MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION

THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997

RESULTS OF OPERATIONS
Net income increased by $104.2 million or 114% for the quarter and $79.2 million or 21% for the year-to-date period due predominantly to the effect of an extraordinary loss from a United Kingdom (U.K.) one-time windfall tax enacted during the third quarter of 1997 and a significant increase in net revenues from energy sales due to favorable weather and energy marketing and trading activities within AEP's traditional marketing area. The windfall tax was based on a revision or recomputation of the original 1990 privatization value of certain privatized regional electric companies in the U.K. including Yorkshire Electricity Group. Income before extraordinary item decreased $6.4 million for the third quarter and $31.4 million for the year-to-date period as a result of a write-down of Yorkshire Electricity Group's investment in Ionica, a U.K. telecommunications company, expenditures to prepare the Cook Plant for restart following an extended outage and certain losses on energy trades outside of AEP's traditional marketing area.
The significant changes in income statement line items and net revenues were:

                                    Increase (Decrease)
                             Third Quarter       Year-to-Date
                          (in millions)   %   (in millions)   %

Operating Revenues . . . .   $3,054.1    193     $5,088.3    114
Fuel Expense . . . . . . .       41.2     10        114.8     10
Purchased Power Expense. .    2,881.7    N.M.     4,858.8    N.M.
  Net Revenues . . . . . .      131.2               114.7
Other Operation Expense. .       63.3     21         63.1      7
Maintenance Expense. . . .        6.9      6         28.3      8
Federal Income Taxes . . .       23.0     25         13.1      5
Nonoperating Income. . . .      (39.1)  (119)       (48.6)  (113)

N.M. = Not Meaningful

Operating revenues increased significantly in both the third quarter and the year-to-date periods due predominantly to increased sales to retail and wholesale customers. Energy sales to retail customers rose 6% in the quarter and 4% in the year-to-date period primarily due to warmer summer weather in 1998 and increased industrial customer usage. The significant increases in wholesale sales and wholesale revenues are attributable to growth in the power marketing and trading business in AEP's marketing area.
The increases in fuel expense were primarily attributable to an increase in coal-fired generation to meet the increased demand for electricity and an increase in the average cost of fuel consumed reflecting the unavailability of lower cost nuclear generation due to the unplanned outage of both Cook Plant nuclear units in 1998.
Purchases of electricity by the wholesale power marketing and trading business accounted for the significant increase in purchased power expense.
The increase in net revenues of $131 million for the quarter and $115 million for the year-to-date period is due to the impact of warmer summer weather and increased industrial usage on retail sales and the successful trading of wholesale energy in a volatile market.
The increases in other operation expenses are related to the increases in energy sales and the extended Cook Plant outage and in the third quarter increased incentive pay accruals.
Maintenance expense increased for the year-to-date period largely as a result of expenditures to prepare the Cook Plant units for restart and to repair and restore service interruptions caused by two severe snowstorms.
Federal income tax expense attributable to operations increased due to an increase in pre-tax operating income.
The decreases in nonoperating income for both periods reflect the effect of the Company's equity share of Yorkshire's loss on its investment in Ionica, losses on certain energy trades and in the third quarter the effect of $26 million of tax benefits recognized in 1997 related to a reduction of the corporate income tax rate in the U.K. by Yorkshire and the utilization of certain foreign tax

credits. The energy trades which produced the losses are marked-to-market and represent non-regulated trading activities outside the Company's traditional marketing area (see footnote 5). Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the first nine months of 1998 were $652 million.
During the first nine months of 1998, subsidiaries issued $608 million principal amount of long-term obligations at interest rates ranging from 5.87% to 10.53%; retired $524 million principal amount of long-term debt with interest rates ranging from 2.85% to 9.15%; and decreased short-term debt by $20 million.
COOK NUCLEAR PLANT SHUTDOWN
As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition, both units of the Cook Nuclear Plant were shut down by Indiana Michigan Power Company (I&M) in September 1997 due to questions regarding the operability of certain safety systems, which arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. The NRC issued a Confirmatory Action Letter in September 1997 requiring I&M to address the issues identified in the letter. I&M is working with the NRC to resolve the one remaining issue in the letter.
On April 17, 1998, the NRC notified I&M that it had convened a Restart Panel for Cook Plant. On July 30, 1998, I&M received a letter from the NRC providing the NRC's list of required restart activities. I&M is and will be meeting with the Panel on a regular basis, until the Cook Plant units are returned to service, to identify and address the items that need to be addressed in order to restart the units. When maintenance and other activities required for restart are complete, I&M will seek concurrence from the NRC to return the Cook Plant to service.

I&M's current restart schedule indicates Unit 1 is expected to return to service by the end of the first quarter of 1999. The restart schedule for Unit 2 has not been completed; however, management anticipates that Unit 2 may return to service 90 days after Unit 1. If the units are not returned to service, there could be a material adverse effect on financial condition.
The incremental cost expected to be incurred to restart the Cook units is approximately $70 million for 1998, of which $34 million has been incurred through September 30, 1998. However, approximately $20 million of previously budgeted work for 1998 at the Cook Plant will not be incurred and will partially mitigate the incremental restart costs. The cost and schedule for the outage during 1999 could be significantly impacted if additional work is identified beyond the $35 million planned for the first quarter.
On July 24, 1998, I&M received an "adverse trend letter" from the NRC indicating that NRC senior managers had determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities.
In a letter dated October 13, 1998, the NRC issued to I&M a Notice of Violation and proposed a $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 4, 1997 and April 15, 1998. I&M paid the penalty.
The cost of electricity supplied to I&M's retail customers rose due to the outage of the two units since higher cost coal-fired generation and purchased power were substituted for low cost nuclear generation. In the Indiana and Michigan retail jurisdictions fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under the fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a

future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor as was the case with regard to the Cook outage, a regulatory asset is recorded and revenues are accrued.
Due to the unscheduled Cook Plant outage, I&M's actual fuel costs significantly exceeded the estimated fuel costs reflected in its fuel cost adjustment factors. A regulatory asset has been recorded for revenues accrued in anticipation of future reconciliation and billing of the higher fuel costs to customers. At September 30, 1998, the regulatory asset was $61 million.
The Indiana Utility Regulatory Commission approved two agreements authorizing I&M during the billing months of July through December 1998 to apply a fuel cost adjustment factor less than that requested by I&M, subject to future reconciliation or refund. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the appropriateness of the recovery of replacement energy cost due to the extended Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that it should be able to recover the Cook replacement energy costs; however, if recovery of the replacement costs is denied, results of operations and cash flows would be adversely affected.
The above timetable for the return to service of the Cook Plant constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, other unforeseen issues encountered in preparing the Cook Plant for restart and the unpredictability of the NRC regulatory process.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also

filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the operating companies of the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that compliance costs could result in required capital expenditures by AEP of approximately $1.2 billion. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.
ENERGY MARKETING AND TRADING
During 1998, the Company substantially increased the volume of its electricity and gas marketing and trading. The purpose of the marketing and trading business is to utilize the Company's knowledge of the energy markets in order to improve the

competitiveness of its generation business and contribute to net income, thereby enhancing both customer and shareholder value.
The electricity and gas marketing and trading business involves the marketing of energy under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Company's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Company had open marketing contracts, not marked-to-market on its balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion.
The Company has also purchased and sold electricity and gas options, futures and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity and gas outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. The unrealized mark-to-market gains and losses from such trading activity are reported as assets and liabilities, respectively. At September 30, 1998, the Company has open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity and gas with a notional value of approximately $755 million and to purchase electricity and gas with a notional value of approximately $585 million.
Dependent on future electricity and gas market conditions these activities could produce material income or losses in future periods.
TAXES
As discussed in Note 10, "Federal Income Taxes", of the Notes to Consolidated Financial Statements in the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition, the Internal Revenue Service

(IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through September 30, 1998 would reduce earnings by approximately $310 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.
In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998 the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Year

2000 ready programs.
Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Year 2000 readiness.
Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. AEP, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30, 1999 to June 30, 1999.
Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans.

Various state regulatory commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction.

Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, communications, and the physical generation and delivery of energy; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g. payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations.
The following chart shows our progress toward becoming ready for the Year 2000 as of September 30, 1998:

                             IT SYSTEMS         NON-IT  SYSTEMS
                     COMPLETION                 COMPLETION
                     DATE/ESTIMATED     PERCENT     DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of       2/24/1998     100%         5/31/1998     100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment:
Identifying all Company     7/31/1998     100%         11/30/1998    86%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,       6/30/1999     Mainframe     6/30/1999     2%
replacing or retiring                     60%
those mission critical and
high priority digital-based
systems with problems                     Client
processing dates past the                 Server:
Year 2000. Testing these                  1%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

Costs to Address the Company's Year 2000 Issues - Through September 30, 1998, the Company has spent $15 million on the Year 2000 project and, estimates spending an additional $41 million to $53 million to achieve Year 2000 readiness. Most Year 2000 costs are software, IT consultant and salary-related and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition.

Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 problems are:
* Automated power generation, transmission and distribution systems
* Telecommunications systems
* Energy trading systems
* Time-in-use, demand and remote metering systems for commercial and industrial customers
* Work management and billing systems.

The potential problems related to erroneous processing by, or failure of, these systems are:
* Power service interruptions to customers
* Interrupted revenue data gathering and collection
* Poor customer relations resulting from delayed billing and settlement.

In addition, although as discussed the Company is monitoring its relationships with third parties, such as suppliers, customers and other electric utilities, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others not affiliated with AEP, fail for critical applications, Year 2000-related issues may materially adversely affect AEP.

Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster recovery, system restoration, and contingency planning that we now have in place. We have begun the contingency planning process, including the review of NERC's Contingency Planning Guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999.

Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on

management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others:
* Continuing availability of experienced consultants and IT personnel and related resources
* Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness
* Ability of the Company to identify and implement contingency plans.

PROPOSED MERGER AND ACQUISITION
As discussed in the Management's Discussion and Analysis of Results of Operations and Financial Condition in the 1997 annual report and the Joint Proxy Statement/Prospectus dated April 16, 1998, the Company and Central and South West Corporation (CSW) have agreed to merge. At the May 1998 annual meeting, AEP shareholders approved the issuance of AEP common shares to effect the merger and approved an increase in the authorized shares of AEP Common Stock from 300,000,000 to 600,000,000. CSW stockholders approved the merger at their May 1998 annual meeting. The companies have filed for necessary approvals to merge with the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission, the NRC and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. Filings with the Federal Communications Commission and the Department of Justice are expected to be made before the end of 1998. The Company's target consummation date for the merger is the second quarter of 1999.
In August 1998 the Arkansas Public Service Commission approved the merger, subject to a number of conditions including the approval of a regulatory plan for sharing net merger savings. On November 3, 1998 the Company, CSW and CSW's Arkansas operating subsidiary, Southwestern Electric Power Company, filed a settlement

agreement for approval with the Arkansas Public Service Commission outlining a regulatory plan, agreed to with the Commission staff, which provides for a sharing of net merger savings through a reduction of rates for Arkansas retail customers.
In October 1998 the Oklahoma Corporation Commission (OCC) approved plans by AEP and CSW to submit an amended filing seeking approval of the proposed merger. The amended application is being made as a result of an Oklahoma administrative law judge's recommendation that the merger filing be dismissed without prejudice for lack of information regarding the potential impact of the merger on the retail electric market in Oklahoma. Submission of the amended application will reset Oklahoma's 90-day statutory time period for OCC action on the merger phase of the application. The filing of the amended application should not affect the timing of the merger closing.
In July 1998 the FERC issued an order which confirmed that the 250 megawatt firm contract path with the Ameren System is available. The contract path is required for AEP and CSW to meet the requirements of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. On November 10, 1998, the FERC issued an order establishing hearing procedures for the merger. A scheduling conference will be held in November 1998. The order indicated that the review of the proposed merger will address the issues of competition, market power and customer protection and instructed the companies to refile an updated market power study. The outcome of the FERC scheduling conference could extend the targeted completion date of the merger.
A settlement agreement between AEP, CSW and certain key parties to the Texas merger proceeding has been reached. The staff of the Public Utility Commission of Texas was not a signatory to the settlement agreement, which resolves all issues for the signing parties. The settlement provides for, among other things, the approval of rate reductions to share net merger savings and settle existing rate reviews.

The application by CSW's operating subsidiary, Central Power and Light Company, to the NRC requesting permission to transfer control of the license for the South Texas Project nuclear generating station to AEP was approved by the NRC.
AEP has a 50% interest in Yorkshire Electricity Group, plc and CSW has a 100% interest in Seeboard, plc, two U.K. regional electricity companies (RECs). The proposed merger of CSW into AEP would result in common ownership of these U.K. entities. As a result, the common ownership of two U.K. RECs could be referred by the U.K. Secretary of State for Trade and Industry to the U.K. Mergers and Monopolies Commission for investigation.
The merger, which is to be accounted for as a pooling of interests, is conditioned upon, among other things, the approval of the above state and federal regulatory agencies. The transaction must satisfy many conditions, including the condition that it must be a pooling, and some of these conditions may not be waived by the parties. The Company is unable to predict the outcome or the timing of the required regulatory proceedings.
In September 1998 the Company and Equitable Resources, Inc. signed a definitive agreement for the Company to purchase Equitable's natural gas midstream assets and operations for approximately $320 million. The purchase includes an intrastate pipeline system, five natural gas processing plants, one natural gas storage facility and an energy trading business. The transaction is expected to close in the fourth quarter of 1998 and be accounted for as a purchase.

                        AEP GENERATING COMPANY
                         STATEMENTS OF INCOME
                              (UNAUDITED)
                                           Three Months Ended      Nine Months Ended
                                              September 30,          September 30,
                                             1998      1997         1998        1997
                                                         (in thousands)
OPERATING REVENUES . . . . . . . . . . .   $59,262    $58,136     $167,596    $170,665

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    27,953     26,354       71,718      72,443
  Rent - Rockport Plant Unit 2 . . . . .    17,071     17,071       51,212      51,212
  Other Operation. . . . . . . . . . . .     2,174      2,518        7,547       8,362
  Maintenance. . . . . . . . . . . . . .     2,703      2,372        9,110      10,115
  Depreciation . . . . . . . . . . . . .     5,405      5,402       16,229      16,209
  Taxes Other Than Federal Income Taxes.       882      1,015        2,759       2,744
  Federal Income Taxes . . . . . . . . .       845        922        2,562       2,529

          TOTAL OPERATING EXPENSES . . .    57,033     55,654      161,137     163,614

OPERATING INCOME . . . . . . . . . . . .     2,229      2,482        6,459       7,051

NONOPERATING INCOME. . . . . . . . . . .       837        831        2,457       2,631

INCOME BEFORE INTEREST CHARGES . . . . .     3,066      3,313        8,916       9,682

INTEREST CHARGES . . . . . . . . . . . .       903        986        2,494       2,997

NET INCOME . . . . . . . . . . . . . . .   $ 2,163    $ 2,327     $  6,422    $  6,685



                    STATEMENTS OF RETAINED EARNINGS
                              (UNAUDITED)

                                           Three Months Ended      Nine Months Ended
                                              September 30,          September 30,
                                             1998      1997         1998        1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . .    $2,435    $3,672       $2,528      $1,886

NET INCOME . . . . . . . . . . . . . . .     2,163     2,327        6,422       6,685

CASH DIVIDENDS DECLARED. . . . . . . . .     2,176     3,286        6,528       5,858

BALANCE AT END OF PERIOD . . . . . . . .    $2,422    $2,713       $2,422      $2,713



The common stock of the Company is wholly owned by
American Electric Power Company, Inc.

See Notes to Financial Statements.

                        AEP GENERATING COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)

                                                            September 30,  December 31,
                                                                 1998          1997

                                                                   (in thousands)

ASSETS
ELECTRIC UTILITY PLANT:
  Production. . . . . . . . . . . . . . . . . . . . . . . .   $629,055       $627,803
  General . . . . . . . . . . . . . . . . . . . . . . . . .      3,151          3,137
  Construction Work in Progress . . . . . . . . . . . . . .      2,510          2,510
          Total Electric Utility Plant. . . . . . . . . . .    634,716        633,450
  Accumulated Depreciation. . . . . . . . . . . . . . . . .    272,198        257,191


          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .    362,518        376,259




CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .        142            237
  Accounts Receivable . . . . . . . . . . . . . . . . . . .     22,674         20,710
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .     12,097         10,107
  Materials and Supplies. . . . . . . . . . . . . . . . . .      4,126          4,246
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .        152            368


          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     39,191         35,668



REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      6,044          5,639



DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      1,570          1,492



            TOTAL . . . . . . . . . . . . . . . . . . . . .   $409,323       $419,058

See Notes to Financial Statements.

                        AEP GENERATING COMPANY
                            BALANCE SHEETS
                              (UNAUDITED)
                                                           September 30,   December 31,
                                                                1998           1997

                                                                  (in thousands)

CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
  Common Stock - Par Value $1,000:
    Authorized and Outstanding - 1,000 Shares . . . . . . .   $  1,000       $  1,000
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     36,235         39,235
  Retained Earnings . . . . . . . . . . . . . . . . . . . .      2,422          2,528
          Total Common Shareholder's Equity . . . . . . . .     39,657         42,763
  Long-term Debt. . . . . . . . . . . . . . . . . . . . . .     44,790         69,570

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     84,447        112,333

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . .        972          1,259

CURRENT LIABILITIES:
  Short-term Debt - Notes Payable . . . . . . . . . . . . .      8,175         11,750
  Accounts Payable. . . . . . . . . . . . . . . . . . . . .     13,226          9,704
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      4,751          3,420
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .        164            461
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . .     23,427          4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      5,311          3,747

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     55,054         34,045

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . .    134,723        138,901

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . . . .     67,494         70,016
  Deferred Amounts Due to Customers for Income Tax. . . . .     30,404         31,375

          TOTAL REGULATORY LIABILITIES. . . . . . . . . . .     97,898        101,391

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     36,075         31,129

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .        154           -

            TOTAL . . . . . . . . . . . . . . . . . . . . .   $409,323       $419,058

See Notes to Financial Statements.

                        AEP GENERATING COMPANY
                       STATEMENTS OF CASH FLOWS
                              (UNAUDITED)
                                                                 Nine Months Ended
                                                                   September 30,
                                                                 1998          1997
                                                                   (in thousands)
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .   $  6,422      $  6,685
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .     16,229        16,209
    Deferred Federal Income Taxes. . . . . . . . . . . . . .      3,975         3,564
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (2,522)       (2,526)
    Amortization of Deferred Gain on Sale
      and Leaseback - Rockport Plant Unit 2. . . . . . . . .     (4,178)       (4,178)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . . .     (1,964)       (1,804)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (1,870)        7,149
    Accounts Payable . . . . . . . . . . . . . . . . . . . .      3,522        (2,655)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      1,331         2,292
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464        18,464
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .      1,174        (2,044)
        Net Cash Flows From Operating Activities . . . . . .     40,583        41,156

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .     (4,829)       (2,042)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      2,254          -
        Net Cash Flows Used For Investing Activities . . . .     (2,575)       (2,042)

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . . . .     (3,000)       (2,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .     (3,575)       (9,575)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (25,000)      (20,010)
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .     (6,528)       (5,858)
        Net Cash Flows Used For Financing Activities . . . .    (38,103)      (37,443)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .        (95)        1,671
Cash and Cash Equivalents at Beginning of Period . . . . . .        237           139
Cash and Cash Equivalents at End of Period . . . . . . . . .   $    142      $  1,810


Supplemental Disclosure:
  Cash paid  (received) for interest  net  of capitalized  amounts was $2,508,000 and
  $2,699,000 and for income taxes was $(1,188,000) and $(1,598,000) in 1998 and 1997,
  respectively.

See Notes to Financial Statements.

AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)

1. GENERAL

The accompanying unaudited financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods.

2. FINANCING ACTIVITIES

In March 1998 $12.5 million of the 1995 Series A pollution control revenue bonds due 2025 and $12.5 million of the 1995 Series B pollution control revenue bonds due 2025 were redeemed.

3. NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income.

In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition.

AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997

Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies and one unaffiliated utility pursuant to Federal Energy Regulatory Commission (FERC) approved long-term unit power agreements. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments.
Net income decreased $0.2 million or 7% for the third quarter and $0.3 million or 4% for the year-to-date period as a result of capital returned to the parent company in 1997, May 1998 and August 1998.
Income statement line items which changed significantly were:

                                   Increase (Decrease)
                            Third Quarter         Year-to-Date
                         (in millions)    %   (in millions)    %

Operating Revenues. . . . .  $ 1.1        2       $(3.1)      (2)
Fuel Expense. . . . . . . .    1.6        6        (0.7)      (1)
Other Operation Expense . .   (0.3)     (14)       (0.8)     (10)
Maintenance Expense . . . .    0.3       14        (1.0)     (10)
Interest Charges. . . . . .   (0.1)      (8)       (0.5)     (17)

The increase in operating revenues for the third quarter reflects the recovery through the unit power agreements of higher operating expenses, primarily fuel expense. In the year-to-date period, lower operating expenses and a lower return on common equity reflecting the return of capital are the primary reasons for the decline in operating revenues.
Fuel expense increased in the third quarter reflecting a 7% increase in generation. While year-to-date generation increased 5%, a lower average cost of fuel consumed, due to lower coal prices, produced a reduction in fuel expense.

The decline in other operation expense in both the quarter and year-to-date periods is primarily due to a decline in administrative and general expenses reflecting a reduction in allocated wages and employee benefit costs and a reduction in a FERC assessment.
Maintenance expense increased during the quarter due to a rise in boiler plant repair expenditures, while for the year-to-date period the reduction in maintenance expense reflects a longer duration outage in 1997 compared with 1998's outage.
The decline in interest charges was due to a reduction in outstanding long-term debt balances reflecting the redemption of $20 million in June 1997 and $25 million in March 1998 of pollution control revenue bonds.

                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
                                           Three Months Ended       Nine Months Ended
                                             September 30,             September 30,
                                           1998         1997        1998          1997
                                                         (in thousands)
OPERATING REVENUES . . . . . . . . . . . $1,312,293    $438,510   $2,689,576    $1,228,044

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    113,059     104,514      322,459       288,773
  Purchased Power. . . . . . . . . . . .    939,595     100,587    1,654,929       261,595
  Other Operation. . . . . . . . . . . .     73,988      60,585      191,297       185,852
  Maintenance. . . . . . . . . . . . . .     30,691      27,615       97,519        79,505
  Depreciation and Amortization. . . . .     36,059      34,568      107,252       102,817
  Taxes Other Than Federal Income Taxes.     29,003      29,544       89,181        89,580
  Federal Income Taxes . . . . . . . . .     18,947      16,317       45,547        45,411

          TOTAL OPERATING EXPENSES . . .  1,241,342     373,730    2,508,184     1,053,533

OPERATING INCOME . . . . . . . . . . . .     70,951      64,780      181,392       174,511
NONOPERATING INCOME (LOSS) . . . . . . .     (5,664)        305       (4,490)          628
INCOME BEFORE INTEREST CHARGES . . . . .     65,287      65,085      176,902       175,139
INTEREST CHARGES . . . . . . . . . . . .     31,841      30,332       95,133        88,524
NET INCOME . . . . . . . . . . . . . . .     33,446      34,753       81,769        86,615
PREFERRED STOCK DIVIDEND REQUIREMENTS. .        675         681        1,822         6,326
EARNINGS APPLICABLE TO COMMON STOCK. . . $   32,771    $ 34,072   $   79,947    $   80,289


               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                             September 30,             September 30,
                                           1998         1997         1998          1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $195,262     $197,471     $207,544      $208,472
NET INCOME . . . . . . . . . . . . . . .   33,446       34,753       81,769        86,615
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   29,729       28,609       89,187        85,827
    Cumulative Preferred Stock . . . . .      567          572        1,499         2,649
  Capital Stock Expense. . . . . . . . .      108          109          323         3,677

BALANCE AT END OF PERIOD . . . . . . . . $198,304     $202,934     $198,304      $202,934

The common stock of the Company is wholly owned by
American Electric Power Company, Inc.

See Notes to Consolidated Financial Statements.

                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                          September 30,   December 31,
                                                               1998           1997
                                                                 (in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .      $1,959,309     $1,942,325
  Transmission . . . . . . . . . . . . . . . . . . . .       1,117,332      1,079,919
  Distribution . . . . . . . . . . . . . . . . . . . .       1,647,232      1,583,161
  General. . . . . . . . . . . . . . . . . . . . . . .         228,803        207,380
  Construction Work in Progress. . . . . . . . . . . .          77,573         88,261
          Total Electric Utility Plant . . . . . . . .       5,030,249      4,901,046
  Accumulated Depreciation and Amortization. . . . . .       1,958,654      1,869,057

          NET ELECTRIC UTILITY PLANT . . . . . . . . .       3,071,595      3,031,989



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         109,354         34,544



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .           8,467          6,947
  Accounts Receivable. . . . . . . . . . . . . . . . .         161,074        164,657
  Allowance for Uncollectible Accounts . . . . . . . .          (1,590)        (1,333)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .          48,425         47,901
  Materials and Supplies . . . . . . . . . . . . . . .          63,860         57,359
  Accrued Utility Revenues . . . . . . . . . . . . . .          40,630         51,208
  Prepayments and Other. . . . . . . . . . . . . . . .          16,671          6,960

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         337,537        333,699


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         434,704        441,223


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .          37,346         41,975

            TOTAL. . . . . . . . . . . . . . . . . . .      $3,990,536     $3,883,430

See Notes to Consolidated Financial Statements.

                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                        September 30,   December 31,
                                                             1998           1997
                                                               (in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  30,000,000 Shares
    Outstanding - 13,499,500 Shares. . . . . . . . . .   $  260,458      $  260,458
  Paid-in Capital. . . . . . . . . . . . . . . . . . .      638,510         613,048
  Retained Earnings. . . . . . . . . . . . . . . . . .      198,304         207,544
          Total Common Shareholder's Equity. . . . . .    1,097,272       1,081,050
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .       19,439          19,747
    Subject to Mandatory Redemption. . . . . . . . . .       22,310          22,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,532,809       1,415,026

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,671,830       2,538,133

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .      164,715         137,371

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       19,504          79,509
  Short-term Debt. . . . . . . . . . . . . . . . . . .       61,975         130,300
  Accounts Payable . . . . . . . . . . . . . . . . . .       80,625          96,816
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       43,772          41,549
  Customer Deposits. . . . . . . . . . . . . . . . . .       14,194          13,713
  Interest Accrued . . . . . . . . . . . . . . . . . .       29,841          20,949
  Revenue Refunds Accrued. . . . . . . . . . . . . . .       42,418           3,311
  Other. . . . . . . . . . . . . . . . . . . . . . . .       91,876          68,812

          TOTAL CURRENT LIABILITIES. . . . . . . . . .      384,205         454,959

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      649,472         658,655

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       63,948          67,496

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .       56,366          26,816

CONTINGENCIES (Note 6)

            TOTAL. . . . . . . . . . . . . . . . . . .   $3,990,536      $3,883,430

See Notes to Consolidated Financial Statements.

                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
                                                                  Nine Months Ended
                                                                    September 30,
                                                                 1998           1997
                                                                    (in thousands)
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $  81,769       $ 86,615
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    108,158        103,796
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     (1,452)        (8,719)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (3,548)        (3,571)
    Provision for Rate Refunds . . . . . . . . . . . . . . .      9,342          3,083
    Deferred Power Supply Costs (net). . . . . . . . . . . .     25,137         13,951
    Amortization of Deferred Property Taxes. . . . . . . . .     12,940         13,240
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .      3,840         13,458
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (7,025)        (1,763)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     10,578         18,942
    Prepayments and Other Current Assets . . . . . . . . . .     (9,711)         3,695
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (16,191)        13,188
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      2,223          1,642
    Interest Accrued . . . . . . . . . . . . . . . . . . . .      8,892         12,285
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .     39,107         (1,933)
  Payment of Disputed Tax and Interest Related to COLI . . .    (68,316)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     22,652        (19,383)
        Net Cash Flows From Operating Activities . . . . . .    218,395        248,526

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (138,297)      (146,039)
  Proceeds from Sale of Property . . . . . . . . . . . . . .        914          4,204
        Net Cash Flows Used For Investing Activities . . . .   (137,383)      (141,835)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .     25,000         20,000
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    193,431        183,257
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (68,325)        22,825
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (229)      (183,842)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (138,472)       (56,378)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (89,187)       (85,827)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,710)        (5,319)
        Net Cash Flows Used For Financing Activities . . . .    (79,492)      (105,284)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .      1,520          1,407
Cash and Cash Equivalents at Beginning of Period . . . . . .      6,947          7,260
Cash and Cash Equivalents at End of Period . . . . . . . . .  $   8,467      $   8,667

Supplemental Disclosure:
  Cash paid for  interest net of capitalized  amounts was  $83,359,000 and $73,466,000
  and for income taxes was $38,378,000 and $46,965,000 in 1998 and 1997, respectively.
  Noncash acquisitions under  capital leases were $16,909,000 and  $14,377,000 in 1998
  and 1997, respectively.

See Notes to Consolidated Financial Statements.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)

1. GENERAL

The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods.

2. RATE MATTER

In September 1992 the Company implemented, subject to refund, an $8.7 million annual rate increase to its wholesale customers pending a final order from the Federal Energy Regulatory Commission (FERC). On June 29, 1998 the FERC granted an annual rate increase of $3.4 million and required a refund including interest of amounts collected in excess of the $3.4 million annual increase. A rehearing of the FERC's order has been requested.

At September 30, 1998, the Company had fully provided for the refund obligation plus interest as a current liability.

                                     Principal
                                     Amount
% Rate        Due Date               Reacquired
                                   (in thousands)
8.75          2022 - February 1       $29,919
8.70          2022 - May 22            35,000
7.95          2002 - March 1           60,000
8.43          2022 - June 1            12,529

In June 1998, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in capital.

4. NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income.

In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed software acquisition and development costs with the exception of newly developed customer service and billing software costs which were capitalized in accordance with an order of the Virginia State Corporation Commission. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition.

5. POWER MARKETING AND TRADING

During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands.

The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these

notional values is approximately $320 million.

The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $70 million for sales and approximately $45 million for purchases.

Dependent on future electricity market conditions these activities could produce material income or losses in future periods.

6. CONTINGENCIES

Taxes

As discussed in Note 9, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $77 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.

In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution

of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.

Revised Air Quality Standards

The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.

On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.

Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.

Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $325 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.

Other

The Company continues to be involved in certain other matters discussed in its 1997 Annual Report.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997

RESULTS OF OPERATIONS
Despite an increase in revenues net of fuel and purchased power expenses (net revenues) of $26.3 million for the third quarter and $34.5 million for the year-to-date period due to an increase in weather related retail sales and wholesale power marketing and trading transactions within AEP's traditional marketing area, net income decreased $1.3 million or 4% for the quarter and $4.8 million or 6% for the year-to-date period. The decline in net income was primarily due to an increase in operating expenses other than fuel and purchased power, losses on certain non-regulated energy trades outside of the Company's marketing area, an increase in interest charges and the recordation of provisions for revenue refunds, net of tax.
The significant changes in income statement line items and net revenues were:

                                   Increase (Decrease)
                             Third Quarter       Year-to-Date
                          (in millions)   %   (in millions)   %

Operating Revenues . . . .   $873.8     199      $1,461.5   119
Fuel Expense . . . . . . .      8.5       8          33.7    12
Purchased Power Expense. .    839.0     N.M.      1,393.3   N.M.
  Net Revenues . . . . . .     26.3                  34.5
Other Operation Expense. .     13.4      22           5.4     3
Maintenance Expense. . . .      3.1      11          18.0    23
Depreciation and
  Amortization . . . . . .      1.5       4           4.4     4
Federal Income Taxes . . .      2.6      16           0.1    -
Nonoperating Income. . . .     (6.0)    N.M.         (5.1)  N.M.
Interest Charges . . . . .      1.5       5           6.6     7

N.M. = Not Meaningful

Operating revenues increased significantly in both the third quarter and the year-to-date periods due predominantly to increased retail and wholesale sales. The increase in retail revenues can be attributed to increased energy sales to residential and commercial customers reflecting warmer spring and summer weather in 1998.

Revenues from wholesale customers increased significantly reflecting growth in power marketing and trading transactions.
The increases in fuel expense for the quarter and year-to-date periods were primarily due to increased coal fired generation to meet the increased demand.
Purchased power expense increased primarily as a result of the growth in power marketing and trading activities.
The increase in other operation expense was mainly due to costs related to the increase in sales and employee incentive pay accruals.
Maintenance expense increased as a result of an increase in planned expenditures to maintain transmission and distribution right-of-ways and, for the year-to-date period, costs for repair and restoration of service caused by two severe snowstorms.
The increase in depreciation and amortization expense is mainly due to additional investment in depreciable plant reflecting improvements to the transmission and distribution system.
In the third quarter federal income tax expense attributable to operations increased primarily due to an increase in pre-tax operating income.
The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 5, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger.
Interest charges for the quarter and year-to-date periods increased as a result of the accrual of interest on a revenue refund to wholesale customers under the terms of a final rate order and an increase in long-term debt outstanding.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the first nine months of 1998 were $155 million.

During the first nine months of 1998, the Company issued two series of senior unsecured notes of $100 million each with rates of 7.20% and 7.30% due in 2038 and redeemed $137 million principal amount of first mortgage bonds with interest rates from 7.95% to 8.75%. Short-term debt decreased by $68 million from year-end balances. In June 1998, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in capital.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to

implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $325 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Year 2000 ready programs.

Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Year 2000 readiness.
Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. AEP, along with other electric utilities in North America, regularly submits information to the North American Electric

Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30, 1999 to June 30, 1999.
Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans.
Various state regulatory commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction.

Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, communications, and the physical generation and delivery of energy; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g. payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations.

The following chart shows our progress toward becoming ready for the Year 2000 as of September 30, 1998:

                             IT SYSTEMS         NON-IT  SYSTEMS
                     COMPLETION                 COMPLETION
                     DATE/ESTIMATED     PERCENT     DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of       2/24/1998     100%         5/31/1998     100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment:
Identifying all Company     7/31/1998     100%         11/30/1998    86%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,       6/30/1999     Mainframe     6/30/1999     2%
replacing or retiring                     60%
those mission critical and
high priority digital-based
systems with problems                     Client
processing dates past the                 Server:
Year 2000. Testing these                  1%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

Costs to Address the Company's Year 2000 Issues - Through September 30, 1998, the Company has spent $4 million on the Year 2000 project and, estimates spending an additional $12 million to $16 million to achieve Year 2000 readiness. Most Year 2000 costs are software, IT consultant and salary-related and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition.

Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 problems are:
* Automated power generation, transmission and distribution systems
* Telecommunications systems
* Energy trading systems
* Time-in-use, demand and remote metering systems for commercial and industrial customers
* Work management and billing systems.

The potential problems related to erroneous processing by, or failure of, these systems are:
* Power service interruptions to customers
* Interrupted revenue data gathering and collection
* Poor customer relations resulting from delayed billing and settlement.

In addition, although as discussed the Company is monitoring its relationships with third parties, such as suppliers, customers and other electric utilities, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others not affiliated with AEP, fail for critical applications, Year 2000-related issues may materially adversely affect AEP.

Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster recovery, system restoration, and contingency planning that we now

have in place. We have begun the contingency planning process, including the review of NERC's Contingency Planning Guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999.

Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others:
* Continuing availability of experienced consultants and IT personnel and related resources
* Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness
* Ability of the Company to identify and implement contingency plans.

TAXES
As discussed in Note 9, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A

disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $77 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.
In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.
POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands.
The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating

revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $320 million.
The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $70 million for sales and approximately $45 million for purchases.
Dependent on future electricity market conditions these activities could produce material income or losses in future periods.

             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
                                          Three Months Ended         Nine Months Ended
                                             September 30,              September 30,
                                           1998         1997         1998          1997
                                                         (in thousands)
OPERATING REVENUES . . . . . . . . . . . $843,007     $313,024    $1,711,773     $841,294

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   49,693       52,269       143,533      134,198
  Purchased Power. . . . . . . . . . . .  561,812       54,444       972,535      138,278
  Other Operation. . . . . . . . . . . .   59,478       46,505       150,843      132,256
  Maintenance. . . . . . . . . . . . . .   13,932       17,535        43,128       50,602
  Depreciation . . . . . . . . . . . . .   22,760       22,784        68,454       67,800
  Amortization of Zimmer Plant
    Phase-in Costs . . . . . . . . . . .     -            -             -          15,744
  Taxes Other Than Federal Income Taxes.   29,295       29,861        86,921       89,484
  Federal Income Taxes . . . . . . . . .   31,774       24,731        69,716       57,639
          TOTAL OPERATING EXPENSES . . .  768,744      248,129     1,535,130      686,001

OPERATING INCOME . . . . . . . . . . . .   74,263       64,895       176,643      155,293
NONOPERATING INCOME (LOSS) . . . . . . .   (2,337)         658        (1,109)       2,018
INCOME BEFORE INTEREST CHARGES . . . . .   71,926       65,553       175,534      157,311
INTEREST CHARGES . . . . . . . . . . . .   19,635       20,065        58,856       59,069
NET INCOME . . . . . . . . . . . . . . .   52,291       45,488       116,678       98,242
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      532          532         1,598        1,909
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 51,759     $ 44,956    $  115,080     $ 96,333



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended         Nine Months Ended
                                             September 30,              September 30,
                                           1998         1997         1998          1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $160,171     $111,953    $138,172       $ 99,582
NET INCOME . . . . . . . . . . . . . . .   52,291       45,488     116,678         98,242
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   20,661       19,671      61,983         59,013
    Cumulative Preferred Stock . . . . .      437          437       1,312          1,312
  Capital Stock Expense. . . . . . . . .       95           95         286            261

BALANCE AT END OF PERIOD . . . . . . . . $191,269     $137,238    $191,269       $137,238

The common stock of the Company is wholly owned by American Electric Power Company, Inc.

See Notes to Consolidated Financial Statements.

             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                          September 30,   December 31,
                                                              1998            1997
                                                                 (in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $1,520,079      $1,521,381
  Transmission . . . . . . . . . . . . . . . . . . . .        338,743         336,446
  Distribution . . . . . . . . . . . . . . . . . . . .        927,225         926,178
  General. . . . . . . . . . . . . . . . . . . . . . .        122,532         138,041
  Construction Work in Progress. . . . . . . . . . . .        120,161          54,064
          Total Electric Utility Plant . . . . . . . .      3,028,740       2,976,110
  Accumulated Depreciation . . . . . . . . . . . . . .      1,118,654       1,074,588

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      1,910,086       1,901,522



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         67,941          33,235



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          6,505          12,626
  Accounts Receivable (net). . . . . . . . . . . . . .        129,936         110,969
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         15,856          19,549
  Materials and Supplies . . . . . . . . . . . . . . .         30,442          27,628
  Accrued Utility Revenues . . . . . . . . . . . . . .         50,537          51,765
  Prepayments. . . . . . . . . . . . . . . . . . . . .         34,219          30,397

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        267,495         252,934


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        351,571         359,481


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         21,658          66,688


            TOTAL. . . . . . . . . . . . . . . . . . .     $2,618,751      $2,613,860

See Notes to Consolidated Financial Statements.

             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                          September 30,   December 31,
                                                              1998            1997
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  24,000,000 Shares
    Outstanding - 16,410,426 Shares. . . . . . . . . .     $   41,026      $   41,026
  Paid-in Capital. . . . . . . . . . . . . . . . . . .        572,397         572,112
  Retained Earnings. . . . . . . . . . . . . . . . . .        191,269         138,172
          Total Common Shareholder's Equity. . . . . .        804,692         751,310
  Cumulative Preferred Stock - Subject to
    Mandatory Redemption . . . . . . . . . . . . . . .         25,000          25,000
  Long-term Debt . . . . . . . . . . . . . . . . . . .        959,651         887,850

          TOTAL CAPITALIZATION . . . . . . . . . . . .      1,789,343       1,664,160


OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .         46,028          42,271

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .           -             81,750
  Short-term Debt. . . . . . . . . . . . . . . . . . .         55,350          66,600
  Accounts Payable . . . . . . . . . . . . . . . . . .         52,053          71,287
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         95,052         131,107
  Interest Accrued . . . . . . . . . . . . . . . . . .         24,227          14,198
  Other. . . . . . . . . . . . . . . . . . . . . . . .         42,908          28,972

          TOTAL CURRENT LIABILITIES. . . . . . . . . .        269,590         393,914

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        436,168         433,593

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .         50,272          52,934

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .         27,350          26,988

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .     $2,618,751      $2,613,860

See Notes to Consolidated Financial Statements.

             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
                                                                 Nine Months Ended
                                                                    September 30,
                                                                1998            1997
                                                                   (in thousands)
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 116,678      $  98,242
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .     68,617         67,978
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     12,398           (741)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (2,662)        (2,705)
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . .    (10,169)        (4,089)
    Amortization of Zimmer Plant Operating Expenses and
      Carrying Charges . . . . . . . . . . . . . . . . . . .       -            15,936
    Amortization of Deferred Property Taxes. . . . . . . . .     48,775         48,601
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (18,967)       (52,786)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .        879          1,364
    Accrued Utility Revenues . . . . . . . . . . . . . . . .      1,228        (14,057)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (19,234)         2,008
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (36,055)       (50,645)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .     10,029         12,707
    Other Current Assets and Current Liabilities . . . . . .     10,114          5,350
  Payment of Disputed Tax and Interest Related to COLI . . .    (37,243)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     16,799         (9,827)
        Net Cash Flows From Operating Activities . . . . . .    161,187        117,336

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .    (84,178)       (82,696)
  Proceeds from Sale of Property and Other . . . . . . . . .      2,546          1,586
        Net Cash Flows Used For Investing Activities . . . .    (81,632)       (81,110)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    111,075         38,574
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (11,250)        42,925
  Retirement of Cumulative Preferred Stock . . . . . . . . .       -           (52,953)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (122,206)          -
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (61,983)       (59,013)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,312)        (2,297)
        Net Cash Flows Used For Financing Activities . . . .    (85,676)       (32,764)

Net Increase (Decrease) in Cash and Cash Equivalents . . . .     (6,121)         3,462
Cash and Cash Equivalents at Beginning of Period . . . . . .     12,626          9,134
Cash and Cash Equivalents at End of Period . . . . . . . . .  $   6,505      $  12,596

Supplemental Disclosure:
  Cash paid for  interest net  of capitalized amounts was  $46,014,000 and $43,341,000
  and for income taxes was $27,254,000 and $50,609,000 in 1998 and 1997, respectively.
  Noncash acquisitions  under capital leases  were $10,029,000 and  $6,583,000 in 1998
  and 1997, respectively.

See Notes to Consolidated Financial Statements.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)

1. GENERAL

The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods.

2. FINANCING ACTIVITIES

During the first nine months of 1998 the Company redeemed $57 million of 9.15% and $25 million of 7.00% first mortgage bonds at maturity and $40 million of 7.95% first mortgage bonds due 2002 and issued $52 million of 6.51% and $60 million of 6.55% senior unsecured notes due in 2008.

3. NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income.

In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition.

4. POWER MARKETING AND TRADING

During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's

knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands.

The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $190 million.

The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside the traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $40 million for sales and approximately $25 million for purchases.

Dependent on future electricity market conditions these activities could produce material income or losses in future periods.

5. CONTINGENCIES

Taxes

As discussed in Note 8, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below)

this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of COLI interest deductions through September 30, 1998 would reduce earnings by approximately $42 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.

In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998, the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.

Revised Air Quality Standards

The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.

On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.

Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in

imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.

Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $140 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.

Other

The Company continues to be involved in certain other matters discussed in its 1997 Annual Report.

                                    Increase (Decrease)
                             Third Quarter        Year-to-Date
                           (in millions)   %   (in millions)   %

Operating Revenues. . . . .    $530.0    169       $870.5    103
Fuel Expense. . . . . . . .      (2.6)    (5)         9.3      7
Purchased Power Expense . .     507.4    N.M.       834.3    N.M.
  Net Revenues. . . . . . .      25.2                26.9
Other Operation Expense . .      13.0     28         18.6     14
Maintenance Expense . . . .      (3.6)   (21)        (7.5)   (15)
Amortization of Zimmer
  Plant Phase-in Costs. . .       -       -         (15.7)   N.M.
Federal Income Taxes. . . .      7.0      28         12.1     21
Nonoperating Income . . . .     (3.0)    N.M.        (3.1)  (155)

N.M. = Not Meaningful

Operating revenues increased significantly in both the third quarter and the year-to-date period due predominantly to increased retail and wholesale sales. The increase in retail revenues resulted from increased sales to residential customers reflecting warmer summer weather in 1998. Revenues from wholesale customers increased reflecting substantial increases in power marketing and trading transactions.
The increase in fuel expense for the year-to-date period was due to an increase in generation reflecting the increase in demand for electricity.
Purchased power expense increased primarily as a result of increased power marketing and trading activities.

Net revenues increased $25.2 million in the third quarter and $26.9 million in the year-to-date period due to increased retail sales reflecting warmer summer weather and the successful trading of wholesale energy in a volatile market.
The increase in other operation expense was mainly due to costs related to the increase in sales including increased emission allowance consumption, transmission costs and employee pensions and benefits expense.
Maintenance expense decreased due to the effect of scheduled power plant maintenance outages in 1997 and a decline in overhead line maintenance expenditures in 1998. In 1997 two generating units underwent a scheduled outage for inspection and repairs while in 1998 only one unit had a scheduled outage for inspection and repairs. Expenditures for overhead line maintenance declined in 1998 as a result of lower expenditures for tree trimming and repair of conductors and pole attachments.
The reduction in the amortization of deferred Zimmer Plant phase-in costs reflects the completion of the surcharge recovery plan and the amortization of the original deferral in June 1997. The cessation of the amortization did not affect net income since the amortization was being recovered in revenues through a surcharge which terminated with the completion of the amortization.
Federal income taxes attributable to operations increased primarily due to an increase in pre-tax operating income.
The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger.

              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
                                          Three Months Ended          Nine Months Ended
                                             September 30,              September 30,
                                           1998        1997           1998         1997
                                                         (in thousands)
OPERATING REVENUES . . . . . . . . . . . $945,474    $362,058      $1,978,907  $1,023,879

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   51,014      62,275         133,768     176,051
  Purchased Power. . . . . . . . . . . .  625,294      54,043       1,126,651     124,216
  Other Operation. . . . . . . . . . . .   97,985      80,399         257,268     240,310
  Maintenance. . . . . . . . . . . . . .   39,107      29,408          99,444      85,103
  Depreciation and Amortization. . . . .   36,380      35,271         108,407     105,395
  Amortization of Rockport Plant Unit 1
    Phase-in Plan Deferrals. . . . . . .     -          2,999            -         10,821
  Taxes Other Than Federal Income Taxes.   16,514      15,781          49,011      49,657
  Federal Income Taxes . . . . . . . . .   20,541      21,433          52,157      61,843
          TOTAL OPERATING EXPENSES . . .  886,835     301,609       1,826,706     853,396
OPERATING INCOME . . . . . . . . . . . .   58,639      60,449         152,201     170,483
NONOPERATING INCOME (LOSS) . . . . . . .   (2,404)        499             191       1,464
INCOME BEFORE INTEREST CHARGES . . . . .   56,235      60,948         152,392     171,947
INTEREST CHARGES . . . . . . . . . . . .   17,544      15,857          51,421      48,689
NET INCOME . . . . . . . . . . . . . . .   38,691      45,091         100,971     123,258
PREFERRED STOCK DIVIDEND REQUIREMENTS. .    1,208       1,219           3,627       4,544
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 37,483    $ 43,872      $   97,344    $118,714



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended          Nine Months Ended
                                             September 30,              September 30,
                                           1998        1997           1998        1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $279,943    $285,783       $278,814    $269,071
NET INCOME . . . . . . . . . . . . . . .   38,691      45,091        100,971     123,258
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   29,366      44,066         88,098     102,196
    Cumulative Preferred Stock . . . . .    1,183       1,186          3,550       3,573
  Capital Stock Expense. . . . . . . . .       25          33             77         971

BALANCE AT END OF PERIOD . . . . . . . . $288,060    $285,589       $288,060    $285,589

The common stock of the Company is wholly owned
by American Electric Power Company, Inc.

See Notes to Consolidated Financial Statements.

              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                          September 30,   December 31,
                                                              1998            1997
                                                                 (in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,555,893      $2,545,484
  Transmission . . . . . . . . . . . . . . . . . . . .        912,155         908,736
  Distribution . . . . . . . . . . . . . . . . . . . .        756,348         737,902
  General (including nuclear fuel) . . . . . . . . . .        229,589         233,888
  Construction Work in Progress. . . . . . . . . . . .        129,122          88,487
          Total Electric Utility Plant . . . . . . . .      4,583,107       4,514,497
  Accumulated Depreciation and Amortization. . . . . .      2,049,510       1,973,937

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,533,597       2,540,560

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
 DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . . . .        627,792         566,390

OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        211,848         156,085



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         10,838           5,860
  Accounts Receivable. . . . . . . . . . . . . . . . .        171,428         137,310
  Allowance For Uncollectible Accounts . . . . . . . .         (1,978)         (1,188)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         15,985          17,182
  Materials and Supplies . . . . . . . . . . . . . . .         80,206          78,701
  Accrued Utility Revenues . . . . . . . . . . . . . .         40,378          30,521
  Prepayments. . . . . . . . . . . . . . . . . . . . .          7,821           4,828

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        324,678         273,214




REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        413,799         400,489

DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         30,583          31,060



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,142,297      $3,967,798

See Notes to Consolidated Financial Statements.

              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                         September 30,    December 31,
                                                              1998            1997
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  2,500,000 Shares
    Outstanding - 1,400,000 Shares . . . . . . . . . .    $   56,584       $   56,584
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       732,573          732,472
  Retained Earnings. . . . . . . . . . . . . . . . . .       288,060          278,814
          Total Common Shareholder's Equity. . . . . .     1,077,217        1,067,870
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         9,346            9,435
    Subject to Mandatory Redemption. . . . . . . . . .        68,445           68,445
  Long-term Debt . . . . . . . . . . . . . . . . . . .     1,124,961        1,014,237

          TOTAL CAPITALIZATION . . . . . . . . . . . .     2,279,969        2,159,987

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .       440,447          381,016
  Other. . . . . . . . . . . . . . . . . . . . . . . .       236,876          232,667

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .       677,323          613,683

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .          -              35,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .       103,500          119,600
  Accounts Payable . . . . . . . . . . . . . . . . . .        79,011           68,394
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        43,615           46,850
  Interest Accrued . . . . . . . . . . . . . . . . . .        16,081           15,741
  Rent Accrued - Rockport Plant Unit 2 . . . . . . . .        23,427            4,963
  Obligations Under Capital Leases . . . . . . . . . .        32,976           34,033
  Other. . . . . . . . . . . . . . . . . . . . . . . .        79,289           58,548

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       377,899          383,129

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       559,596          559,708

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       132,318          138,045

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .        89,639           92,419

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        25,553           20,827

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .    $4,142,297       $3,967,798

See Notes to Consolidated Financial Statements.

              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
                                                                 Nine Months Ended
                                                                    September 30,
                                                                 1998           1997
                                                                   (in thousands)
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 100,971      $ 123,258
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    111,510        111,176
    Amortization of Rockport Plant Unit 1
      Phase-in Plan Deferrals. . . . . . . . . . . . . . . .       -            10,821
    Deferral of Incremental Nuclear Refueling
      Outage Expenses (net). . . . . . . . . . . . . . . . .     11,368         (2,402)
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     11,226         (9,753)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (5,727)        (5,906)
    Under-recovery of Fuel and Purchased Power . . . . . . .    (42,676)        (9,554)
   Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (33,328)         7,029
    Fuel, Materials and Supplies . . . . . . . . . . . . . .       (308)         8,705
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     (9,857)         7,284
    Accounts Payable . . . . . . . . . . . . . . . . . . . .     10,617        (36,462)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     (3,235)       (13,615)
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464         18,464
  Payment of Disputed Tax and Interest Related to COLI . . .    (53,628)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     24,237         26,966
        Net Cash Flows From Operating Activities . . . . . .    139,634        236,011

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .    (98,218)       (79,066)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      4,154          1,798
        Net Cash Flows Used For Investing Activities . . . .    (94,064)       (77,268)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    122,222         47,728
  Retirement of Cumulative Preferred Stock . . . . . . . . .        (65)       (78,838)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (55,000)       (50,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (16,100)        14,350
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (88,098)       (87,195)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (3,551)        (4,746)
        Net Cash Flows Used For Financing Activities . . . .    (40,592)      (158,701)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .      4,978             42
Cash and Cash Equivalents at Beginning of Period . . . . . .      5,860          8,233
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  10,838      $   8,275

Supplemental Disclosure:
  Cash paid  for interest  net of capitalized amounts was  $49,041,000 and $44,575,000
  and for income taxes was $20,224,000 and $83,580,000 in 1998 and 1997, respectively.
  Noncash acquisitions under  capital leases  were $7,050,000 and  $80,231,000 in 1998
  and 1997, respectively.

See Notes to Consolidated Financial Statements.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)

1. GENERAL

The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods.

2. FINANCING ACTIVITIES

In 1998 the Company redeemed $35 million of 7.00% first mortgage bonds at maturity and $20 million of 7.80% first mortgage bonds due 2023 at face value. In May 1998 $125 million of 7.60% junior subordinated deferrable interest debentures due 2038 were issued.

3. NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there are no material differences between comprehensive income and net income.

In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition.

4. POWER MARKETING AND TRADING

During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's

knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands.

The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $200 million.

The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998 the Company's share of the unrealized mark-to-market gains and losses of such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $45 million for sales and approximately $30 million for purchases.

Dependent on future electricity market conditions these activities could produce material income or losses in future periods.

5. CONTINGENCIES

Taxes

As discussed in Note 7, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below)

this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $64 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.

In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.

Cook Nuclear Plant Shutdown

As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1997 Annual Report, both units of the Cook Nuclear Plant were shut down by the Company in September 1997 due to questions regarding the operability of certain safety systems, which arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address the issues identified in the letter. The Company is working with the NRC to resolve a remaining issue in the letter.

On April 17, 1998, the NRC notified the Company that it had convened a Restart Panel for the Cook Plant. On July 30, 1998, the Company received a letter from the NRC providing the NRC's list of required restart activities. The Company is and will be meeting with the Panel on a regular basis, until the Cook Plant units are returned to service, to identify and address the issues necessary for the restart of the units. When maintenance and other activities required for restart are complete, the Company will seek concurrence from the NRC to return the Cook Plant to service.

The current restart schedule indicates Unit 1 is expected to return to service by the end of the first quarter of 1999. The restart schedule for Unit 2 has not been completed; however, management anticipates that Unit 2 may return to service 90 days after Unit 1. If the units are not returned to service, there could be a material adverse effect on financial condition.

The incremental cost expected to be incurred to restart the Cook units is approximately $70 million for 1998, of which $34 million has been incurred through September 30, 1998. However, approximately $20 million of previously budgeted work for 1998 at the Cook Plant will not be incurred and will partially mitigate the incremental restart costs. The cost and schedule for the outage during 1999 could be significantly impacted if additional work is identified beyond the $35 million planned for the first quarter.

On July 24, 1998, the Company received an "adverse trend letter" from the NRC indicating that NRC senior managers had determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities.

In a letter dated October 13, 1998, the NRC issued to the Company a Notice of Violation and proposed $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 4, 1997 and April 15, 1998. The Company paid the penalty.

The cost of electricity supplied to retail customers rose due to the outage of the two units since higher cost coal-fired generation and purchased power were substituted for low cost nuclear generation. In the Indiana and Michigan retail jurisdictions fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under the fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor as was the case with regard to Cook, a regulatory asset is recorded and revenues are accrued.

Due to the unscheduled Cook Plant outage, the Company's actual fuel costs significantly exceeded the estimated fuel costs reflected in its fuel cost adjustment factors. A regulatory asset has been recorded for revenues accrued in anticipation of future reconciliation and billing of the higher fuel costs to customers. At September 30, 1998, the regulatory asset was $61 million.

The Indiana Utility Regulatory Commission approved two agreements authorizing the Company during the billing months of July through December 1998 to apply a fuel cost adjustment factor less than that requested by the Company, subject to future reconciliation or refund. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the recovery of replacement energy cost due to the extended Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that the Company should be able to recover the Cook replacement energy costs; however, if recovery of the replacement costs is denied, results of operations and cash flows would be adversely affected.

Revised Air Quality Standards

The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.

On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.

Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA

in the event the states fail to implement SIPs in accordance with the final rules.

Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $169 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition

Other

The Company continues to be involved in certain other matters discussed in its 1997 Annual Report.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997

RESULTS OF OPERATIONS
Despite substantial increases in operating revenues due to increased retail sales and power marketing and trading activities, net income decreased $6.4 million or 14% for the quarter and $22.3 million or 18% for the year-to-date period. The decreases in net income are due primarily to increased costs related to an extended Cook Nuclear Plant outage, increased purchased power costs, losses on certain energy trades outside AEP's traditional market area and a decrease in capacity credits from the AEP System Power Pool (Power Pool). Under the terms of the Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the Power Pool members based on their relative peak demands and generating reserves. The reduction in capacity credits received can be attributed to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all Power Pool members.
As discussed in Note 5 of the Notes to Consolidated Financial Statements, the Cook Nuclear Plant was shut down in September 1997. The shutdown has had a significant impact on the operations of the Company as reflected in the variations of certain income statement line items discussed below.
Income statement line items which changed significantly were:

                                    Increase (Decrease)
                             Third Quarter         Year-to-Date
                          (in millions)   %     (in millions)  %

Operating Revenues . . . .   $583.4     161       $  955.0    93
Fuel Expense . . . . . . .    (11.3)    (18)         (42.3)  (24)
Purchased Power Expense. .    571.3     N.M.       1,002.4   N.M.
Other Operation Expense. .     17.6      22           17.0     7
Maintenance Expense. . . .      9.7      33           14.3    17
Amortization of Rockport
 Plant Unit 1 Phase-in
 Plan Deferrals. . . . . .     (3.0)    N.M.         (10.8)  N.M.
Federal Income Taxes . . .     (0.9)     (4)          (9.7)  (16)
Nonoperating Income. . . .     (2.9)    N.M.          (1.3)  (87)

N.M. = Not Meaningful

Operating revenues increased significantly in both periods due predominantly to an increase in sales to retail and wholesale customers. The increase in retail revenues can be attributed to increased energy sales to all retail customer classes reflecting warmer summer weather and increased industrial customer usage. Fuel and power supply cost recovery accruals also contributed to the increase in retail revenues. Under the fuel cost recovery mechanism, revenues are accrued to match increased fuel expense in both of the Company's retail jurisdictions and for replacement power costs in the Michigan jurisdiction. The fuel and purchased power costs incurred are subsequently reviewed by the commissions and, if acceptable, approved for recovery through billings. During the extended outage of both nuclear units, retail revenues increased from the accrual of revenues to match the increased fuel costs and purchase power expense incurred to replace the unavailable lower cost nuclear power.
Revenues from wholesale customers increased reflecting growth in power marketing and trading activities.
Fuel expense decreased significantly in both periods due to a decline in nuclear generation reflecting the outages of both nuclear units in 1998.
The significant increase in purchased power expense for both periods was the result of purchases for the power marketing and trading business and additional energy purchases from the Power Pool due to the unavailability of the nuclear units.
Other operation expense increased for both periods as a result of costs associated with the extended Cook Plant outage and increased incentive pay accruals.
The increase in maintenance expense for both periods was the result of additional expenditures to prepare the nuclear units for restart.
The recovery periods for Rockport Plant Unit 1 costs deferred under a rate phase-in plan in the Indiana and FERC jurisdictions ended in the fall of 1997 causing the decrease in amortization of phase-in plan deferrals. The deferred costs were amortized over a 10-year period commensurate with their collection from customers pursuant to commission orders. The Company has increased its

decommissioning expense accruals (approximately $12 million through September 30, 1998), pending approval from the Indiana Utility Regulatory Commission (IURC), in an amount equal to the continuing phase-in plan revenues. On November 12, 1998 the IURC issued an order that denied the Company's request to increase its decommissioning accruals and requires the Company to submit revised quarterly net operating income calculations for each quarter subsequent to August 1997. The Company will be making the revised calculations and under the worst case scenario there would be no favorable impact on results of operations.
Federal income taxes attributable to operations decreased for the year-to-date period as a result of a decrease in pre-tax operating income.
The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the year-to-date period were $106 million. During the first nine months of 1998 short-term debt outstanding decreased by $16 million.
During the first nine months of 1998 the Company redeemed two series of first mortgage bonds; $35 million at 7.00% at maturity and $20 million at 7.80% due 2023, and issued $125 million of 7.60% junior subordinated deferrable interest debentures due 2038.
COOK NUCLEAR PLANT SHUTDOWN
As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1997 Annual Report, both units of the Cook Nuclear Plant were shut down by the Company in September 1997 due to questions regarding the operability of certain safety systems, which arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. The NRC issued a Confirmatory Action

Letter in September 1997 requiring the Company to address the issues identified in the letter. The Company is working with the NRC to resolve a remaining issue in the letter.
On April 17, 1998, the NRC notified the Company that it had convened a Restart Panel for the Cook Plant. On July 30, 1998, the Company received a letter from the NRC providing the NRC's list of required restart activities. The Company is and will be meeting with the Panel on a regular basis, until the Cook Plant units are returned to service, to identify and address the issues necessary for the restart of the units. When maintenance and other activities required for restart are complete, the Company will seek concurrence from the NRC to return the Cook Plant to service.
The current restart schedule indicates Unit 1 is expected to return to service by the end of the first quarter of 1999. The restart schedule for Unit 2 has not been completed; however, management anticipates that Unit 2 may return to service 90 days after Unit 1. If the units are not returned to service, there could be a material adverse effect on financial condition.
The incremental cost expected to be incurred to restart the Cook units is approximately $70 million for 1998, of which $34 million has been incurred through September 30, 1998. However, approximately $20 million of previously budgeted work for 1998 at the Cook Plant will not be incurred and will partially mitigate the incremental restart costs. The cost and schedule for the outage during 1999 could be significantly impacted if additional work is identified beyond the $35 million planned for the first quarter.
On July 24, 1998, the Company received an "adverse trend letter" from the NRC indicating that NRC senior managers had determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities.

In a letter dated October 13, 1998, the NRC issued to the Company a Notice of Violation and proposed $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 4, 1997 and April 15, 1998. The Company paid the penalty.
As a result of the extended outage, the cost of electricity supplied to retail customers increased since higher cost coal-fired generation and purchased power were substituted for low cost nuclear generation. In the Indiana and Michigan retail jurisdictions fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under the fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor, a regulatory asset is recorded and revenues are accrued.
Due to the unscheduled Cook Plant outage, the Company's actual fuel costs significantly exceeded the estimated fuel costs reflected in its fuel cost adjustment factors. A regulatory asset has been recorded for revenues accrued in anticipation of future reconciliation and billing of the higher fuel costs to customers. At September 30, 1998, the regulatory asset was $61 million.
The IURC approved two agreements authorizing the Company during the billing months of July through December 1998 to apply a fuel cost adjustment factor less than that requested by the Company, subject to future reconciliation or refund. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the recovery of replacement energy cost due to the Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that the Company should be able to recover the Cook replacement costs; however, if recovery of the replacement costs is denied,

results of operations and cash flows would be adversely affected.
The timetable for the return to service of the Cook Plant constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, other unforeseen issues encountered in preparing the Cook Plant for restart and the unpredictability of the NRC regulatory process.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and

could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $169 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.
POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the Power Pool, substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands.
The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $200 million.

The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998 the Company's share of the unrealized mark-to-market gains and losses of such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $45 million for sales and approximately $30 million for purchases.
Dependent on future electricity market conditions these activities could produce material income or losses in future periods.
TAXES
As discussed in Note 7, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $64 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.

In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Year 2000 ready programs.

Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of

the external evaluation, the Company has sought written assurances from third parties regarding their state of Year 2000 readiness.
Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. AEP, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30, 1999 to June 30, 1999.
Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans.
Various state regulatory commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction.

Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, communications, and the physical generation and delivery of energy; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g. payroll, procurement, accounts

payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations.
The following chart shows our progress toward becoming ready for the Year 2000 as of September 30, 1998:

                             IT SYSTEMS         NON-IT  SYSTEMS
                     COMPLETION                 COMPLETION
                     DATE/ESTIMATED     PERCENT     DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of       2/24/1998     100%         5/31/1998     100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment:
Identifying all Company     7/31/1998     100%         11/30/1998    86%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,       6/30/1999     Mainframe     6/30/1999     2%
replacing or retiring                     60%
those mission critical and
high priority digital-based
systems with problems                     Client
processing dates past the                 Server:
Year 2000. Testing these                  1%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

Costs to Address the Company's Year 2000 Issues - Through September 30, 1998, the Company has spent $3 million on the Year 2000 project and, estimates spending an additional $7 million to $10 million to achieve Year 2000 readiness. Most Year 2000 costs are software, IT consultant and salary-related and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial

condition.
Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 problems are:
* Automated power generation, transmission and distribution systems
* Telecommunications systems
* Energy trading systems
* Time-in-use, demand and remote metering systems for commercial and industrial customers
* Work management and billing systems.

The potential problems related to erroneous processing by, or failure of, these systems are:
* Power service interruptions to customers
* Interrupted revenue data gathering and collection
* Poor customer relations resulting from delayed billing and settlement.

In addition, although as discussed the Company is monitoring its relationships with third parties, such as suppliers, customers and other electric utilities, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others not affiliated with AEP, fail for critical applications, Year 2000-related issues may materially adversely affect AEP.

Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster

recovery, system restoration, and contingency planning that we now have in place. We have begun the contingency planning process, including the review of NERC's Contingency Planning Guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999.

Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others:
* Continuing availability of experienced consultants and IT personnel and related resources
* Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness
* Ability of the Company to identify and implement contingency plans.

                          KENTUCKY POWER COMPANY
                           STATEMENTS OF INCOME
                                (UNAUDITED)
                                           Three Months Ended        Nine Months Ended
                                              September 30,            September 30,
                                             1998        1997        1998         1997
                                                          (in thousands)
OPERATING REVENUES . . . . . . . . . . . . $282,319    $89,791     $571,743     $256,472

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .   21,478     20,020       61,963       58,647
  Purchased Power. . . . . . . . . . . . .  208,945     28,632      375,333       73,775
  Other Operation. . . . . . . . . . . . .   13,647     13,241       36,633       37,130
  Maintenance. . . . . . . . . . . . . . .    7,335      6,148       23,759       16,826
  Depreciation and Amortization. . . . . .    7,068      6,649       20,956       19,708
  Taxes Other Than Federal Income Taxes. .    2,668      2,427        7,420        7,266
  Federal Income Taxes . . . . . . . . . .    4,627      1,837        7,406        7,614

         TOTAL OPERATING EXPENSES. . . . .  265,768     78,954      533,470      220,966

OPERATING INCOME . . . . . . . . . . . . .   16,551     10,837       38,273       35,506

NONOPERATING LOSS. . . . . . . . . . . . .     (902)       (62)      (1,066)        (351)

INCOME BEFORE INTEREST CHARGES . . . . . .   15,649     10,775       37,207       35,155

INTEREST CHARGES . . . . . . . . . . . . .    7,207      6,323       21,335       18,431

NET INCOME . . . . . . . . . . . . . . . . $  8,442    $ 4,452     $ 15,872     $ 16,724




                      STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                              September 30,            September 30,
                                             1998        1997        1998         1997
                                                          (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . $71,356     $82,982      $78,076      $84,090

NET INCOME . . . . . . . . . . . . . . . .   8,442       4,452       15,872       16,724

CASH DIVIDENDS DECLARED. . . . . . . . . .   7,075       6,690       21,225       20,070

BALANCE AT END OF PERIOD . . . . . . . . . $72,723     $80,744      $72,723      $80,744



The common stock of the Company is wholly owned by
American Electric Power Company, Inc.

See Notes to Financial Statements.

                          KENTUCKY POWER COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
                                                         September 30,    December 31,
                                                             1998             1997
                                                                (in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $  259,980      $  249,184
  Transmission . . . . . . . . . . . . . . . . . . . .        325,854         303,456
  Distribution . . . . . . . . . . . . . . . . . . . .        347,834         350,793
  General. . . . . . . . . . . . . . . . . . . . . . .         74,670          71,462
  Construction Work in Progress. . . . . . . . . . . .         24,167          32,060
          Total Electric Utility Plant . . . . . . . .      1,032,505       1,006,955
  Accumulated Depreciation and Amortization. . . . . .        310,083         296,318

          NET ELECTRIC UTILITY PLANT . . . . . . . . .        722,422         710,637

OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .         12,031           6,414

CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .            955           1,381
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         18,122          24,127
    Affiliated Companies . . . . . . . . . . . . . . .         11,469           1,722
    Miscellaneous. . . . . . . . . . . . . . . . . . .          4,221           3,276
    Allowance for Uncollectible Accounts . . . . . . .           (698)           (525)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .          9,300          10,685
  Materials and Supplies . . . . . . . . . . . . . . .         14,212          14,054
  Accrued Utility Revenues . . . . . . . . . . . . . .         11,587          12,981
  Other. . . . . . . . . . . . . . . . . . . . . . . .          3,568           1,715

          TOTAL CURRENT ASSETS . . . . . . . . . . . .         72,736          69,416


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .         91,502          90,045

DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .          6,788          10,159

            TOTAL. . . . . . . . . . . . . . . . . . .     $  905,479      $  886,671

See Notes to Financial Statements.

                          KENTUCKY POWER COMPANY
                              BALANCE SHEETS
                                (UNAUDITED)
                                                          September 30,   December 31,
                                                              1998            1997
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
  Common Stock - $50 Par Value:
    Authorized -  2,000,000 Shares
    Outstanding - 1,009,000 Shares . . . . . . . . . .      $ 50,450        $ 50,450
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       138,750         128,750
  Retained Earnings. . . . . . . . . . . . . . . . . .        72,723          78,076
          Total Common Shareholder's Equity. . . . . .       261,923         257,276
  Long-term Debt . . . . . . . . . . . . . . . . . . .       313,979         341,051

          TOTAL CAPITALIZATION . . . . . . . . . . . .       575,902         598,327

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        28,124          26,544

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .        25,000            -
  Short-term Debt. . . . . . . . . . . . . . . . . . .        49,350          36,500
  Accounts Payable . . . . . . . . . . . . . . . . . .        20,817          24,574
  Customer Deposits. . . . . . . . . . . . . . . . . .         3,999           3,660
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         4,937           6,130
  Interest Accrued . . . . . . . . . . . . . . . . . .         8,097           6,015
  Other. . . . . . . . . . . . . . . . . . . . . . . .        18,069          15,084

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       130,269          91,963

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       155,655         153,945

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        14,700          15,615

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .           829             277

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .      $905,479        $886,671

See Notes to Financial Statements.

                          KENTUCKY POWER COMPANY
                         STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
                                                                Nine Months Ended
                                                                  September 30,
                                                                1998          1997
                                                                  (in thousands)
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 15,872      $ 16,724
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    20,966        19,718
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     1,173           163
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (915)         (924)
    Amortization of Deferred Property Taxes. . . . . . . . .     3,840         3,690
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (4,514)         (305)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     1,227          (113)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     1,394         1,712
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (3,757)       (9,040)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (1,193)       (1,237)
  Payment of Disputed Taxes and Interest Related to COLI . .    (5,376)         -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     1,952         5,301
        Net Cash Flows From Operating Activities . . . . . .    30,669        35,689

INVESTING ACTIVITIES - Construction Expenditures . . . . . .   (30,517)      (45,023)

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .    10,000        10,000
  Change in Short-term Debt (net). . . . . . . . . . . . . .    12,850        19,775
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (2,203)         -
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .   (21,225)      (20,070)
        Net Cash Flows From (Used For) Financing Activities.      (578)        9,705

Net Increase (Decrease) in Cash and Cash Equivalents . . . .      (426)          371
Cash and Cash Equivalents at Beginning of Period . . . . . .     1,381         1,106
Cash and Cash Equivalents at End of Period . . . . . . . . .  $    955      $  1,477

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was  $18,950,000 and $16,950,000
  and for income taxes was $5,812,000 and $8,115,000 in 1998 and 1997, respectively.
  Noncash acquisitions under capital leases  were $4,448,000 and $3,571,000  in 1998
  and 1997, respectively.

See Notes to Financial Statements.

KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)

1. GENERAL

The accompanying unaudited financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods.

2. FINANCING ACTIVITIES

The Company received from its parent a cash capital contribution of $10 million in June 1998 which was credited to paid-in capital.

3. NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income.

In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition.

4. POWER MARKETING AND TRADING

During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are

shared by the Power Pool members based on their relative peak demands.

The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $70 million.

The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating loss. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $15 million for sales and approximately $10 million for purchases.

Dependent on future electricity market conditions these activities could produce material income or losses in future periods.

5. CONTINGENCIES

Taxes

As discussed in Note 8, "Federal Income Taxes" of the Notes to Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1992-96. A disallowance of COLI interest deductions

through September 30, 1998 would reduce earnings by approximately $7 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.

In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1992-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.

Revised Air Quality Standards

The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.

On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.

Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA

in the event the states fail to implement SIPs in accordance with the final rules.

Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $105 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.

Other

The Company continues to be involved in certain other matters discussed in its 1997 Annual Report.

KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997

Net income increased $4 million or 90% for the quarter and decreased $0.9 million or 5% for the year-to-date period. The increase in net income for the quarter is attributable to an increase in retail and wholesale revenues reflecting increased sales. The decline in year-to-date net income is due to increased maintenance and interest costs.
The significant changes in income statement line items and net revenues were:

                                    Increase (Decrease)
                            Third Quarter        Year-to-Date
                          (in millions)  %   (in millions)    %

Operating Revenues. . . . .  $192.5     214     $315.3       123
Fuel Expense. . . . . . . .     1.5       7        3.3         6
Purchased Power Expense . .   180.3     N.M.     301.6       409
  Net Revenues                 10.7               10.4
Maintenance Expense . . . .     1.2      19        6.9        41
Depreciation and
  Amortization. . . . . . .     0.4       6        1.2         6
Federal Income Taxes. . . .     2.8     152       (0.2)       (3)
Nonoperating Loss . . . . .    (0.8)    N.M.      (0.7)      N.M.
Interest Charges. . . . . .     0.9      14        2.9        16

N.M. = Not Meaningful

The substantial increases in operating revenues for the third quarter and year-to-date periods were due primarily to increased sales volume. Retail revenues increased 4% in the third quarter and 2% year-to-date reflecting the impact of warmer summer weather on retail usage. Wholesale revenues increased in both periods due to growth in the power marketing and trading business which contributed substantially to an increase in wholesale sales.
Fuel expense increased due to additional generation to meet the increase in demand and an increase in the cost of coal.
The significant increase in purchased power expense resulted from the growth of the power marketing and trading business.

Net revenues increased $10.7 million in the third quarter and $10.4 million in the year-to-date period due to increased retail sales reflecting the impact of warmer summer weather and the successful trading of wholesale energy in a volatile market.
The increase in maintenance expense in both periods reflects the effects of scheduled steam plant maintenance work in 1998 at the Company's Big Sandy Plant and, for the year-to-date period, expenditures for repair and restoration of distribution service caused by two severe snowstorms.
Depreciation and amortization expense increased due to additional investment in depreciable plant reflecting improvements to the transmission and distribution systems completed during 1997.
The increase in federal income taxes for the third quarter resulted from an increase in pre-tax operating income.
Nonoperating income declined due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger.
The increase in interest charges reflects an increase in outstanding long-term debt due to the issuance of Senior Unsecured Notes in October 1997.

                    OHIO POWER COMPANY AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF INCOME
                                (UNAUDITED)
                                          Three Months Ended         Nine Months Ended
                                             September 30,             September 30,
                                           1998        1997          1998         1997
                                                         (in thousands)
OPERATING REVENUES . . . . . . . . . . . $1,361,336  $486,398     $2,901,072   $1,417,845
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    199,934   156,482        574,156      462,720
  Purchased Power. . . . . . . . . . . .    824,021    37,270      1,392,404       69,738
  Other Operation. . . . . . . . . . . .     96,254    78,623        260,097      240,182
  Maintenance. . . . . . . . . . . . . .     34,900    39,443         98,651      102,292
  Depreciation and Amortization. . . . .     36,236    35,323        108,097      105,351
  Taxes Other Than Federal Income Taxes.     42,931    42,938        127,451      126,801
  Federal Income Taxes . . . . . . . . .     38,222    27,203        102,444       92,022

          TOTAL OPERATING EXPENSES . . .  1,272,498   417,282      2,663,300    1,199,106
OPERATING INCOME . . . . . . . . . . . .     88,838    69,116        237,772      218,739
NONOPERATING INCOME (LOSS) . . . . . . .     (2,665)    2,273          2,022        9,803
INCOME BEFORE INTEREST CHARGES . . . . .     86,173    71,389        239,794      228,542
INTEREST CHARGES . . . . . . . . . . . .     20,212    20,718         60,338       61,961
NET INCOME . . . . . . . . . . . . . . .     65,961    50,671        179,456      166,581
PREFERRED STOCK DIVIDEND REQUIREMENTS. .        369       370          1,107        2,278
EARNINGS APPLICABLE TO COMMON STOCK. . . $   65,592  $ 50,301     $  178,349   $  164,303



               CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                (UNAUDITED)

                                          Three Months Ended         Nine Months Ended
                                             September 30,             September 30,
                                           1998        1997          1998         1997
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $597,357    $573,236     $590,151       $584,015
NET INCOME . . . . . . . . . . . . . . .   65,961      50,671      179,456        166,581
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   52,775      37,562      158,325        161,771
    Cumulative Preferred Stock . . . . .      369         370        1,108          2,829
  Capital Stock Expense. . . . . . . . .     -           -            -                21

BALANCE AT END OF PERIOD . . . . . . . . $610,174    $585,975     $610,174       $585,975

The common stock of the Company is wholly owned by
American Electric Power Company, Inc.

See Notes to Consolidated Financial Statements.

                    OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                          September 30,   December 31,
                                                              1998            1997
                                                                 (in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
  Production . . . . . . . . . . . . . . . . . . . . .     $2,636,368      $2,606,981
  Transmission . . . . . . . . . . . . . . . . . . . .        841,410         837,953
  Distribution . . . . . . . . . . . . . . . . . . . .        938,470         927,239
  General (including mining assets). . . . . . . . . .        686,593         709,475
  Construction Work in Progress. . . . . . . . . . . .        103,453          74,149
          Total Electric Utility Plant . . . . . . . .      5,206,294       5,155,797
  Accumulated Depreciation and Amortization. . . . . .      2,425,511       2,349,995

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,780,783       2,805,802


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        219,677         113,279


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         95,620          44,203
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .        329,254         196,982
    Affiliated Companies . . . . . . . . . . . . . . .         73,956          55,597
    Miscellaneous. . . . . . . . . . . . . . . . . . .         20,884          43,594
    Allowance for Uncollectible Accounts . . . . . . .         (1,838)         (2,501)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         87,763         119,543
  Materials and Supplies . . . . . . . . . . . . . . .         84,433          80,853
  Accrued Utility Revenues . . . . . . . . . . . . . .         43,900          37,586
  Prepayments. . . . . . . . . . . . . . . . . . . . .         37,905          37,257

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        771,877         613,114



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        528,068         523,891


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         46,127         107,116



            TOTAL. . . . . . . . . . . . . . . . . . .     $4,346,532      $4,163,202

See Notes to Consolidated Financial Statements.

                    OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEETS
                                (UNAUDITED)
                                                          September 30,   December 31,
                                                              1998            1997
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  40,000,000 Shares
    Outstanding - 27,952,473 Shares. . . . . . . . . .     $  321,201      $  321,201
  Paid-in Capital. . . . . . . . . . . . . . . . . . .        462,314         462,296
  Retained Earnings. . . . . . . . . . . . . . . . . .        610,174         590,151
          Total Common Shareholder's Equity. . . . . .      1,393,689       1,373,648
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         17,471          17,542
    Subject to Mandatory Redemption. . . . . . . . . .         11,850          11,850
  Long-term Debt . . . . . . . . . . . . . . . . . . .      1,027,587       1,012,031

          TOTAL CAPITALIZATION . . . . . . . . . . . .      2,450,597       2,415,071

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        315,114         295,375

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .         16,289          83,195
  Short-term Debt. . . . . . . . . . . . . . . . . . .         98,808          78,700
  Accounts Payable - General . . . . . . . . . . . . .        286,042         146,824
  Accounts Payable - Affiliated Companies. . . . . . .         44,392          37,923
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .        114,435         160,055
  Interest Accrued . . . . . . . . . . . . . . . . . .         22,165          16,255
  Obligations Under Capital Leases . . . . . . . . . .         27,994          30,307
  Other. . . . . . . . . . . . . . . . . . . . . . . .        114,733          94,829

          TOTAL CURRENT LIABILITIES. . . . . . . . . .        724,858         648,088

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .        723,718         723,172

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .         40,293          42,821

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .         91,952          38,675

CONTINGENCIES (Note 5)

            TOTAL. . . . . . . . . . . . . . . . . . .     $4,346,532      $4,163,202

See Notes to Consolidated Financial Statements.

                    OHIO POWER COMPANY AND SUBSIDIARIES
                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (UNAUDITED)
                                                                  Nine Months Ended
                                                                    September 30,
                                                                 1998           1997
                                                                    (in thousands)
OPERATING ACTIVITIES:
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 179,456      $ 166,581
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .    129,366        129,597
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     12,504             85
    Amortization of Deferred Property Taxes. . . . . . . . .     58,664         57,646
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (128,584)        (9,892)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     28,200         (5,112)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     (6,314)        10,044
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    145,687         34,712
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (45,620)       (80,111)
    Other Current Assets and Current Liabilities . . . . . .     22,853         31,267
  Payment of Disputed Tax and Interest Related to COLI . . .   (104,222)          -
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     68,381        (24,047)
        Net Cash Flows From Operating Activities . . . . . .    360,371        310,770

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (121,310)      (102,469)
  Proceeds from Sale of Property and Other . . . . . . . . .      4,348          8,553
        Net Cash Flows Used For Investing Activities . . . .   (116,962)       (93,916)

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    137,566        146,589
  Change in Short-term Debt (net). . . . . . . . . . . . . .     20,108         53,123
  Retirement of Cumulative Preferred Stock . . . . . . . . .        (52)      (117,601)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (190,181)      (119,542)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (158,325)      (161,771)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,108)        (2,829)
        Net Cash Flows Used For Financing Activities . . . .   (191,992)      (202,031)

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     51,417         14,823
Cash and Cash Equivalents at Beginning of Period . . . . . .     44,203         24,003
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  95,620      $  38,826

Supplemental Disclosure:
  Cash paid for  interest net  of capitalized amounts was  $52,523,000 and $54,010,000
  and for income taxes was $55,898,000 and $98,341,000 in 1998 and 1997, respectively.
  Noncash acquisitions  under capital leases  were $24,740,000 and $41,677,000 in 1998
  and 1997, respectively.

See Notes to Consolidated Financial Statements.

OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)

1. GENERAL

The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods.

2. FINANCING ACTIVITY

In April 1998 the Company issued $140 million of 7-3/8% senior unsecured notes due 2038. During the first nine months of 1998 the Company and a subsidiary retired $183 million of long-term debt: $56 million of 6-3/4% first mortgage bonds and $17 million of 6.85% notes payable at maturity and two series of $50 million first mortgage bonds due in 2002 with interest rates of 8.10% and 8.25% and $10 million of variable rate notes payable due in 1999.

As a result of the redemption of the 6-3/4% series first mortgage bonds due in 1998, the restriction on the use of retained earnings for the payment of common stock dividends was eliminated.

3. NEW ACCOUNTING STANDARDS

Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there are no material differences between comprehensive income and net income.

In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition.

4. POWER MARKETING AND TRADING

During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands.

The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $290 million.

The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside the traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $65 million for sales and approximately $40 million for purchases.

Dependent on future electricity market conditions these activities could produce material income or losses in future periods.

5. CONTINGENCIES

Taxes

As discussed in Note 8, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $115 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.

In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998 the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows.

Revised Air Quality Standards

The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.

On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission

levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules.

Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.

Based on initial studies, preliminary estimates indicate that compliance costs could result in required capital expenditures by the Company of approximately $452 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.

Other

The Company continues to be involved in certain other matters discussed in the 1997 Annual Report.

                                    Increase (Decrease)
                             Third Quarter       Year-to-Date
                          (in millions)   %   (in millions)    %

Operating Revenues. . . .    $874.9     180     $1,483.2     105
Fuel Expense. . . . . . .      43.5      28        111.4      24
Purchased Power . . . . .     786.8     N.M.     1,322.7     N.M.
  Net Revenues. . . . . .      44.6                 49.1
Other Operation Expense .      17.6      22         19.9       8
Maintenance Expense . . .      (4.5)    (12)        (3.6)     (4)
Federal Income Taxes. . .      11.0      41         10.4      11
Nonoperating Income . . .      (4.9)   (217)        (7.8)    (79)

N.M. = Not Meaningful

Operating revenues increased significantly in both the third quarter and year-to-date periods due predominantly to increased retail and wholesale sales. Retail sales increased 6% in the third quarter and 4% year-to-date reflecting warmer summer weather in 1998 and the resumption of operations by a major industrial customer following an extended labor strike. Operating revenues from wholesale sales increased significantly as a result of growth in power marketing and trading activities and increased sales to the AEP System Power Pool (Power Pool) to replace power previously generated at an affiliate's nuclear plant which was out of service.

The increases in fuel expense for the third quarter and year-to-date periods were mainly due to an increase in generation, reflecting the rise in demand and the replacement of energy previously supplied to the Power Pool by an affiliate's out-of-service nuclear plant, and an increase in the cost of fuel consumed.
Purchased power expense increased substantial for both periods primarily due to the growth of power marketing and trading activities.
The increase in net revenues of $45 million in the third quarter and $49 million in the year-to-date period reflects the impact of warmer summer weather and increased industrial usage on retail sales and the successful trading of wholesale energy in a volatile market.
Other operation expense increased in both periods primarily due to costs related to the increase in energy sales, employer pension and benefit expense, a reduction in gains on emission allowance sales and increased costs under the AEP System transmission equalization agreement. The transmission equalization agreement combines certain AEP System companies' investment in transmission facilities and shares the costs of ownership of those facilities in proportion to each AEP System company's peak demand relative to the peak demands of all AEP System companies utilizing the AEP System transmission system. The charges paid by the Company under the agreement increased due to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all transmission agreement members.
The decreases in maintenance expense for both periods were mainly due to decreased boiler plant maintenance reflecting a reduction in planned maintenance work on the Company's generating units.
Federal income taxes attributable to operations increased due to an increase in pre-tax operating income.

The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the first nine months of 1998 were $146 million.
During the first nine months of 1998, the Company and a subsidiary retired $183 million principal amount of long-term debt with interest rates ranging from 6.11% to 8.25%, issued $140 million of senior unsecured notes at an interest rate of 7-3/8% and increased short-term debt by $20 million.
As a result of the redemption of the 6-3/4% series first mortgage bonds due in 1998, the restriction on the use of retained earnings for the payment of common stock dividends was eliminated.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for

the District of Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that compliance costs could result in required capital expenditures by the Company of approximately $452 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Year 2000 ready programs.

Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Year 2000 readiness.
Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. AEP, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills.
The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30 to June 30, 1999.
Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans.

Various state commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction.

Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, communications, and the physical generation and delivery of energy; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g. payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations.

The following chart shows our progress toward becoming ready for the Year 2000 as of September 30, 1998:

                             IT SYSTEMS         NON-IT  SYSTEMS
                     COMPLETION                 COMPLETION
                     DATE/ESTIMATED     PERCENT     DATE/ESTIMATED   PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE  COMPLETE  COMPLETION DATE  COMPLETE

Launch: Initiation of       2/24/1998     100%         5/31/1998     100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.

Inventory and Assessment:
Identifying all Company     7/31/1998     100%         11/30/1998    86%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.

Remediation/Testing: The
process of modifying,       6/30/1999     Mainframe     6/30/1999     2%
replacing or retiring                     60%
those mission critical and
high priority digital-based               Client
systems with problems                     Server:
processing dates past the                 1%
Year 2000. Testing these
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.

Costs to Address the Company's Year 2000 Issues - Through September 30, 1998, the Company has spent $5 million on the Year 2000 project and, estimates spending an additional $12 million to $16 million to achieve Year 2000 readiness. Most Year 2000 costs are software- and salary-related and are expensed; however, in certain cases the Company has acquired hardware that is capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition.

Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 problems are:
* Automated power generation, transmission and distribution systems
* Telecommunications systems
* Energy trading systems
* Time-in-use, demand and remote metering systems for commercial and industrial customers
* Work management and billing systems.

The potential problems related to erroneous processing by, or failure of, these systems are:
* Power service interruptions to customers
* Interrupted revenue data gathering and collection
* Poor customer relations resulting from delayed billing and settlement.

In addition, although as discussed the Company is monitoring its relationships with third parties, such as suppliers, customers and other electric utilities, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty.

Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others not affiliated with AEP, fail for critical applications, Year 2000-related issues may materially adversely affect AEP.

Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster recovery, system restoration, and contingency planning that we now have in place. We have begun the contingency planning process, including the review of NERC's contingency planning and preparations guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999.

Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others:

* Continuing availability of experienced consultants and IT personnel and related resources
* Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness
* Ability of the Company to identify and implement contingency plans.
TAXES
As discussed in Note 8, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $115 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter.
In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998 the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is

unfavorable, it will have a material adverse impact on results of operations and cash flows.
POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands.
The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $290 million.
The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside the traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230

million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $65 million for sales and approximately $40 million for purchases.
Dependent on future electricity market conditions these activities could produce material income or losses in future periods.

PART II. OTHER INFORMATION