period January 1, 1998 through December 31, 2000:

o Reduction in base rates of $6,000,000 from the level in effect prior to the November 1997 increase, with the expectation that rates would remain at the agreed-upon levels.

o APCo's commitment to invest at least $90,000,000 in Virginia distribution facilities to maintain the overall quality and reliability of electric service.

o Benchmark rate of return on equity of 10.85% with one-third of earnings above that level to be retained by APCo and the remaining two-thirds to be refunded to ratepayers.

o Refund with interest of all amounts collected above the approved rates.

At December 31, 1998, APCo had accrued a refund liability, including interest, of $51,600,000.

West Virginia: On December 27, 1996, the West Virginia PSC approved a settlement agreement among APCo and other parties. In accordance with that agreement, the West Virginia PSC reduced APCo's base rates and Expanded Net Energy Cost (ENEC) rates by $5,000,000 and $28,000,000, respectively, on a one-time annual basis, effective November 1, 1996. Under the terms of the agreement, APCo's rates would not increase prior to January 1, 2000 and, through this date, ENEC cost variances will be subject to deferred accounting and a cumulative ENEC recovery balance will be maintained. Regardless of the actual cumulative ENEC recovery balance at December 31, 1999, ratepayers will not be responsible for any cumulative underrecovery and any cumulative overrecoveries will be treated in a manner to be determined by the West Virginia PSC, except that ENEC overrecoveries during each calendar year through December 31, 1999, in excess of $10,000,000 per period, will be accumulated and shared equally between APCo and its ratepayers.

CSPCo

Zimmer Plant: The Zimmer Plant was placed in commercial operation as a 1,300-megawatt coal-fired plant on March 30, 1991. CSPCo owns 25.4% of the Zimmer Plant with the remainder owned by two unaffiliated companies, CG&E (46.5%) and DP&L (28.1%).

From the in-service date of March 1991 until rates went into effect in May 1992, deferred carrying charges of $43,000,000 were recorded on the Zimmer Plant investment. Recovery of the deferred carrying charges will be sought in the next PUCO base rate proceeding in accordance with the PUCO accounting order that authorized the deferral.

I&M

Reference is made to Cook Nuclear Plant --Cook Plant Shutdown under 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.

Based on the estimated future cost of coal burned at Gavin Plant, management believes that the Ohio jurisdictional portion of the investment in, and liabilities and closing costs of, the affiliated mining operations, including deferred amounts, will be recovered under the terms of the predetermined price agreement following shutdown. Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of any remaining investment in, and the liabilities and closing costs of, OPCo's Muskingum, Windsor and Meigs mines, but there can be no assurance that such recovery will be approved. The non-Ohio jurisdictional portion of shutdown costs for these mines, which includes the investment in the mines, leased asset buy-outs, reclamation costs and employee benefits, is estimated to be approximately $17,000,000 for Muskingum, $14,000,000 for Windsor and $68,000,000 for Meigs, after tax at December 31, 1998.

Management anticipates closing the Muskingum mine in October 1999, Windsor mine in December 2000 and Meigs mine in December 2001. The Muskingum mine supplies coal to Muskingum River Plant and the Windsor mine supplies coal to Cardinal Plant Unit 1. 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). The mines could close earlier depending on the economics of continued operation under the terms of the 1995 settlement agreement. 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.

                           1994   1995   1996    1997   1998
                           ----   ----   ----    ----   ----
Coal.....................   91%    88%    87%     92%    99%
Nuclear..................    8%    11%    12%      7%     0%
Hydroelectric and other..    1%     1%     1%      1%     1%

Variations in the generation of nuclear power are primarily related to refueling outages and, in 1997 and 1998, 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 closure of existing coal mines and divestiture or acquisition of coal properties in light of Federal and state environmental and mining laws and regulations which may affect the System's need for or ability to mine such coal.

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 3,593 coal hopper cars to be used in unit train movements, as well as 14 towboats, 352 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:

                                                                      1994        1995        1996       1997       1998
                                                                      ----        ----        ----       ----       ----
Total coal delivered to
   AEP operated plants (thousands of tons).......................   49,024      46,867     51,030      54,292     54,004
Sources (percentage):
   Subsidiaries..................................................      15%         14%        13%         14%        14%
   Long-term contracts...........................................      65%         75%        71%         66%        66%
   Spot or short-term purchases..................................      20%         11%        16%         20%        20%
Average price per ton of spot-purchased coal.....................   $23.00      $25.15     $23.85      $24.38     $25.05

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:

                                                                    1994          1995       1996         1997       1998
                                                                    ----          ----       ----         ----       ----
                                                                                         DOLLARS PER TON
                                                                                         ---------------
AEP System Companies...........................................    $ 33.95      $ 32.52     $ 31.70      $ 31.77    $ 32.60
   AEGCo.......................................................      18.59        18.80       18.22        19.30      19.37
   APCo........................................................      39.89        38.86       37.60        36.09      34.81
   CSPCo.......................................................      32.80        33.23       31.70        31.69      31.63
   I&M.........................................................      22.85        23.25       22.99        23.68      22.61
   KEPCo.......................................................      26.83        26.91       27.25        26.76      27.42
   OPCo........................................................      41.10        37.58       35.96        36.00      38.94

                                                                                     CENTS PER MILLION BTU'S
                                                                                     -----------------------
AEP System Companies...........................................     152.41       145.26      140.48       140.23     143.51
   AEGCo.......................................................     112.06       112.87      109.25       115.21     112.63
   APCo........................................................     161.37       156.96      152.54       146.54     141.76
   CSPCo.......................................................     140.45       140.79      134.60       134.44     134.15
   I&M.........................................................     123.62       125.50      121.16       123.36     118.02
   KEPCo.......................................................     113.40       114.77      114.42       110.37     112.15

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, 1998, the System's coal inventory was approximately 38 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 1998 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 1998 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.

                                                                                AVERAGE SULFUR CONTENT
                                                    ESTIMATED REQUIRE-             OF DELIVERED COAL
                           TOTAL CONSUMPTION       MENTS FOR REMAINDER       -----------------------------
                              DURING 1998            OF USEFUL LIVES                       POUNDS OF SO2
                        (IN THOUSANDS OF TONS)    (IN MILLIONS OF TONS)      BY WEIGHT   PER MILLION BTU'S
                        ----------------------    ---------------------      ---------   -----------------
AEGCo (a)..............           4,966                     253               0.3%            0.7
APCo...................          11,813                     454               0.8%            1.3
CSPCo..................           6,359(b)                  249(b)            2.8%            4.7
I&M (c)................           6,956                     293               0.8%            1.5
KEPCo..................           3,044                      94               1.2%            1.9
OPCo...................          20,648                     654               2.3%            3.9

(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 1998, 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 2,400,000 tons per year through 1999. 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 48,685,543 tons expires on December 31, 2014 and another contract with remaining deliveries of 37,785,000 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 1999. 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 190,000,000 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 101,000,000 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 24,000,000 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 Reprocessing or other 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 $118,000,000 at December 31, 1998. 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, 1998, 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.

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.

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 $29,000,000 in 1998, $28,000,000 in 1997, and $27,000,000 in 1995. At December 31, 1998, I&M had recognized a decommissioning liability of $446,000,000. 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.

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 $35,521,000, subject to inflation adjustments, and is payable in annual assessments over the next eight 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 joined with 22 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 currently being proposed at the state and federal levels 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 which 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 (SO2), measured in tons per year, on a system wide or aggregate basis. Emission reductions are required by virtue of the establishment of annual allowance allocations at levels substantially below historical emission levels for most utility units. There are two phases of SO2 control under the Acid Rain Program. Phase I, effective January 1, 1995, requires SO2 emission reductions from certain units that emitted SO2 above a rate of 2.5 pounds per million Btu heat input in 1985. Phase I unit allowance allocations were calculated based on 1985 utilization rates and an emission rate of 2.5 pounds of SO2 per million Btu heat input. Phase I permits have been issued for all Phase I affected units in the AEP System.

Phase II, which affects all fossil fuel-fired steam generating units with capacity greater than 25 megawatts imposes more stringent SO2 emission control requirements beginning January 1, 2000. If a unit emitted SO2 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. If actual SO2 emissions for a Phase II affected unit in 1985 were less than 1.2 pounds per million Btu, the allowance allocation is, in most instances, based on the actual 1985 emission rate.

In addition to regulating SO2 emissions, Title IV of the CAAA contains provisions regulating emissions of nitrogen oxides (NOx). In April 1995, Federal EPA promulgated NOx emission limitations for tangentially fired boilers and dry bottom wall-fired boilers for Phase I and Phase II units. In addition, on December 19, 1996, Federal EPA published final NOx emission limitations for wet bottom wall-fired boilers, cyclone boilers, units applying cell burner technology and all other types of boilers. The regulations also revised downward the NOx limitations applicable to tangentially fired and wall-fired boilers in Phase II. These emission limitations are to be achieved by January 1, 2000.

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 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 (PM2.5). Both of these new standards have the potential to affect adversely the operation of AEP System generating units. Substantial reductions in NOx emissions from fossil fuel-fired power plants may be required as part of a state's plan to attain the eight-hour ozone standard. The actual implementation of the new PM2.5 NAAQS has been delayed for five years. Substantial reductions in SO2 and/or other emissions from fossil fuel-fired power plants may be required as part of a state's plan to attain the PM2.5 NAAQS. In August and September 1997 the AEP System operating companies joined with certain other utilities to appeal the revised NAAQS by filing petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit. Oral argument was held in December 1998.

In September 1998, Federal EPA issued revisions to the New Source Performance Standards applicable to new and modified fossil fuel-fired power plants. Federal EPA characterized its proposal as "fuel neutral" since it would impose the same stringent NOx emission limit (1.35lb. per megawatt-hour net energy output) for coal-fired boilers as for gas-fired boilers. The emission limit is set at a level which cannot currently be achieved by combustion controls and 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. Imposition of this standard to existing sources which might become subject to the rule based on an administrative finding that an existing source had been modified or reconstructed could result in substantial capital and operating expenditures. On October 30, 1998, the AEP System operating companies joined with certain other utilities to appeal the revised regulations by filing petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit.

NOx SIP Call: On October 27, 1998, Federal EPA published in the Federal Register a final rule (NOx transport SIP call) concluding that certain State Implementation Plans are deficient because they allow NOx emissions that contribute excessively to ozone nonattainment 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 by the year 2003. The NOx budgets apply to 22 eastern states and are premised mainly on the assumption of controlling power plant NOx emissions to 0.15 lb. per million Btu (approximately 85% below 1990 levels). The NOx transport SIP call purports to implement both the new eight-hour ozone standard and the one-hour ozone standard. The SIP call was accompanied by a proposed Federal Implementation Plan which could be implemented in any state which 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 to appeal the final NOx SIP Call rule by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit.

Preliminary estimates indicate that compliance costs could result in required capital expenditures as follows:

(IN MILLIONS)

                                       -------------
AEP System..........................      $1,200
   APCo.............................         325
   CSPCo............................         140
   I&M..............................         169
   KEPCo............................         105
   OPCo.............................         452

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, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.

Section 126 Petitions: In August 1997, eight northeastern states (New York, New Hampshire, Maine, Massachusetts, Rhode Island, Pennsylvania, Connecticut, and Vermont) filed petitions with Federal EPA under Section 126 of the Clean Air Act, 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 October 21, 1998, Federal EPA published in the Federal Register proposed conditional remedial action requiring NOx emission reductions from named utility sources.

Federal EPA is seeking comment on the effect on the Section 126 petitions of a proposed determination by Federal EPA that the one-hour ozone standard no longer applies to non-attainment areas in Maine, New Hampshire, Rhode Island and a portion of Massachusetts. In a separate Notice of Proposed Rulemaking, Federal EPA is seeking comment with respect to its proposed determination

that eight-hour ozone non-attainment in New Hampshire and Maine is being significantly affected by sources of NOx emissions in the northeastern U.S. as well as certain sources in the midwestern and southern U.S.

In December 1997 Federal EPA entered into a Memorandum of Agreement (MOA) with the petitioning states that establishes a schedule for taking final action on the Section 126 petitions on approximately the same time frame as Federal EPA's final action on the NOx transport SIP call. The MOA called for a proposed rulemaking on the Section 126 petitions by September 30, 1998 and a technical determination by April 30, 1999. Final action would be deferred pending satisfaction of the NOx SIP call requirements. In October 1998, the U.S. District Court for the Southern District of New York entered an order directing Federal EPA to conform to the schedule set forth in the MOA.

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. It is possible that this assessment of water body deposition may result in additional regulation of electric utility steam generating units.

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 increasing the range of civil and criminal penalties for violations of the CAA and enhancing administrative civil provisions, adding a citizen suit provision and imposing a national operating permit system, emission fee program and enhanced monitoring, recordkeeping and reporting requirements for existing and new sources. On February 13, 1997, Federal EPA issued the Credible Evidence rule, which allows Federal EPA to use any credible evidence or information in lieu of, or in addition to, the test methods prescribed by the regulation for determining compliance with emission limits. This rule has the potential to expand significantly Federal EPA's ability to bring enforcement actions and to increase the stringency of the emission limits to which AEP System plants are subject. In March 1997, a number of industries, including AEP System operating companies, filed petitions for review of the Credible Evidence Rule with the U.S. Court of Appeals for the District of Columbia Circuit. In August 1998, the court held that the appeal was not ripe for review. A petition for writ of certiori was filed with the U.S. Supreme Court.

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 (CO2), 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 CO2 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 December 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 CO2 emissions if compliance costs cannot be fully recovered from customers. In addition, any such severe program to reduce CO2 emissions could impose substantial costs on industry and society and erode the economic base that AEP's operations serve.

West Virginia SO2 Limits: West Virginia promulgated SO2 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 SO2 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.

West Virginia has had a request to increase the SO2 emission limitation for Kammer pending before Federal EPA for many years, although the change has not been acted upon by Federal EPA. On August 4, 1994, however, Federal EPA issued a Notice of Violation to OPCo alleging that Kammer Plant was operating in violation of the applicable federally enforceable SO2 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. The decree provides for compliance with an interim emission limit of 6.5 pounds of SO2 per million Btu actual heat input on a three-hour basis and 5.8 pounds of SO2 per million Btu on an annual basis. West Virginia and industrial sources in the area of the Kammer Plant are developing a revision to the State Implementation Plan with respect to SO2 emission limitations which is to be submitted no later than October 1, 1999. The interim emission limit for Kammer will remain in effect until after that time.

Short Term SO2 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 SO2 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 SO2 levels. The effects of this proposed intervention program on AEP operations cannot be predicted at this time.

Regional Haze: On July 31, 1997, Federal EPA proposed new 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. The finalization of Federal EPA's proposed rule to control regional haze 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 SO2 and NOx). The actual impact of the regional haze regulations cannot be determined at this time.

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.

On February 4, 1999, Federal EPA (Regions III and V) issued a request under Section 114 of the Clean Air Act seeking documents and information regarding capital and maintenance expenditures at AEP's Muskingum River, Gavin, Cardinal, Sporn and Mitchell plants. Federal EPA conducted a review of the accounting records of AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo in the summer of 1998 and made site visits to Sporn, Muskingum River and Mitchell plants in the summer and fall of 1998. These activities are focused on assessing compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act.

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 Plants are operating with NPDES permits. Under 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 which expire in 1999.

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.

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 which 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.

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 law 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. AEP System companies are presently defendants in three cases involving cost-recovery lawsuits at Federal EPA-identified CERCLA sites. OPCo is involved at two of these sites and I&M at the other site. AEP System companies are identified as Potentially Responsible Parties (PRPs) for three additional federal sites, including CSPCo at one site and I&M at two sites. Management's present estimates do not anticipate material cleanup 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 cleanup, future results of operations and possibly financial condition would 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 in surface impoundments or landfills in accordance with state permits or authorization or beneficially utilized. As required by RCRA, 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 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, Federal EPA will gather additional information and make a regulatory determination by April 1999. Until that time, these low volume wastes are

provisionally excluded from regulation under the hazardous waste provisions of RCRA. 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 which 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.

Federal EPA's technical requirements for underground storage tanks containing petroleum will require retrofitting or replacement of an appreciable number of tanks. Compliance costs for tank replacement and site remediation have not been significant to date.

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. In 1996, the National Academy of Sciences (NAS) released a report, based on a review of over 500 studies spanning 17 years of research, which contained the following summary statement: "... the conclusion of the committee is that the current body of evidence does not show that exposure to these fields presents a human health hazard..."

In 1997, the results of a five-year study by the National Cancer Institute (NCI) were released. The NCI researchers found no evidence that EMF in the home increases the risk of childhood cancer.

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. The National Institute of Environmental Health Sciences will provide a report to Congress this year, summarizing the results of this program. AEP contributed over $400,000 to this program. AEP has also supported an extensive EMF research program coordinated by the Electric Power Research Institute, working closely with its staff and contributing more than $500,000 to this effort in 1998. 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. 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 $15,400,000 for 1998, $15,300,000 for 1997 and $9,900,000 for 1996.

Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $24,100,000 for the year ended December 31, 1998, $23,600,000 for the year ended December 31, 1997 and $16,400,000 for the year ended December 31, 1996. This includes expenditures of $3,300,000 for 1998, $4,600,000 for 1997 and $3,300,000 for 1996 related to pressurized fluidized-bed combustion, a process in which sulfur is removed during coal combustion and nitrogen oxide formation is minimized.