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 electric utility and 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 in the U.S. and 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, 1996, the subsidiaries of AEP had a total of 17,951 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are:

APCo (organized in Virginia in 1926) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 867,000 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, 1996, APCo and its wholly owned subsidiaries had 3,900 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 Power Company 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, purchase, transmission and distribution of electric power to approximately 609,000 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, 1996, CSPCo had 1,837 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, purchase, transmission and distribution of electric power to approximately 542,000 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, 1996, I&M had 3,393 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, purchase, transmission and distribution of electric power to approximately 167,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 1996, KEPCo had 718 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 43,000 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, 1996, Kingsport Power Company had 87 employees.

OPCo (organized in Ohio in 1907 and reincorporated in 1924) is engaged in the generation, purchase, transmission and distribution of electric power to approximately 673,000 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, 1996, OPCo and its wholly owned subsidiaries had 4,418 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 41,000 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, 1996, Wheeling Power Company had 96 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. In January and February 1997, legislation was introduced in Congress 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. 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 .  $   --    $  231,504  $  325,351  $  232,212  $ 41,602  $  280,640  $1,132,140
 With Electric Heating. . .      --       340,796     115,339     111,556    64,839     155,081     826,411
                             --------  ----------  ----------  ----------  --------  ----------  ----------
  Total Residential . . . .      --       572,300     440,690     343,768   106,441     435,721   1,958,551
 Commercial . . . . . . . .      --       284,765     383,621     253,750    58,417     265,886   1,284,670
 Industrial . . . . . . . .      --       368,421     147,543     312,777    92,322     635,404   1,618,843
 Miscellaneous. . . . . . .      --        32,035      16,043       6,445       846       8,065      66,930
                             --------  ----------  ----------  ----------  --------  ----------  ----------
  Total Retail. . . . . . .      --     1,257,521     987,897     916,740   258,026   1,345,076   4,928,994
Wholesale (sales for resale)  225,767     332,800      93,496     391,478    57,141     526,702     792,592
                             --------  ----------  ----------  ----------  --------  ----------  ----------
  Total from KWH Sales. . .   225,767   1,590,321   1,081,393   1,308,218   315,167   1,871,778   5,721,586
Provision for Revenue Refunds    --        (7,581)      --          --         --         --         (7,581)
                             --------  ----------  ----------  ----------  --------  ----------  ----------
  Total Net of Provision for
    Revenue Refunds . . . .   225,767   1,582,740   1,081,393   1,308,218   315,167   1,871,778   5,714,005
Other Operating Revenues. .       125      42,129      24,290      20,275     8,154      39,930     135,229
                             --------  ----------  ----------  ----------  --------  ----------  ----------
  Total Electric Operating
     Revenues                $225,892  $1,624,869  $1,105,683  $1,328,493  $323,321  $1,911,708  $5,849,234
- ----------------------       ========  ==========  ==========  ==========  ========  ==========  ==========

(a) Includes revenues of other subsidiaries not shown and reflects 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. 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.

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, 1994, 1995 and 1996:

                          1994         1995        1996(a)
                       ----------   ----------   ----------
                                 (in thousands)

APCo . . . . . . . . . $(254,000)   $(252,000)   $(258,000)
CSPCo. . . . . . . . .  (105,000)    (143,000)    (145,000)
I&M. . . . . . . . . .   107,000      118,000      121,000
KEPCo. . . . . . . . .    12,000       23,000        2,000
OPCo . . . . . . . . .   240,000      254,000      280,000
- ----------------

(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 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, 1994, 1995 and 1996:

                         1994(a)     1995(a)      1996(a)
                         -------     -------      -------
                                 (in thousands)

AEGCo(b) . . . . . . .  $ 30,800    $ 29,200     $ 26,300
APCo(c). . . . . . . .    25,000      24,100       36,800
CSPCo(c) . . . . . . .    11,700      12,000       18,100
I&M(c)(d). . . . . . .    34,600      34,700       43,000
KEPCo(c) . . . . . . .     4,800       5,000        7,600
OPCo(c). . . . . . . .    20,000      20,200       30,200
                         -------     -------      -------
     Total System. . .  $126,900    $125,200     $162,000
                         =======     =======      =======
- ----------------

(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 1994, 1995 and 1996 were made on a short-term basis, except that $21,800,000, $22,500,000 and $33,300,000, 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 1994, 1995 and 1996 amounts for I&M include $21,600,000, $21,000,000 and $20,900,000 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) 100 megawatts of electric power through 1997; (2) 205 megawatts of electric power through 2010; and (3) 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 1996 was 606, 105, 413, 18 and 136 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 1995, customers have given notices of termination, effective in 1998 and 1999, for 405, 63 and 131 megawatts for APCo, I&M and OPCo, respectively.

In June 1993, certain municipal customers of APCo, who have since given APCo notice to terminate their contracts in 1998, 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 are full-requirements contracts which preclude the customers from purchasing power from third parties. 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.

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. 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, 1994, 1995 and 1996:

                           1994       1995         1996
                        ---------   ---------    ---------
                                 (in thousands)

APCo . . . . . . . . .  $(10,200)   $ (5,400)    $ (6,500)
CSPCo. . . . . . . . .   (30,100)    (31,100)     (30,600)
I&M. . . . . . . . . .    50,300      46,700       46,300
KEPCo. . . . . . . . .     4,300       3,500        3,300
OPCo . . . . . . . . .   (14,300)    (13,700)     (12,500)

                           1994         1995        1996
                         --------     --------    --------
                                    (In thousands)
APCo . . . . . . . . . . $ 4,100      $ 6,000     $13,800
CSPCo. . . . . . . . . .   3,100        4,200       8,000
I&M. . . . . . . . . . .   6,700        4,800       7,700
KEPCo. . . . . . . . . .     800        1,200       2,800
OPCo . . . . . . . . . .  15,700       17,800      17,800
                         -------      -------     -------
Total System . . . . . . $30,400      $34,000     $50,100
                         =======      =======     =======

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 12, 1993, APCo, CSPCo, I&M, KEPCo and OPCo and two other AEP System companies filed a transmission tariff with the FERC under which these AEP System companies would provide limited transmission service to certain companies. The tariff covered the terms and conditions of the service, as well as the price which the companies pay for transmission services, regardless of the source of electric power generation. On September 3, 1993, the FERC issued an order accepting the transmission service tariff for filing, with the tariff becoming effective on September 7, 1993, subject to refund.

On April 24, 1996, the FERC issued orders 888 and 889. These orders, which resulted from the FERC's March 29, 1995 Notice of Proposed Rulemaking ("Mega-NOPR"), 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.

AEP is presently 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. 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 1,760,000 kilowatts. On October 1, 1997, it is scheduled to increase to approximately 1,900,000 kilowatts and to remain at about that level through the remaining term of the contract. The proceeds from the sale of power by OVEC, aggregating $312,000,000 in 1996, 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 1996. 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 27 of the rural electric cooperatives which operate in the State of Ohio at 301 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 18, 1994, was recorded at 1,146,933 kilowatts.

CERTAIN INDUSTRIAL CUSTOMERS

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 356,000 kilowatts for Ravenswood and 534,000 kilowatts for Ormet.

On October 3, 1996, the PUCO approved, with some exceptions, a contract pursuant to which OPCo will continue to provide electric service to Ravenswood for the period July 1, 1996 through July 31, 2003. On February 6, 1997, the PUCO approved an amendment to the contract addressing these exceptions and the amended contract is now in effect.

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, 1999, unless extended.

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 1996 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 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; 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. FERC has required utilities to sell transmission services separately from their other services. 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 stranded investment losses.

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 benefitted by attracting new industrial customers to their service territories.

The legislatures and/or the regulatory commissions in many states are considering "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 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 1997, S.B. 427 was introduced in the Indiana Senate. The bill proposed that all customers would have the unrestricted right to choose their generator of electricity by July 1, 2004. Under the bill, customers could choose their power supplier after October 1, 1999, by paying an access charge. Transmission and distribution services would continue to be regulated at the federal and state levels, respectively. The Indiana Senate Commerce Committee held hearings on S.B. 427, and on February 25, 1997, amended the bill to have a legislative committee study electric industry competition.

Michigan: In June 1995, the MPSC issued an order approving an experimental five-year retail wheeling program and ordered Consumers Energy Company and Detroit Edison Company, 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 commences when each utility needs new capacity. The experiment seeks, as its goal, to determine whether a retail wheeling program best serves the public interest in a manner that promotes retail competition in a non-discriminatory fashion. 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 Court of Appeals.

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. I&M, in response to a MPSC order promulgated pursuant to the Michigan Jobs Committee proposals, filed in June 1996 a proposed open access distribution tariff applicable to new or expanding electric loads. The MPSC has not yet taken action on I&M's filing. In December 1996, the MPSC staff issued a report on electric industry restructuring which recommends a phase-in program from 1997 through 2004 of direct access to electricity suppliers applicable to all customers. The MPSC is holding hearings on the staff report and has directed utilities to provide information on the implementation of the staff's recommendations.

Ohio: On April 15, 1994, the Ohio Energy Strategy Task Force released its final report. The report contained seven broad implementation strategies along with 53 specific initiatives to be undertaken by government and the private sector. One strategy recommended continuing to encourage competition in the electric utility industry in a manner which maximizes benefits and efficiencies for all customers. An initiative under this strategy recommends facilitating informal roundtable discussions on issues concerning competition in the electric utility industry and promoting increased competitive options for Ohio businesses that do not unduly harm the interests of utility company shareholders or ratepayers. The PUCO has begun such discussions. As a result, on February 15, 1996, the PUCO adopted guidelines for interruptible electric service, including a buy-through provision that will enable customers to avoid being interrupted during utility capacity deficiencies by having the utility purchase off-system replacement power for the customer. On February 28, 1997, CSPCo and OPCo implemented four new interruptible electric services in conformance with the PUCO guidelines.

Also stemming from the roundtable discussions, on December 24, 1996, the PUCO issued conjunctive electric service guidelines under which customers may be aggregated for cost-of-service, rate design, rate eligibility and billing purposes. The Ohio investor-owned electric utilities were ordered by the PUCO to file conjunctive electric service tariff applications conforming to the guidelines.

In February 1997, the Ohio General Assembly formed the Joint Committee on Electric Utility Deregulation to study and report to the General Assembly concerning deregulation of the electric utility industry in Ohio. The Joint Committee is scheduled to issue its report by October 1, 1997. In February 1997, H.B. 220 was introduced in the Ohio House of Representatives. The bill is essentially identical to H.B. 653 introduced in the last session. The bill proposes that all customers be permitted to select their electricity suppliers effective January 1, 1998. The bill eliminates price regulation of electricity generation functions in favor of market based prices. Service area rights for Ohio's electricity suppliers would be confined to distribution service. Transmission and distribution services would continue to be regulated at the federal and state levels, respectively. The bill would require Ohio's electric utilities to functionally unbundle their generation, transmission and distribution services. Electric utilities would be permitted to recover transition costs provided that such recovery does not cause prices to exceed those in effect on the effective date of the legislation.

Virginia: In September 1995, the Virginia SCC instituted a proceeding to review and consider policy regarding restructuring and the role of competition in the electric utility industry in Virginia. Pursuant to the Virginia SCC's order, its staff conducted an investigation into current issues in the electric utility industry and, in July 1996, filed a report of its observations and recommendations. Following the receipt of comments from interested parties, the Virginia SCC issued an order in November 1996 directing the three largest electric utility companies in the state, including APCo, to file various studies and information with the Virginia SCC by March 31, 1997. In addition, the November 1996 order directs the staff of the Virginia SCC to file reports on subjects pertinent to the ongoing investigation throughout 1997.

In February 1997, the Virginia legislature passed a resolution requiring the staff of the Virginia SCC to develop and provide to the joint subcommittee of the legislature studying restructuring of the electric utility industry, by November 1997, its draft of a working model of a restructured electric utility industry most appropriate for Virginia. Five working groups, consisting of representatives from the Virginia SCC staff and other interested parties, have been organized to develop various aspects of such a model.

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 establishment of competition in power supply markets, and the establishment of retail wheeling and intra-state open access of jurisdictional power distribution systems. Pursuant to the West Virginia PSC's order, various parties have filed comments and the West Virginia PSC has scheduled a hearing on these matters commencing May 1, 1997.

Certain Other States in the Vicinity of AEP's Service Territory: In March 1996, the Illinois Commerce Commission approved, and two Illinois-based electric utilities implemented, retail wheeling pilot programs whereby certain classes of customers are eligible to choose their electricity providers. In addition, several bills have been introduced in the Illinois legislature that would provide for retail competition among electric energy suppliers.

In May 1996, the New York Public Service Commission issued an Opinion and Order Regarding Competitive Opportunities for Electric Service. The Opinion and Order required each of the seven major electric utilities in New York to file a rate/restructuring plan with the New York Public Service Commission in which the utilities were to classify transmission and distribution facilities and address the formation of an independent system operator for their transmission systems. The Opinion and Order called for the establishment of a competitive wholesale power market by early 1997 and the introduction of retail customer choice early in 1998.

In late 1996, Pennsylvania enacted the Electricity Generation Customer Choice and Competition Act. The Act requires Pennsylvania's electric utilities to unbundle their rates and services and to provide open access over their transmission and distribution systems to allow competitive suppliers to generate and sell electricity directly to consumers in Pennsylvania. The Act provides for phased implementation of retail access, with 33% of the peak load having direct access by January 1, 1999, 66% of the peak load having direct access by January 1, 2000, and all customers having direct access by January 1, 2001. Transmission and distribution of electricity will continue to be regulated as a monopoly subject to the jurisdiction of the Pennsylvania Public Utility Commission.

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.

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 continues to consider new business opportunities, particularly those which allow use of its expertise. These endeavors began in 1982 and are conducted through AEP Resources, Inc. (Resources), AEP Resources International, Limited (AEPRI), AEP Resources Engineering & Services Company (formerly AEP Energy Services, Inc.) (AEPRES) and AEP Energy Services, Inc. (formerly AEP Energy Solutions, Inc.) (AEPES).

Resources' and AEPRI's primary business is development of, and investment in, exempt wholesale generators, foreign utility companies, qualifying cogeneration facilities and other power projects.

On February 24, 1997, AEP and Public Service Company of Colorado (PSCo) jointly agreed with the Board of Directors of Yorkshire Electricity Group plc (Yorkshire Electricity) in the United Kingdom to make a cash tender offer (the Tender Offer) for Yorkshire Electricity. The Tender Offer values Yorkshire Electricity at U.S. $2.4 billion. The Tender Offer will be effected by Yorkshire Holdings plc, a holding company owned by Yorkshire Power Group Limited, which is equally owned and controlled by Resources and New Century International Inc. (NCII), a wholly-owned subsidiary of PSCo. Resources and NCII will each contribute U.S. $360 million toward the Tender Offer with the remaining U.S. $1.7 billion funded through a non-recourse loan to Yorkshire Power Group Limited. Yorkshire Electricity is an English inde- pendent regional electricity company. It is principally engaged in the distribution of electricity to 2.1 million customers in its authorized service territory comprised of 4,180 square miles in northeast England.

AEPRI's 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 Municipal Finance Development Co. (15% interest). Funding for the construction of the generating units has commenced and will continue through completion which is expected to occur by 1999. AEPRI's share of the total cost of the project of $172 million is estimated to be approximately $120 million.

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

AEP has received approval from the SEC under PUHCA to finance up to 50%, and is seeking approval to finance up to 100%, of its consolidated retained earnings (approximately $1,500,000,000), for investment in exempt wholesale generators and foreign utility companies. Resources expects to investigate opportunities to develop and invest in new, and invest in existing, generation projects worldwide.

In September 1996, the SEC authorized AEP to invest up to $100,000,000 in subsidiaries engaged in the business of marketing energy commodities, including electricity and gas. The SEC also adopted Rule 58, effective March 24, 1997, which permits AEP and other registered holding companies to invest up to 15% of consolidated capitalization in energy-related companies. In September 1996, AEP formed AEPES to market natural gas and consider marketing electric power at retail where permitted by state law.

In July 1996, AEP Power Marketing, Inc. (AEP Marketing), a wholly-owned subsidiary of AEP, requested authority from FERC to market electric power at wholesale at market-based rates. In September, the FERC accepted the filing, conditioned upon, among other things, that the utility subsidiaries of AEP not
(1) sell nonpower goods or services to any affiliate at a price below its cost or market price, whichever is higher and (2) purchase nonpower goods or services from any affiliate at a price above market price. AEP Marketing filed a request that FERC clarify that this condition only apply to transactions between utility subsidiaries and AEP Marketing. AEP Marketing is inactive pending FERC's decision.

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

CONSTRUCTION PROGRAM OF OPERATING COMPANIES

New Generation

The AEP System companies are continuously involved in an assessment of the adequacy of its generation, transmission, distribution and other facilities necessary to 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 accordingly, 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 generation resources through the year 2000 include: a purchase from an independent power producer's hydro project with an expected capacity value of 28 megawatts, reratings of several existing AEP System generating units, and the termination of the Rockport Unit 1 sale of 455 megawatts to VEPCo on December 31, 1999 (see AEGCo). Beyond these changes, 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 until about the year 2002, at the very earliest. When the time for commitment to specific capacity additions approaches, all means for adding such capacity, including self-build and external resource options, will be considered. However, given the restructuring that is expected to take place in the industry, the need of AEP's operating companies for any additional generation resources in the foreseeable future is highly uncertain.

Proposed Transmission Facilities

APCo: On March 23, 1990, APCo and VEPCo announced plans, subject to regulatory approval, for major new transmission facilities. APCo will construct approximately 115 miles of 765,000-volt line from APCo's Wyoming station in southern West Virginia to APCo's Cloverdale station near Roanoke, Virginia. VEPCo will construct approximately 102 miles of 500,000-volt line from APCo's Joshua Falls station east of Lynchburg, Virginia to VEPCo's Ladysmith station north of Richmond, Virginia. The construction of the transmission lines and related station improvements will provide needed reinforcement for APCo's internal load, reinforce the ability to exchange electric power between the two companies and relieve present constraints on the transmission of electric power from potential independent power producers in the APCo service area to VEPCo. APCo's cost is estimated at $245,000,000 while VEPCo's cost is estimated at $164,000,000. Management estimates that the project cannot be completed before December 2002, but the actual service date will be dependent upon the time necessary to meet various regulatory requirements.

The U.S. Forest Service (Forest Service) is directing the preparation of an Environmental Impact Statement (EIS) which will be required prior to the granting of special use permits for crossing Federal lands. On June 18, 1996, the Forest Service released a Draft EIS. The Forest Service preliminarily identified a "No Action Alternative" as its preferred alternative. If this alternative is incorporated in the Final EIS, APCo would not be authorized to cross the Federally-administered lands of the Forest Service with the proposed transmission line.

Hearings before the Virginia SCC were concluded in September 1993. A report was issued by the hearing examiner in December 1993 which recommended that the Virginia SCC grant APCo approval to construct the proposed 765,000-volt line. In an interim order issued on December 13, 1995, the Virginia SCC found that major additional transmission capacity was needed to serve APCo's native load customers. The Virginia SCC further asked that APCo provide additional information on possible routing modifications and utilization of the additional transmission capacity prior to a final ruling.

On July 25, 1996, the Virginia SCC issued an order extending indefinitely the date for filing comments and suspending its proceeding on the transmission line due to the findings of the Draft EIS. However, the Virginia SCC ordered APCo to file, on or before December 1, 1996, a proposal detailing its intentions with regard to meeting the need for major additional transmission capacity identified in the Virginia SCC's interim order of December 13, 1995. In APCo's December 1996 filing with the Virginia SCC, APCo reviewed the need for the project, taking into account the additional transmission improvements completed after August 1991, and improvements projected to be in service prior to completion of the proposed project. As part of the review, APCo also considered the implications of electric utility industry restructuring. Based on the review and after considering all possible alternatives, APCo concluded that the need for reinforcement of the transmission system serving its central and eastern areas remains compelling and that the proposed Wyoming-Cloverdale project is the most proper alternative for addressing that need. APCo intends to file an amended application in Virginia.

APCo refiled with the West Virginia PSC in February 1993 its application for certification. An application filed in June 1992 was withdrawn at the request of the West Virginia PSC to permit additional time for review by the West Virginia PSC. The West Virginia PSC rejected APCo's application for certification in May 1993, directing APCo to supplement its line siting information. APCo intends to refile its application with the West Virginia PSC.

Given the findings set forth in the Draft EIS and the preliminary position of the Forest Service, APCo cannot presently predict the schedule for completion of the state and Federal permitting process.

APCo and KEPCo: APCo and KEPCo have announced an improvement plan to be implemented during a four-year period (1996-1999) to reinforce their 138,000-volt transmission system. Included in this plan is a new transmission line to link KEPCo's Big Sandy Plant to communities in eastern Kentucky. APCo's and KEPCo's estimated project costs are $5,115,000 and $84,184,000, respectively. The KPSC approved the project in its order dated June 11, 1996. Construction commenced in late 1996.

                         1994      1995      1996      1997
                        Actual    Actual    Actual   Estimate
                       --------  --------  --------  --------
                                   (in thousands)
AEGCo. . . . . . . . . $  3,900  $  4,000  $  2,200  $  4,000
APCo . . . . . . . . .  230,300   217,600   192,900   205,000
CSPCo. . . . . . . . .   81,500    99,500    93,600   124,000
I&M. . . . . . . . . .  114,500   113,000    90,500   106,000
KEPCo. . . . . . . . .   53,200    39,300    75,800    72,000
OPCo (a) . . . . . . .  149,000   116,900   113,800   151,800
                       --------  --------  --------  --------
   AEP System (b). . . $642,100  $601,200  $578,000  $672,000
                       ========  ========  ========  ========

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 1994, 1995 and 1996 and the current estimate for 1997 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.

                         1994      1995      1996      1997
                        Actual    Actual    Actual   Estimate
                       --------  --------  --------  --------
                                   (in thousands)
AEGCo. . . . . . . . .  $     0   $     0   $     0  $     0
APCo . . . . . . . . .   32,000     7,800    10,500    6,800
CSPCo. . . . . . . . .   13,700    10,000     1,800    1,900
I&M. . . . . . . . . .        0         0         0      300
KEPCo. . . . . . . . .    9,500       600         0      800
OPCo (a) . . . . . . .   22,400     3,100     1,600    5,900
                        -------   -------   -------  -------
AEP System (a) . . . .  $77,600   $21,500   $13,900  $15,700
                        =======   =======   =======  =======

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 preferred stock, 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 1996, AEP issued 1,600,000 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 1994-1996, external funds from financings and capital contributions by AEP amounted, with respect to APCo and KEPCo to approximately 40% and 61%, 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, I&M 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, 1997, 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(b)   CSPCo   I&M(c)   KEPCo   OPCo(c)  System(a)
  ---------------        -----   -----   -------   -----   ------   -----   -------  ---------
                                                    (in millions)
Amount authorized ...... $150     $80     $227      $175    $175    $150     $223     $1,260
Amount outstanding:
   Notes payable ....... $ --     $10     $ --      $ 20    $  4    $ 34     $  4     $   92
   Commercial paper ....   42      --       61        32      40      18       37        228
                         ----     ---     ----      ----    ----    ----     ----     ------
                         $ 42     $10     $ 61      $ 52    $ 44    $ 52     $ 41     $  320
                         ====     ===     ====      ====    ====    ====     ====     ======

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 and preferred stock, it is necessary for APCo, CSPCo, I&M, KEPCo and OPCo to comply with earnings coverage requirements contained in their respective mortgages and charters. The most restrictive of these provisions in each instance generally requires
(1) 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 and (2) for the issuance of additional preferred stock by APCo, I&M and OPCo, a minimum, after income tax, gross income coverage of one and one-half times pro forma annual interest charges and preferred stock dividends, in each case 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 from time to time restricted the ability of one or more of the above subsidiaries of AEP to issue senior securities.

The respective mortgage and preferred stock coverages of APCo, CSPCo, I&M, KEPCo and OPCo under their respective mortgage and charter provisions, calculated on the foregoing basis and in accordance with the respective amounts then recorded in the accounts of the companies, assuming the respective short-term debt of the companies at those dates were to remain outstanding for a twelve-month period at the respective rates of interest prevailing at those dates, were at least those stated in the following table:

                                          December 31,
                                     --------------------
                                     1994    1995    1996
                                     ----    ----    ----
APCo
    Mortgage coverage . . . . . . .  3.12    3.47    3.98
    Preferred stock coverage  . . .  1.65    1.78    1.99
CSPCo
    Mortgage coverage . . . . . . .  3.64    3.90    4.44
I&M
    Mortgage coverage . . . . . . .  6.23    6.25    6.66
    Preferred stock coverage  . . .  2.74    2.63    3.07
KEPCo
    Mortgage coverage . . . . . . .  2.60    2.86    3.22
OPCo
    Mortgage coverage . . . . . . .  5.04    6.17    6.62
    Preferred stock coverage  . . .  2.58    3.04    3.63

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 and preferred stock 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 use of alternative financing arrangements, if available, which may be more costly or the curtailment of construction and other outlays.

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.

Shares of AEP Common Stock may be sold by AEP from time to time at prices below the then current book value per share and repurchased by AEP at prices above book value. Such sales or purchases, if any, would have a dilutive effect on the book value of then outstanding shares but are not expected to have a material adverse effect on AEP's business including its future financing plans or capabilities and pending construction projects.

RATES

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. 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. See Competition and Business Change.

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 issued an initial decision recommending, among other things, the higher level of post-retirement benefits other than pensions under SFAS 106. FERC action on APCo's applications is pending.

Virginia: On December 20, 1996, APCo filed an application with the Virginia SCC to increase its annual fuel factor revenues by approximately $17,000,000. On January 31, 1997, the Virginia SCC approved APCo's request, effective February 1, 1997.

West Virginia: Under the terms of a 1993 settlement agreement in the West Virginia jurisdiction, APCo agreed to a three-year base rate freeze and suspension of the West Virginia PSC Expanded Net Energy Cost (ENEC) recovery mechanism until October 31, 1996. 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 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%).

Zimmer Plant -- Rate Recovery: In May 1992, the PUCO issued an order providing for a phased-in rate increase of $123,000,000 for the Zimmer Plant to be implemented in three steps over a two-year period and disallowed $165,000,000 of Zimmer Plant investment. CSPCo appealed the PUCO ordered Zimmer disallowance and phase-in plan to the Ohio Supreme Court. In November 1993, the Supreme Court issued a decision on CSPCo's appeal affirming the disallowance and finding that the PUCO did not have statutory authority to order phased-in rates. The court instructed the PUCO to fix rates to provide gross annual revenues in accordance with the law and to provide a mechanism to recover the amounts deferred as regulatory assets under the phase-in order.

As a result of the Supreme Court decision, in January 1994 the PUCO approved a 7.11% or $57,167,000 rate increase effective February 1, 1994. The increase is comprised of a 3.72% base rate increase to complete the rate increase phase-in and a temporary 3.39% surcharge, which will be in effect until the phase-in plan deferrals are recovered, estimated to be June 1997. In 1996, 1995 and 1994, $31,500,000, $28,500,000 and $18,500,000, respectively, of net phase-in deferrals were collected through the surcharge. The deferral balance was $15,400,000 at December 31, 1996 and $46,900,000 at December 31, 1995. The recovery of amounts deferred under the phase-in plan and the increase in rates to the full rate level did affect net income since the deferred costs are amortized commensurate with their recovery.

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.

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 fixes the EFC factor at 1.465 cents per kwh for the period June 1995 through November 1998 (less Ohio jurisdictional emission allowance gains currently set at .043 cents per kwh which, commencing on December 1, 1996, are being returned to customers). After 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. Management intends to seek from non-Ohio jurisdictional ratepayers recovery of the non-Ohio jurisdictional portion of the investment in, and the liabilities and closing costs of, OPCo's Meigs, Muskingum and Windsor 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 $90,000,000 for Meigs, $55,000,000 for Muskingum and $35,000,000 for Windsor, after tax at December 31, 1996.

OPCo's Muskingum and Windsor mines may have to close by January 2000 as a result of compliance by the Muskingum River Plant and Cardinal Unit 1 with the Phase II requirements of the Clean Air Act Amendments of 1990 (see Environmental and Other Matters -- Air Pollution Control - Clean Air Act). The Muskingum and Windsor mines supply coal to Muskingum River Plant and Cardinal Plant, respectively. The Muskingum and/or Windsor mines could close prior to January 2000 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 Meigs, Muskingum and Windsor mines can be recovered, AEP's and OPCo's results of operations would be adversely affected.

In November 1992, the municipal wholesale customers of OPCo filed a complaint with the SEC requesting an investigation of the sale of the Martinka mining operation to an unaffiliated company and an investigation into the pricing of OPCo's affiliated coal purchases back to 1986. OPCo has filed a response with the SEC seeking to dismiss this complaint. These customers also sought to intervene in three proceedings before the SEC. In September 1996, the SEC denied two requests to intervene, but has not ruled on the complaint.

                              1992    1993    1994    1995    1996
                              ----    ----    ----    ----    ----
Coal . . . . . . . . . . . .   93%     86%     91%     88%     87%
Nuclear. . . . . . . . . . .    6%     13%      8%     11%     12%
Hydroelectric and other. . .    1%      1%      1%      1%      1%

Variations in the generation of nuclear power are primarily related to refueling outages and, in 1992, a forced outage at Cook Plant Unit 2. See Cook Nuclear Plant.

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 - Clean Air Act 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 a terminal on the Ohio River for transloading to barges for delivery to generating stations on the river. Subsidiaries of AEP lease approximately 3,464 coal hopper cars to be used in unit train movements, as well as 14 towboats, 295 jumbo barges and 184 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:

                                 1992    1993    1994    1995    1996
                                ------  ------  ------  ------  ------
Total coal delivered to
  AEP operated plants
  (thousands of tons) . . . . . 44,738  40,561  49,024  46,867  51,030
Sources (percentage):
  Subsidiaries. . . . . . . . .   25%     20%     15%     14%     13%
  Long-term contracts . . . . .   65%     66%     65%     75%     71%
  Spot or short-term
     purchases. . . . . . . . .   10%     14%     20%     11%     16%
Average price per ton of
  spot-purchased coal . . . . . $23.88  $23.55  $23.00  $25.15  $23.85

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:

                                 1992    1993    1994    1995    1996
                                ------  ------  ------  ------  ------
                                            Dollars per ton
AEP System Companies . . . . .  $34.31  $33.57  $33.95  $32.52  $31.70
AEGCo  . . . . . . . . . . . .   20.11   17.74   18.59   18.80   18.22
APCo . . . . . . . . . . . . .   43.00   42.65   39.89   38.86   37.60
CSPCo  . . . . . . . . . . . .   33.87   33.87   32.80   33.23   31.70
I&M  . . . . . . . . . . . . .   24.23   23.80   22.85   23.25   22.99
KEPCo. . . . . . . . . . . . .   30.24   27.08   26.83   26.91   27.25
OPCo . . . . . . . . . . . . .   38.36   38.12   41.10   37.58   35.96

                                        Cents per Million Btu's
AEP System Companies . . . . .  154.41  150.89  152.41  145.26  140.48
                                <cents> <cents> <cents> <cents> <cents>
AEGCo. . . . . . . . . . . . .  120.90  107.71  112.06  112.87  109.25
                                <cents> <cents> <cents> <cents> <cents>
APCo . . . . . . . . . . . . .  173.05  173.32  161.37  156.96  152.54
                                <cents> <cents> <cents> <cents> <cents>
CSPCo. . . . . . . . . . . . .  143.94  143.66  140.45  140.79  134.60
                                <cents> <cents> <cents> <cents> <cents>
I&M. . . . . . . . . . . . . .  135.11  129.39  123.62  125.50  121.16
                                <cents> <cents> <cents> <cents> <cents>
KEPCo. . . . . . . . . . . . .  126.92  113.90  113.40  114.77  114.42
                                <cents> <cents> <cents> <cents> <cents>
OPCo . . . . . . . . . . . . .  163.89  161.25  173.51  157.62  151.55
                                <cents> <cents> <cents> <cents> <cents>

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, 1996, the System's coal inventory was approximately 45 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 1996 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 1996 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 1996          of Useful Lives                  Pounds of SO2
             (In Thousands of Tons)  (In Millions of Tons)  By Weight  Per Million Btu's
             ----------------------  ---------------------  ---------  -----------------
AEGCo (a) . . . . .   5,091                   257              0.3%           0.8
APCo. . . . . . . .  10,743                   434              0.8%           1.3
CSPCo (b) . . . . .   5,859                   226              2.8%           4.8
I&M (c) . . . . . .   6,975                   296              0.8%           1.6
KEPCo . . . . . . .   2,425                    89              1.2%           1.9
OPCo  . . . . . . .  20,473                   658              2.3%           3.8

AEGCo: See Fuel Supply -- I&M for a discussion ofthe 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 1996, whereas the maximum sulfur content permitted, for emission standard purposes, for existing plants in the regions in which APCo's generating stations are located ranged between 0.78% and 2% by weight depending in some circumstances on the calorific value of the coal which can be obtained for some generating stations.

CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,500,000 tons per year through 1998. 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 55,335,543 tons expires on December 31, 2014 and another contract with remaining deliveries of 49,005,000 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 2,500,000 tons of coal in 1997. 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 which contain approximately 205,000,000 tons of clean recoverable coal, which ranges in sulfur content between 3.4% and 4.5% sulfur by weight (weighted average, 3.8%), which can be recovered based upon existing mining plans and projections and employing current mining practices and techniques. 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 2.6%). 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 105,000,000 tons of clean recoverable coal ranging in sulfur content between 1.4% and 3.3% sulfur by weight (weighted average, 2.0%) of which approximately 28,000,000 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 the mining and milling of uranium ore to uranium concentrates; the conversion of uranium concentrates to uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication of fuel assemblies; the utilization of nuclear fuel in the reactor; and the 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 to permit normal operations through 2010.

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 $71,124,000, exclusive of interest of $100,622,000 at December 31, 1996. 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, 1996, funds collected from customers to pay the pre-April 1983 fee and accrued interest approximated the long-term debt 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 in 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.

Studies completed in 1994 estimate decommissioning and low-level radioactive waste disposal costs for the Cook Plant to range from $634,000,000 to $988,000,000 in 1993 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 $27,000,000 in 1996, $30,000,000 in 1995 (including $4,000,000 in special deposits) and $26,000,000 in 1994. At December 31, 1996, I&M had recognized a decommissioning liability of $313,845,000. 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 (a) the type of decommissioning plan selected,
(b) the escalation of various cost elements (including, but not limited to, general inflation), (c) the further development of regulatory requirements governing decommissioning, (d) the limited availability to date of significant experience in decommissioning such facilities and (e) the technology available at the time of decommissioning differing significantly from that assumed in these studies. Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly greater than current projections.

In February 1996, the Financial Accounting Standards Board (FASB) issued an exposure draft entitled Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets. I&M generally records such liabilities over the life of its plant commensurate with rate recovery. The exposure draft proposes that the present value of decommissioning and certain other closure or removal obligations be recorded as a liability when the obligation is incurred. A corresponding asset would be recorded in the plant investment account and recovered through depreciation charges over the asset's life. A proposed transition rule would require that an entity report in income the cumulative effect of initially applying the new standard. However, as a cost-based rate-regulated entity, I&M would expect to record a corresponding regulatory asset for the cumulative effect of initially applying the new standard. The FASB is reconsidering several aspects of the exposure draft. It is unclear at this time what, if any, changes the FASB will make to the proposal. Until it becomes apparent what the FASB will decide and how certain questions raised by the exposure draft are resolved, I&M cannot determine its ultimate impact.

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. 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. The bill is expected to be reintroduced in 1997. 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. Currently, the Cook Plant produces less than 1,500 cubic feet of low-level waste annually.

Energy Policy Act -- Nuclear Fees

The Energy Policy Act of 1992 (Energy Act), contains a provision to fund the decommissioning and decontamination of DOE's existing uranium enrichment facilities from a combination of sources including assessments against electric utilities which purchased enrichment services from DOE facilities. I&M's remaining estimated liability is $42,743,000, subject to inflation adjustments, and is payable in annual assessments over the next 10 years. I&M recorded a regulatory asset concurrent with the recording of the liability. The payments are being recorded and recovered as fuel expense.

In a case involving an unaffiliated utility, the U.S. Court of Federal Claims decided in June 1995 that these assessments are unlawful. On November 13, 1995, the Federal Government appealed this decision to the U.S. Court of Appeals for the Federal Circuit. I&M has filed with DOE claims for refunds under certain of its enrichment services contracts based on this decision. I&M also intends to pursue refund claims on other enrichment services contracts directly to the U.S. Court of Federal Claims.

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.

It is expected that costs related to environmental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries and that, in the long term, 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

Clean Air Act: For the AEP System, compliance with the Clean Air Act (CAA) is requiring substantial expenditures which generally are being recovered through increases in the rates of AEP's operating subsidiaries. OPCo is incurring a major portion of such costs. There can be no assurance that all such costs will be recovered. See Construction Program of Operating Companies
- -- Construction Expenditures.

The Acid Rain Program (Title IV) provisions of the Clean Air Act Amendments of 1990 (CAAA) create an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of sulfur dioxide, 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 a level below historical emission levels for many utility units. Effective January 1, 1995, Title IV of the CAAA established Phase I sulfur dioxide allowance limitations (caps or ceilings on emissions) for certain units that emitted sulfur dioxide above a rate of 2.5 pounds per million Btu heat input in 1985, premised upon sulfur dioxide emissions at a rate of 2.5 pounds per million Btu heat input at 1985 utilization levels. The following AEP System units are Phase I-affected units: I&M's Tanners Creek Unit 4; CSPCo's Beckjord Unit 6, Conesville Units 1-4, Picway Unit 5 and Stuart Units 1-4; and OPCo's Gavin Units 1-2, Muskingum River Units 1-5, Cardinal Unit 1, Mitchell Units 1-2 and Kammer Units 1-3. Phase I permits have been issued for all Phase I-affected units in the AEP System.

All fossil fuel-fired steam generating units with capacity greater than 25 megawatts are affected in Phase II of the Acid Rain program. All Phase II-affected units are allocated allowances with which compliance must be accomplished beginning January 1, 2000. The basis for Phase II allowance allocation depends on 1985 sulfur dioxide emission rates -- if a unit emitted sulfur dioxide in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels. If a unit emitted sulfur dioxide in 1985 at a rate of less than 1.2 pounds, the allowance allocation is in most instances premised upon the actual 1985 emission rate.

Title IV also contains provisions governing nitrogen oxides (NOx) emissions. 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 in the Federal Register for wet bottom wall-fired boilers, cyclone boilers, units applying cell burner technology and all other types of boilers. These emission limitations are to be achieved by January 1, 2000. A petition for review of the regulations was filed by a number of utilities, including AEP System operating companies, in the U.S. Court of Appeals for the District of Columbia Circuit on December 26, 1996.

The CAA contains additional provisions, other than the Acid Rain Program, which could require reductions in emissions of nitrogen oxides from fossil fuel-fired power plants. Title I, dealing generally with attainment of federally set National Ambient Air Quality Standards, establishes a tiered system for classifying degrees of non-attainment with the air quality standard for ozone. Depending upon the severity of non-attainment within a given non-attainment area, reductions in nitrogen oxides emissions from fossil fuel-fired power plants may be required as part of a state's plan for achieving attainment with the ozone air quality standard. While ozone non-attainment is largely restricted to urban areas, AEP System generating units could be determined to be affecting ozone concentrations and may therefore, eventually be required to reduce nitrogen oxides emissions pursuant to Title I.

In addition, certain environmental organizations and states have taken the position that nitrogen oxides emissions from the midwest must be reduced in order to achieve the air quality standard for ozone in the northeast as well as the Lake Michigan and Atlanta, Georgia areas. All AEP coal-fired plants are potentially subject to the imposition of additional emission controls resulting from these initiatives. The Environmental Council of States formed the Ozone Transport Assessment Group (OTAG) in early 1995 to develop estimates of levels of reduction in volatile organic compound and/or nitrogen oxides emissions required for significant reductions in ozone concentrations in the eastern United States. OTAG, consisting of the environmental commissioners and air directors of 37 eastern states, Federal EPA and representatives from environmental and industry groups, is currently scheduled to complete modeling and technical work by the spring of 1997 with evaluation of technical findings and recommendations on regional emission controls to be submitted to Federal EPA in the summer of 1997. Federal EPA published a notice of intent in the January 10, 1997 Federal Register proposing the specification of ranges or amounts of nitrogen oxides and volatile organic compounds reductions required by states to reduce downwind concentrations of ozone. Federal EPA will direct states to revise their state implementation plans (SIPs) to provide for specified emission reductions within a set time period. Federal EPA's proposal for reductions of nitrogen oxides and volatile organic compounds is scheduled to be issued in March 1997 and final SIP calls requiring revisions in state plans will be issued in the summer of 1997. The cost of meeting Nox emissions reduction requirements which might be imposed to achieve the ozone ambient air quality standard cannot be precisely predicted but could be substantial.

Utility boilers are potentially subject to additional control requirements under Title III of the CAAA governing hazardous air pollutant emissions. Federal EPA is directed to conduct studies concerning the potential public health impacts of pollutants identified by the legislation as hazardous in connection with their emission from electric utility steam generating units. Federal EPA was required to report the results of this study to Congress by November 1993 and is required to regulate emissions of these pollutants from electric utility steam generating units if it is determined that such regulation is necessary and appropriate, based on the results of the study. In October 1996, Federal EPA submitted to Congress an interim report that did not make any determinations regarding additional regulation of electric utilities. Additionally, Federal EPA is directed to study the deposition of hazardous pollutants to 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 emissions from electric utility steam generating units may be regulated under this water body deposition assessment program.

The CAAA expand the enforcement authority of the Federal government by increasing the range of civil and criminal penalties for violations of the Clean Air Act and enhancing administrative civil provisions, adding a citizen suit provision and imposing a national operating permit system, emission fee program and enhanced monitoring, record keeping and reporting requirements for existing and new sources. On February 13, 1997, Federal EPA issued a regulation providing for the use of any credible evidence or information in lieu of, or in addition to, test methods prescribed by regulation to determine the compliance status of permitted sources of air pollution. This rule may effectively make emission limits previously adopted for many air emission sources including those of the AEP System's operating subsidiaries more stringent. On March 10, 1997, a group of utilities, including AEP System operating companies, filed a petition for review of these regulations in the U.S. Court of Appeals for the District of Columbia Circuit.

Global Climate Change: Increasing concentrations of "greenhouse gases," including carbon dioxide (CO2), in the atmosphere have led to concerns about the potential for the earth's climate to change in ways that could result in adverse human health effects, destruction of sensitive ecosystems, inundated low-lying areas caused by sea-level rise, shifts in agricultural production and other serious environmental consequences. The proponents of this view maintain that rising levels of greenhouse gas emissions will cause some of the sun's energy that is normally radiated back into space to be trapped in the atmosphere, warming the biosphere and triggering these detrimental effects.

At the Earth Summit in Rio de Janeiro, Brazil in June 1992, 165 nations, including the United States, signed a global climate change treaty. Each country that ratifies the treaty commits itself to a process of achieving the aim of reducing greenhouse gas emissions, including CO2, to their 1990 level by the year 2000. On October 7, 1992, the U.S. Senate ratified the treaty. The treaty went into effect on March 21, 1994. In April 1995, the first meeting of the nations that have ratified was held. The parties declared that the existing commitments under the treaty are not adequate to address the threat of global climate change and authorized the immediate commencement of negotiations on a protocol or other legal instrument for emission controls in the post-2000 period. The protocol or other legal instrument is required to set forth "policies and measures," and "quantified limitation and reduction objectives within specified time frames, such as 2005, 2010 and 2020" to be adopted by signatory nations. The parties will meet in December 1997 in Kyoto, Japan to finalize the agreement.

On January 17, 1997, the U.S. government submitted text for a proposed treaty that would establish a future system of legally binding emission budgets with trading of emission credits between nations that are parties to the new agreement and which have emission control obligations. Although the U.S. proposal does not specify either the level of emission reductions or timeframe in which they must be achieved, it is expected to result in at least a cap on greenhouse gas emissions at the level emitted in the year 1990.

In accordance with the obligations set forth in the global climate change treaty, on April 21, 1993, President Clinton committed the United States to reducing greenhouse gas emissions to 1990 levels by the year 2000. On October 19, 1993, the President unveiled the Administration's Climate Change Action Plan for meeting this emission reduction target. The plan emphasizes reductions in fossil fuel use, the largest source of CO2 emissions, primarily through reliance on voluntary energy efficiency programs and partnerships between the Federal government and U.S. industry. One such collaboration is between the electric utility industry and DOE. Known as the Climate Challenge, this initiative has identified flexible, cost-effective measures to reduce, avoid or sequester future greenhouse gas emissions. AEP System companies joined with nearly 800 investor-owned, municipal, rural electric cooperative and Federal utilities in a voluntary agreement signed with DOE on April 20, 1994 that has led to individual utility Participation Accords resulting in substantial reductions in future greenhouse gas emissions. On February 3, 1995, the AEP System entered into its Climate Challenge Participation Accord with DOE. The Accord contains a diverse portfolio of supply-side, demand-side and forest management/tree planting activities that will be undertaken on the AEP System between now and the year 2000 with a projected reduction in CO2 emissions of 9,550,000 tons from what would have otherwise been emitted but for these actions.

As a result of the AEP System's historical practice of using low-cost indigenous coal supplies to produce electricity, AEP System power plants are significant sources of CO2 emissions. Management is working to support further efforts to properly study the issue of global climate change to define the extent, if any, to which it poses a threat to the environment. Management is concerned that new laws may be passed or new regulations promulgated without sufficient scientific study and support.

Since the AEP System is a major emitter of carbon dioxide, its financial condition and results of operations could be materially adversely affected by the imposition of limitations on CO2 emissions if the compliance costs incurred are not fully recovered from ratepayers. In addition, any such severe program to stabilize or reduce CO2 emissions could impose substantial costs on industry and society and seriously erode the economic base that AEP's operations serve.

West Virginia: West Virginia promulgated sulfur dioxide 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 obliged to reanalyze sulfur dioxide emission limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) standards. Because the Clean Air Act 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 sulfur dioxide 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 sulfur dioxide 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 sulfur dioxide per million Btu actual heat input on a three-hour basis and 5.8 pounds of sulfur dioxide 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 sulfur dioxide emission limitations which is to be submitted no later than November 1998. The interim emission limit for Kammer will remain in effect until after that time.

Stack Height Regulations: On June 27, 1985, Federal EPA issued stack height regulations pursuant to an order of the United States Court of Appeals for the District of Columbia Circuit. These regulations were appealed by a number of states, environmental groups and investor-owned electric utilities (including APCo, CSPCo, I&M, KEPCo and OPCo), along with three electric utility trade associations. OPCo also filed a separate petition for review to raise issues unique to its Kammer Plant. Various petitions for reconsideration filed with and denied by Federal EPA were also appealed. This litigation was consolidated into a single case.

On January 22, 1988, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision in part upholding the June 1985 stack height rules and remanding certain of the June 1985 rules to Federal EPA for further consideration. With respect to Kammer Plant, the January 1988 court decision rejected OPCo's appeal, holding that Federal EPA acted lawfully in revoking stack height credit previously granted for Kammer Plant in October 1982. OPCo has also commenced administrative proceedings with the State of West Virginia and Federal EPA in an effort to preserve stack height credit for Kammer Plant.

While it is not possible to state with particularity the ultimate impact of the final rules on AEP System operations, at present it appears that the most likely AEP System plants at which the final rules could possibly result in more stringent emission limitations are CSPCo's Conesville Plant, AEGCo's and I&M's Rockport Plant, I&M's Tanners Creek Plant and OPCo's Gavin and Kammer plants. Gavin and Rockport plants were not affected by Federal EPA's stack height rules as issued in June 1985. However, the provision exempting these plants was remanded to Federal EPA in the January 1988 court decision. Accordingly, the ultimate impact of the stack height rules on Gavin and Rockport plants will not be known until Federal EPA completes administrative proceedings on remand and reissues final stack height rules. OPCo and AEGCo and I&M intend to participate in the remand rulemaking affecting Gavin and Rockport plants, respectively.

State air pollution control agencies are required to implement the stack height rules by revising emission limitations for sources subject to the rules and submitting such revisions to Federal EPA.

On June 1, 1989, Ohio EPA adopted a rule concerning CSPCo's Conesville Plant in response to Federal EPA's stack height rules adopted in 1985. Under Federal EPA policy published in January 1988, emission reductions required by the stack height rules may be obtained at plants other than the plant directly affected by the rules, and thereafter credited to the directly affected plant. Under Ohio EPA's June 1, 1989 rule, the sulfur dioxide emission limitations for Conesville Units 5 and 6 remain at 1.2 pounds sulfur dioxide per million Btu heat input as long as the emission rate at CSPCo's retired Poston Units 1-4 remains at 0.0 pounds sulfur dioxide per million Btu heat input. Federal EPA has yet to take action concerning Ohio EPA's June 1, 1989 rule.

Administrative Developments Regarding Sulfur Dioxide: On November 15, 1994, Federal EPA published a notice in the Federal Register proposing to retain the present 24-hour national ambient air quality standard for sulfur dioxide. Federal EPA also sought comment on the need to adopt additional regulations to address short-term peak exposures to sulfur dioxide. On January 2, 1997, Federal EPA proposed a new intervention level program under the authority of Section 303 of the Clean Air Act to address high five-minute peak SO2 concentrations. The proposal calls for regulatory intervention to reduce emissions from a source or group of sources responsible for five-minute peak SO2 concentrations above prescribed levels. The effect on AEP operations of Federal EPA's proposed intervention level program for further regulating sulfur dioxide emissions, if finalized, cannot be predicted, but may be significant.

Life Extension: 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 Clean Air Act Amendments of 1990. 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.

National Ambient Air Quality Standards: Federal EPA proposed revisions to the National Ambient Air Quality Standard for ozone on December 13, 1996. The proposed standard is significantly more stringent than the current standard and, if adopted, would result in redesignation of many areas currently designated attainment. The proposal, if adopted, could lead to substantial reductions in allowable nitrogen oxide emissions from System power plants.

Federal EPA also proposed revision of the National Ambient Air Quality Standard for particulate matter (PM) on December 13, 1996. Federal EPA's proposed revision would add a standard for particulate matter below 2.5 microns in size (PM2.5). Federal EPA is required by court order to make a final determination on this issue by July 19, 1997. The new PM2.5 standard, if finalized, could lead to substantial reductions in allowable emissions of SO2, nitrogen oxides and particulate matter from System power plants.

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 1997.

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, antidegradation 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. Management cannot presently determine whether the GLWQI would have a significant adverse impact on AEP operations. The significance of such impact will depend on the outcome of Federal EPA's policy on intake credits and site specific variables as well as Michigan's implementation strategy. Federal EPA's rule is presently under review by the District of Columbia Circuit Court of Appeals in litigation initiated by several industry groups. If Indiana and Ohio eventually adopt the GLWQI criteria for statewide application, AEP System plants located in those states could also be affected.

Hazardous Substances and Wastes

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 PCB's contained in certain capacitors and transformers, but the occurrence and ramifications of a spill or release of such substances cannot be predicted.

CERCLA 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 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 five cases involving cost-recovery lawsuits at Federal EPA-identified CERCLA sites. OPCo is involved at three of these sites and I&M at the two other sites. Seven AEP System companies are identified as Potentially Responsible Parties (PRPs) for six additional federal sites, including CSPCo, KEPCo and Wheeling Power Company at one site each, I&M at two sites, and OPCo at two sites. I&M has been named as a PRP at one state remediation site. 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 1998. 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, or being used in 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. On October 31, 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..." The epidemiological studies that have received the most public attention, including the NAS report, reflect a weak correlation between surrogate or indirect estimates of EMF exposure and certain cancers. Studies using direct measurements of EMF exposure show no such association.

Federal EPA is currently studying whether exposure to EMF is associated with cancer in humans. In 1990, Federal EPA issued a draft report on EMF, received interagency review and public comment, and is in the process of preparing its final report. A December 1992 brochure from Federal EPA, Questions And Answers About Electric And Magnetic Fields (EMFs), states at page 3, "The bottom line is that there is no established cause and effect relationship between EMF exposure and cancer or other disease."

The Energy Policy Act of 1992 established a coordinated Federal EMF research program. The program funding is $65,000,000 over five years, half of which is to be provided by private parties including utilities. AEP has committed to contribute $446,571 over the five-year period. 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 1996. See Research and Development.

AEP's participation in the programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue. Its operating company subsidiaries provide their residential customers with 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 in recent years 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. The trial date has been set at August 18, 1997.

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. Under the amended EMF rules, persons seeking approval to build electric transmission lines have to provide estimates of EMF from transmission lines under a variety of conditions. In addition, applicants are required to address possible health effects and discuss the consideration of design alternatives with respect to EMF.

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 a number of research projects which are directed toward developing more efficient methods of burning coal, reducing the contaminants resulting from combustion of coal, and improving the efficiency and reliability of power transmission, distribution and utilization, including load management.

AEP System operating companies are members of the Electric Power Research Institute (EPRI), a nonprofit organization that manages research and development on behalf of the U.S. electric utility industry. EPRI, founded in 1973, manages technical research and development programs for its members to improve power production, delivery and use. Approximately 700 utilities are members. Total AEP dues to EPRI were $9,900,000 for 1996, $9,600,000 for 1995 and $3,200,000 for 1994.

Total research and development expenditures by AEP and its subsidiaries, including EPRI dues, were approximately $16,400,000 for the year ended December 31, 1996, $13,600,000 for the year ended December 31, 1995 and $7,600,000 for the year ended December 31, 1994. This includes expenditures of $3,300,000 for 1996, $1,100,000 for 1995 and $2,200,000 for 1994 related to pressurized fluidized-bed combustion, a process in which sulfur is removed during coal combustion and nitrogen oxide formation is minimized.