AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1998 1997 1996 1995 1994
INCOME STATEMENTS DATA (in millions):
Operating Revenues $6,346 $5,880 $5,849 $5,670 $5,505
Operating Income 957 984 1,008 965 932
Income Before Extraordinary Item 536 620 587 530 500
Extraordinary Loss -
UK Windfall Tax - 109 - - -
Net Income 536 511 587 530 500
December 31, 1998 1997 1996 1995 1994
BALANCE SHEETS DATA (in millions):
Electric Utility Plant $20,146 $19,597 $18,970 $18,496 $18,175
Accumulated Depreciation
and Amortization 8,416 7,964 7,550 7,111 6,827
Net Electric
Utility Plant $11,730 $11,633 $11,420 $11,385 $11,348
Total Assets $19,483 $16,615 $15,883 $15,900 $15,736
Common Shareholders' Equity 4,842 4,677 4,545 4,340 4,229
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 46 47 90 148 233
Subject to Mandatory Redemption* 128 128 510 523 590
Long-term Debt* 7,006 5,424 4,884 5,057 4,980
Obligations Under Capital Leases* 533 538 414 405 400
*Including portion due within one year
Year Ended December 31, 1998 1997 1996 1995 1994
COMMON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item $2.81 $ 3.28 $3.14 $2.85 $2.71
Extraordinary Loss - UK Windfall Tax - (0.58) - - -
Net Income $2.81 $ 2.70 $3.14 $2.85 $2.71
Average Number of Shares
Outstanding (in thousands) 190,774 189,039 187,321 185,847 184,666
Market Price Range: High $53-5/16 $ 52 $44-3/4 $40-5/8 $37-3/8
Low 42-1/16 39-1/8 38-5/8 31-1/4 27-1/4
Year-end Market Price 47-1/16 51-5/8 41-1/8 40-1/2 32-7/8
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 85.4% 88.7%(a) 76.5% 84.1% 88.6%
Book Value per Share $25.24 $24.62 $24.15 $23.25 $22.83
(a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is 73.1%.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
This discussion includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements reflect assumptions, and involve
a number of risks and uncertainties. Among the factors that could
cause actual results to differ materially from forward looking
statements are: electric load and customer growth; abnormal weather
conditions; available sources and costs of fuels; availability of
generating capacity; the impact of the proposed merger with Central
and South West Corporation (CSW) including any regulatory
conditions imposed on the merger or the inability to consummate the
merger with CSW; the speed and degree to which competition is
introduced to our power generation business, the structure and
timing of a competitive market and its impact on energy prices or
fixed rates; the ability to recover stranded costs in connection
with possible deregulation of generation; new legislation and
government regulations; the ability of the Company to successfully
control its costs; the success of new business ventures;
international developments affecting our foreign investments; the
economic climate and growth in our service territory; unforeseen
events affecting the Company's nuclear plant which is on an
extended safety related shutdown; problems or failures related to
Year 2000 readiness of computer software and hardware; inflationary
trends; electricity and gas market prices; interest rates and other
risks and unforeseen events. This discussion contains a "Year 2000
Readiness Disclosure" within the meaning of the Year 2000
Information and Readiness Disclosure Act.
Growth Of The Business
In 1998 management continued to implement its growth-oriented
strategy with a goal of being America's Energy Partner and a global
energy and related services company. We have adopted a strategy to
expand our geographic reach and to build and acquire capabilities
across a broader spectrum of the energy products and services value
chain. AEP is working to position itself to be successful in an
increasingly competitive market that will allow customers to choose
their energy supplier. AEP made several acquisitions in 1998 that
expanded its energy operations overseas and in the United States.
The expansion of the foreign energy business in 1998 included the
purchase of CitiPower, an Australian electric distribution utility,
the acquisition of an equity interest in Pacific Hydro, an
Australian hydroelectric generating company, and continued on-
schedule construction of two generating units in China.
The $1.1 billion acquisition of CitiPower, completed on
December 31, 1998, was accounted for using the purchase method of
accounting. CitiPower serves approximately 240,000 customers in
the city of Melbourne. CitiPower will contribute to earnings
beginning in the first quarter of 1999.
In March 1998 the Company invested $10 million to acquire a 20%
equity interest in Pacific Hydro. Pacific Hydro operates four
hydroelectric power stations in Australia with an installed
capacity of 40 megawatts (MW) and has interests in two
hydroelectric projects under construction in the Philippines.
The generating units under construction in China are owned 70%
by the Company with the remaining 30% owned by two Chinese
partners. Construction of the two unit 250 MW, coal-fired station
is proceeding on schedule. The first unit began commercial
operation in February of 1999 and the second unit is expected to go
into commercial service in July of 1999. These units are expected
to contribute to earnings in 1999.
In addition, the Company has a 50% investment in Yorkshire
Electricity Group plc (Yorkshire), a United Kingdom (UK)
distribution electric company. The investment was made in April
1997 and contributed $38.5 million to nonregulated, nonoperating
income in 1998. In September 1998 certain residential and
commercial customers in the UK could choose their electricity
supplier marking the start of a transition to competition.
Yorkshire serves approximately 2.2 million customers.
One disappointment we suffered in 1998 was the withdrawal of
a joint venture partner. In 1997 the Company announced a joint
venture with Conoco, an energy subsidiary of DuPont. The venture
was to provide energy management and financing for steam and
electric generation facilities for commercial and industrial
customers. Conoco withdrew from the joint venture after its parent
announced plans to sell Conoco.
The past year also saw the expansion of AEP's domestic energy
operations. On December 1, 1998, the Company purchased the
midstream gas operations of Equitable Resources, Inc. for
approximately $340 million including working capital funds. The
midstream operations include a fully integrated natural gas
gathering, processing, storage and transportation operation in
Louisiana and a gas trading and marketing operation in Houston,
Texas. Assets include an intrastate pipeline system, four natural
gas processing plants plus a fifth plant under construction, one
natural gas storage facility and an additional storage facility
under construction. The gas trading operation included in this
purchase was merged with AEP's existing gas trading organization
which began operating in December 1997. This acquisition is
expected to enhance AEP's gas trading operations by improving
management's knowledge of the Henry Hub gas market.
Traditionally a major marketer of electricity, AEP has recently
become a major participant in the electricity trading market. Our
electricity trading operation, which commenced in mid 1997,
significantly expanded its trading volume in 1998. Electricity
trading involves the trading of contracts for the future delivery
or receipt of electricity in both regulated and non-regulated
operations. It also involves the purchase and sale of options,
swaps and other electricity derivative financial instruments. Open
access transmission, the introduction of competition to the
wholesale electricity market and the development of a trading
market and settlement process have fostered the growth of
electricity trading in the United States. The electricity trading
market is a highly volatile market which requires enhanced credit
and market risk management skills. Electricity trading requires
little capital investment and profit margins are usually smaller
than margins on traditional electricity sales. The Company's goal
is to utilize its knowledge of energy markets to trade electricity
and gas to contribute to net income, thereby enhancing both
customer and shareholder value.
In December 1997 the Company and CSW agreed to merge. The
merger is intended to expand AEP's geographic reach. The benefits
of the merger include costs savings; improved prices and services;
increased financial strength; greater diversity in fuel, generation
and service territory; and increased scale (the size of the Company
which contributes to business success in a competitive market). At
the 1998 annual meeting AEP shareholders approved the issuance of
common shares to effect the merger and approved an increase in the
number of authorized shares of AEP Common Stock from 300,000,000 to
600,000,000 shares. CSW stockholders approved the merger at their
May 1998 annual meeting. Approval of the merger has been requested
from the Federal Energy Regulatory Commission (FERC), the
Securities and Exchange Commission, the Nuclear Regulatory
Commission (NRC) and all of CSW's state regulatory commissions:
Arkansas, Louisiana, Oklahoma and Texas. In the near future, AEP
and CSW plan to make the final two filings associated with approval
of the merger with the Federal Communications Commission and the
Department of Justice.
Regulatory approvals for the merger have been received from the
Arkansas Public Service Commission (APSC) and the NRC. In December
1998 the APSC approved a stipulated agreement related to a proposed
merger regulatory plan submitted by the Company, CSW and CSW's
Arkansas operating subsidiary, Southwestern Electric Power Company.
The regulatory plan, agreed to with the APSC staff, provides for a
sharing of net merger savings through a $6 million rate reduction
over 5 years following the completion of the merger.
The application to the NRC by CSW's operating subsidiary,
Central Power and Light Company (CPL), requesting permission to
transfer indirect control of the license from CSW to AEP for CPL's
interest in the South Texas Project nuclear generating station was
approved by the NRC in November 1998.
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 sufficient 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.
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
signatories. The settlement provides for, among other things, rate
reductions totaling approximately $180 million over a six year
period following completion of the merger to share net merger
savings of $84 million and settle existing rate issues of $96
million. Hearings are scheduled for April 1999.
In July 1998 the FERC issued an order which confirmed that a
250 megawatt firm contract path with the Ameren System is
available. The contract path was obtained by AEP and CSW to meet
the requirement of the Public Utility Holding Company Act of 1935
that the two systems operate on an integrated and coordinated
basis.
In November 1998 the FERC issued an order establishing hearing
procedures for the merger and scheduled the hearings to begin on
June 1, 1999. The FERC 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 proposed merger of CSW into AEP would result in common
ownership of two UK regional electricity companies (RECs),
Yorkshire and Seeboard, plc. AEP has a 50% ownership interest in
Yorkshire and CSW has a 100% interest in Seeboard. Although the
merger of CSW into AEP is not subject to approval by UK regulatory
authorities, the common ownership of two UK RECs could be referred
by the UK Secretary of State for Trade and Industry to the UK
Monopolies and Mergers Commission for investigation.
AEP has received a request from the staff of the Kentucky
Public Service Commission (KPSC) to file an application seeking
KPSC approval for the indirect change in control of Kentucky Power
Company that will occur as a result of the proposed merger.
Although AEP does not believe that the KPSC has the jurisdictional
authority to approve the merger, management will prepare a merger
application filing to be made with the KPSC, which is expected to
be filed by April 15, 1999. Under the governing statute the KPSC
must act on the application within 60 days. Therefore this is not
expected to impact the timing of the merger.
The merger is conditioned upon, among other things, the
approval of the above state and federal regulatory agencies. The
transaction must satisfy many conditions, a number of which may not
be waived by the parties, including the condition that the merger
must be accounted for as a pooling of interests. The merger
agreement will terminate on December 31, 1999 unless extended by
either party as provided in the merger agreement. Although
consummation of the merger is expected to occur in the fourth
quarter of 1999, the Company is unable to predict the outcome or
the timing of the required regulatory proceedings.
Business Outlook
The most significant factors affecting the Company's future
earnings are the ability to recover its costs as the domestic
electric generating business becomes more competitive and the
performance of the recently acquired energy investments and
business ventures described above. The Company continues to
evaluate domestic and international markets for investments to grow
the business in the best interests of our shareholders, customers
and employees. The performance of any future acquisitions, mergers
and investments will also impact future earnings.
The introduction of competition and customer choice for retail
customers in the Company's domestic service territory has been slow
and continues at a deliberate pace as legislators and regulatory
officials recognize the complexity of the issues. Federal
legislation has been proposed to mandate competition and customer
choice at the retail level. In February 1999 the Virginia general
assembly passed legislation, subject to the governor's signature,
that would provide Virginia retail customers the ability to choose
their electric supplier beginning in 2002. The legislation
provides for the recovery of "just and reasonable net stranded
costs". Prior to January 1, 2001 the Virginia State Corporation
Commission must establish rates that will be "capped" through as
long as July 1, 2007. Statement of Financial Accounting Standards
(SFAS) 71 "Accounting for the Effects of Certain Types of
Regulation" will no longer apply to the Company's Virginia retail
jurisdiction once the "capped" rates are established. When this
occurs the application of SFAS 71 will be discontinued for the
Virginia retail jurisdiction portion of the generating business and
net regulatory assets applicable to the Virginia generating
business would have to be written off to the extent that they are
not probable of recovery. Although management does not believe
that the impact of the new legislation on regulatory assets would
have a material adverse impact on results of operations, cash flows
or financial condition, the amount of an impairment loss, if any,
cannot be estimated with any certainty until the "capped" rates are
determined (See requirements of EITF 97-4 discussed below).
All of the other states within our service territory have
initiatives to implement or review customer choice, although the
timing is uncertain. The Company supports customer choice and
deregulation of generation and is proactively involved in
discussions at both the state and federal levels regarding the best
competitive market structure and method to transition to a
competitive marketplace.
As the pricing of generation in the electric energy market
evolves from regulated cost-of-service ratemaking to market-based
rates, many complex issues must be resolved, including the recovery
of stranded costs. Stranded costs are those costs above market and
potentially would not be recoverable in a competitive market. At
the wholesale level recovery of stranded costs under certain
conditions was addressed by the FERC when it established rules for
open transmission access and competition in the wholesale markets.
However, the issue of stranded cost is generally unresolved at the
retail level where it is much larger than it is at the wholesale
level. The amount of stranded costs the Company could experience
depends on the timing and extent to which competition is introduced
to its generation business and the future market prices of
electricity. The recovery of stranded cost is dependent on the
terms of future legislation and related regulatory proceedings.
Under the provisions of SFAS 71, regulatory assets (deferred
expenses) and regulatory liabilities (deferred revenues) are
included in the consolidated balance sheets of regulated utilities
in accordance with regulatory actions in order to match expenses
and revenues with cost-based rates. In order to maintain net
regulatory assets on the balance sheet, SFAS 71 requires that rates
charged to customers be cost-based and provide for the recovery of
the deferred expenses over future accounting periods. In the event
a portion of AEP's business no longer meets the requirements of
SFAS 71, SFAS 101 "Accounting for the Discontinuance of
Application of Statement 71" requires that net regulatory assets be
written off for that portion of the business. The provisions of
SFAS 71 and SFAS 101 never anticipated that deregulation would
include an extended transition period or that it could provide for
recovery of stranded costs during and after the transition period.
In 1997 the Financial Accounting Standards Board's Emerging Issues
Task Force (EITF) addressed such a situation with the consensus
reached on issue 97-4 that requires the application of SFAS 71 to
a segment of a regulated electric utility cease when that segment
is subject to a legislatively approved plan for competition or an
enabling rate order is issued containing sufficient detail for the
utility to reasonably determine what the plan would entail. The
EITF indicated that the cessation of application of SFAS 71 would
require that regulatory assets and impaired plant be written off
unless they are recoverable in future rates.
Although certain FERC orders provide for competition in the
firm wholesale market, that market is a relatively small part of
our business and most of our firm wholesale sales are still under
cost-of-service contracts. As of December 31, 1998 AEP's
generation business is cost-based regulated. The enactment of
enabling legislation in Virginia to deregulate the generation
business will cause a portion of the Company's generation business
to become deregulated. This could ultimately result in adverse
impacts on results of operations and cash flows depending on the
market price of electricity and the ability of the Company to
recover its stranded costs. We believe that enabling state
legislation should provide for the recovery of any generation-related
net regulatory assets and other reasonable stranded costs
from impaired generating assets. However, if in the future AEP's
generation business were to no longer be cost-based regulated and
if it were not possible to demonstrate probability of recovery of
resultant stranded costs including regulatory assets, results of
operations, cash flows and financial condition would be adversely
affected.
Cost Containment and Process Improvements
Efforts continue to reduce the costs of AEP's products and
services in order to maintain competitiveness. The accounting
department completed its consolidation of operations and the
marketing department completed its reorganization in 1998 producing
significant cost reductions. In 1998 plans were announced to close
one of the Company's coal mining operations in October 1999 and the
Company reviewed its staffing levels for power generation and
energy delivery and developed plans to reduce staff in 1999. The
cost of staff reductions planned for 1999 was provided for in the
fourth quarter of 1998. Although cost savings are expected to
result from the power generation and energy delivery
reorganizations and the planned mine closing, the Company continues
to incur expenses related to investments in new business growth and
development; marketing and customer services; and the reengineering
and improvement of business processes.
During 1998, AEP completed installation of a new unified
customer service system which is designed to support customer
requests for service, billings, accounts receivable, credit and
collection functions. On January 1, 1999, the Company's new
financial data base and PeopleSoft client server accounting and
purchasing software became operational. The move to client server
business software and related online data bases will empower AEP
employees to maximize the benefits of their personal computers and
will position AEP to access the power of the Internet and other new
technologies.
Fuel Costs
The management and control of coal costs is critical to AEP's
competitive position. Approximately 90% of AEP's generation is
coal fired and approximately 13% of the 54 million tons of coal
burned in 1998 were supplied by affiliated mines with the remainder
acquired under long-term contracts and purchases in the spot
market. As long-term contracts expire we are negotiating with
unaffiliated suppliers to lower coal costs. We intend to continue
to prudently supplement our long-term coal supplies with spot
market purchases when spot market prices are favorable.
We have agreed in our Ohio jurisdiction to certain limitations
on the current recovery of affiliated coal costs. At December 31,
1998, the Company had deferred $106 million for future recovery
under the agreements which established the limitation. See
discussion in Note 2 of the Notes to Consolidated Financial
Statements. Our analysis shows that we should be able to recover
the Ohio jurisdictional portion of the costs of our affiliated
mining operations including future mine closure costs before the
expiration of the agreement in 2009. The Company has announced
plans to close the Muskingum mine in 1999. A provision for
Muskingum mine closing cost of $45 million was recorded in 1998.
Management intends to seek recovery of its non-Ohio jurisdictional
portion of its investment in and the liabilities and closing costs
of affiliated mines estimated at $100 million after tax.
Should it become apparent that these affiliated mining costs
will not be recovered from Ohio and/or non-Ohio jurisdictional
customers, the other mines may have to be closed and future
earnings, cash flows and possibly financial condition would be
adversely affected. In addition compliance with Phase II
requirements of the Clean Air Act Amendments of 1990 (CAAA), which
become effective in January 2000, could also cause the remaining
mining operations to close. Unless the cost of any mine closure
and the coal cost deferrals in the Ohio jurisdiction are recovered
either in regulated rates or as a stranded cost under a plan to
transition the generation business to competition, future earnings,
cash flows and possibly financial condition would be adversely
affected.
Costs for Spent Nuclear Fuel and Decommissioning
AEP, as the owner of the Cook Nuclear Plant, like other nuclear
power plants, has a significant future financial commitment to
safely dispose of spent nuclear fuel (SNF) and decommission and
decontaminate the plant. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site
disposal of SNF and high-level radioactive waste. By law we
participate in the Department of Energy's (DOE) SNF disposal
program which is described in Note 4 of the Notes to Consolidated
Financial Statements. Since 1983 we have collected $272 million
from customers for the disposal of nuclear fuel consumed at the
Cook Plant. $115 million of these funds have been deposited in
external trust funds to provide for the future disposal of spent
nuclear fuel and $157 million has been remitted to the DOE. Under
the provisions of the Nuclear Waste Policy Act, collections from
customers are to provide the DOE with money to build a repository
for spent fuel. However, in December 1996, the DOE notified AEP
that it would be unable to begin accepting SNF by the January 1998
deadline required by law.
As a result of DOE's failure to make sufficient progress toward
a permanent repository or otherwise assume responsibility for SNF,
AEP along with a number of unaffiliated utilities and states filed
suit in the U.S. Court of Appeals for the District of Columbia
Circuit requesting, among other things, that the court order DOE to
meet its obligations under the law. The court ordered the parties
to proceed with contractual remedies but declined to order DOE to
begin accepting SNF for disposal. DOE estimates its planned site
for the nuclear waste will not be ready until 2010. In June 1998,
AEP filed a complaint in the U.S. Court of Federal Claims seeking
damages in excess of $150 million due to the DOE's partial material
breach of its unconditional contractual deadline to begin disposing
of SNF generated by the Cook Nuclear Plant. Similar lawsuits have
been filed by other utilities. As long as the delay in the
availability of a government approved storage repository for SNF
continues, the cost of both temporary and permanent storage will
increase.
The cost to decommission the Cook Plant is affected by both NRC
regulations and the delayed SNF disposal program. Studies
completed in 1997 estimate the cost to decommission the Cook Plant
ranges from $700 million to $1,152 million in 1997 dollars. This
estimate could escalate due to continued uncertainty in the SNF
disposal program and the length of time that SNF may need to be
stored at the plant site. External trust funds have been
established with amounts collected from customers to decommission
the plant. At December 31, 1998, the total decommissioning trust
fund balance was $443 million which includes earnings on the trust
investments. We will work with regulators and customers to recover
the remaining estimated cost of decommissioning the Cook Plant.
However, AEP's future results of operations, cash flows and
possibly its financial condition would be adversely affected if the
cost of SNF disposal and decommissioning continues to increase and
cannot be recovered.
COOK NUCLEAR PLANT SHUTDOWN
We shut down both units of the Cook Nuclear Plant in September
1997 due to questions, which arose during a NRC architect engineer
design inspection, regarding the operability of certain safety
systems. The NRC issued a Confirmatory Action Letter in September
1997 requiring AEP to address the issues identified in the letter.
We are working with the NRC to resolve the remaining open issue in
the letter.
In April 1998 the NRC notified I&M that it had convened a
Restart Panel for Cook Plant. A list of required restart
activities was provided by the NRC in July 1998 and in October the
NRC expanded the list. In order to identify and resolve the issues
necessary to restart the Cook units, AEP is and will be meeting
with the Panel on a regular basis, until the units are returned to
service.
In January 1999 we announced that we will conduct additional
engineering reviews at the Cook Plant that will delay restart of
the units. Previously, the units were scheduled to return to
service at the end of the first and second quarters of 1999. The
decision to delay restart resulted from internal assessments that
indicated a need to conduct expanded system readiness reviews. A
new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999. When
maintenance and other activities required for restart are complete,
AEP will seek concurrence from the NRC to return the Cook Plant to
service. Until these additional reviews are completed, management
is unable to determine when the units will be returned to service.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows and possibly financial
condition.
One of the steps AEP has taken toward expediting the restart
of the Cook units is to augment its existing nuclear generation
management and staff with personnel experienced in restarting
unaffiliated companies' nuclear plants during NRC supervised
extended outages.
The incremental costs incurred in 1997 and 1998 for restart of
the Cook units were $6 million and $78 million, respectively, and
recorded as operation and maintenance expense. Currently
incremental restart expenses are approximately $12 million a month.
In July 1998 AEP received an "adverse trend letter" from the
NRC indicating that NRC senior managers determined that there had
been a slow decline in performance at the Cook Plant during the 18
month period preceding the letter. The letter indicated that the
NRC will closely monitor efforts to address issues at Cook Plant
through additional inspection activities. In October 1998 the NRC
issued AEP a Notice of Violation and proposed a $500,000 civil
penalty for alleged violations at the Cook Plant discovered during
five inspections conducted between August 1997 and April 1998. AEP
paid the penalty.
The cost of electricity supplied to certain retail customers
rose due to the outage of the two units since higher cost coal-fired
generation and coal based purchased power were substituted
for low cost nuclear generation. AEP's Indiana and Michigan retail
jurisdictional 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 these 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. Therefore, a regulatory asset
has been recorded and revenues accrued in anticipation of the
future reconciliation and billing under the fuel cost recovery
mechanisms of the higher fuel costs to replace Cook energy during
the extended outage. At December 31, 1998, the regulatory asset
was $65 million.
The Indiana Utility Regulatory Commission approved, subject to
future reconciliation or refund, agreements authorizing AEP, during
the billing months of July 1998 through March 1999, to include in
rates a fuel cost adjustment factor less than that requested by
AEP. 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 allowed to recover the deferred Cook replacement energy
costs; however, if recovery of the replacement costs is denied,
future results of operations and cash flows would be adversely
affected by the writeoff of the regulatory asset.
Environmental Concerns and Issues
We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
Over the years AEP has spent more than a billion dollars to equip
its facilities with the latest cost effective clean air and water
technologies and to research new technologies. We are also proud
of our award winning efforts to reclaim our mining properties. We
intend to continue in a leadership role fostering economically
prudent efforts to protect and preserve the environment.
By-products from the generation of electricity include
materials such as ash, slag, sludge, low-level radioactive waste
and SNF. Coal combustion by-products, which constitute the
overwhelming percentage of these materials, are typically disposed
of or treated in captive disposal facilities or are beneficially
utilized. In addition, our generating plants and transmission and
distribution facilities have used asbestos, polychlorinated
biphenyls (PCBs) and other hazardous and nonhazardous materials.
We are currently incurring costs to safely dispose of such
substances. Additional costs could be incurred to comply with new
laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and
Liability Act (Superfund) addresses clean-up of hazardous
substances at disposal sites and authorized the United States
Environmental Protection Agency (Federal EPA) to administer the
clean-up programs. As of year-end 1998, we are involved in
litigation with respect to three sites overseen by the Federal EPA
and have been named by the Federal EPA as a potentially responsible
party (PRP) for three other sites. There is one additional site
for which AEP has received an information request which could lead
to PRP designation. Our liability has been resolved for a number
of sites with no significant effect on results of operations. In
those instances where we have been named a PRP or defendant, our
disposal or recycling activity was in accordance with the then-applicable laws
and regulations. Unfortunately, Superfund does not
recognize compliance as a defense, but imposes strict liability on
parties who fall within its broad statutory categories.
While the potential liability for each Superfund site must be
evaluated separately, several general statements can be made
regarding our potential future liability. AEP's disposal of
materials at a particular site is often unsubstantiated and the
quantity of materials deposited at a site was small and often
nonhazardous. Typically many parties are named as PRPs for each
site and, although liability is joint and several, generally
several of the parties are financially sound enterprises.
Therefore, our present estimates do not anticipate material cleanup
costs for identified sites for which we have been declared PRPs.
However, if for reasons not currently identified significant
cleanup costs are attributed in the future to AEP, results of
operations, cash flows and possibly financial condition would be
adversely affected unless the costs can be recovered from
customers.
In December 1998 the Company purchased gas assets from
Equitable Resources, Inc. (Equitable). The purchase contract
contains details of partial indemnification by Equitable for
certain environmental and soil and ground water contamination
cleanup liabilities which existed at the time of AEP's purchase.
An outside consultant has estimated total environmental liabilities
for the acquired entities to range from $10 million to $16 million.
By contract the Company must seek indemnification by December 1,
2000. The indemnification clause requires that AEP incur $3
million of cleanup liabilities before seeking reimbursement. Based
upon the consultant's estimate, environmental liabilities resulting
from the gas asset acquisition should not have a material impact on
results of operations, cash flows or financial condition.
In December 1998, the Company purchased CitiPower, an
Australian distribution utility, from Entergy, an unaffiliated
company. CitiPower operates under Australian environmental laws.
Prior to the purchase, AEP hired an outside consultant, experienced
in Australian environmental laws, to identify CitiPower's exposure.
The consultant's assessment identified sites with contaminated
land, PCBs and storm water runoff. Cost of environmental
remediation are estimated at $3.5 million by the consultant. Based
upon this estimate, environmental costs from the acquisition of
CitiPower are not expected to have a material impact on results of
operations, cash flows or financial condition.
Federal EPA is required by the CAAA to issue rules to implement
the law. In 1996 Federal EPA issued final rules governing nitrogen
oxides (NOx) emissions that must be met after January 1, 2000
(Phase II of CAAA). The final rules will require substantial
reductions in NOx emissions from certain types of boilers including
those in AEP's power plants. To comply with Phase II of CAAA, the
Company plans to install NOx emission control equipment on certain
units and switch fuel at other units. Total capital costs to meet
the requirements of Phase II of CAAA are estimated to be
approximately $90 million of which $69 million has been incurred
through December 31, 1998.
On September 24, 1998, the administrator of Federal EPA signed
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 state implementation plans (SIPs)
by September 1999. SIPs are a procedural method used by each state
to comply with Federal EPA rules. The final rules anticipate the
imposition of a NOx reduction on utility sources of approximately
85% below 1990 emission levels by the year 2003. On October 30,
1998, a number of utilities, including the operating companies of
the AEP System, filed petitions 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 the final rules were signed
(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 petitions filed by eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources in upwind midwestern
states. These reductions are substantially the same as those
required by the final NOx rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance with
the final rules.
Preliminary estimates indicate that compliance costs could
result in required capital expenditures of approximately $1.2
billion for the AEP System. Compliance costs cannot be estimated
with certainty and the actual costs incurred to comply could be
significantly different from this preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
At the Third Conference of the Parties to the United Nations
Framework Convention on Climate Change held in Kyoto, Japan in
December 1997 more than 160 countries, including the United States,
negotiated a treaty requiring legally-binding reductions in
emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change. The
treaty, which requires the advice and consent of the United States
Senate for ratification, would require the United States to reduce
greenhouse gas emissions seven percent below 1990 levels in the
years 2008-2012. Although the United States has agreed to the
treaty and signed it on November 12, 1998, President Clinton has
indicated that he will not submit the treaty to the Senate for
consideration until it contains requirements for "meaningful
participation by key developing countries" and the rules,
procedures, methodology and guidelines of the treaty's market-based
policy instruments, joint implementation programs and compliance
enforcement provisions have been negotiated. At the Fourth
Conference of the Parties, held in Buenos Aires, Argentina, in
November 1998, the parties agreed to a work plan to complete
negotiations on outstanding issues with a view toward approving
them at the Sixth Conference of the Parties to be held in December
2000. We will continue to work with the Administration and
Congress to monitor the development of public policy on this issue.
If the Kyoto treaty is approved by Congress, the costs to
comply with the emission reductions required by the treaty are
expected to be substantial and would have a material adverse impact
on results of operations, cash flows and possibly financial
condition if not recovered from customers.
Results of Operations
Net Income
Net income increased 5% to $536 million or $2.81 per share from
$511 million or $2.70 per share in 1997 primarily due to the effect
of a 1997 extraordinary loss of $109 million. The extraordinary
loss, recorded in 1997, was a result of the UK's one-time windfall
tax which was based on a revision or recomputation of the original
privatization value of certain privatized utilities, including
Yorkshire. In 1997 net income decreased 13% to $511 million
primarily due to the extraordinary loss of $109 million from the
UK's one-time windfall tax.
Income Before Extraordinary Item
In 1998 income before the extraordinary loss, recorded in 1997,
decreased 14% to $536 million or $2.81 per share from $620 million
or $3.28 per share in 1997. Several major items reduced 1998
earnings including the cost of restart activities during an
extended outage at the Cook Nuclear Plant, a write-down of
Yorkshire's investment in Ionica, a UK telecommunications company,
severance accruals for reductions in power generation and energy
delivery staff and mild winter and fall weather.
AEP's 1997 income before the extraordinary loss increased 6%
to $620 million or $3.28 per share from $587 million or $3.14 per
share in 1996. The increase was primarily attributable to
increased transmission service revenues, reduced preferred stock
dividends due to a redemption program and an increase in
nonoperating income from equity earnings, exclusive of the
extraordinary loss, since the April 1997 investment in Yorkshire.
Revenues Increase
Operating revenues increased 8% in 1998 and were relatively
unchanged in 1997. Increased revenues from retail, wholesale and
transmission service customers were the primary reasons for the
increase in 1998. The slight increase in 1997 is primarily due to
increased transmission service revenues. The changes in the
components of revenues are as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1998 1997
Amount % Amount %
Retail:
Residential $ 37.6 $(34.7)
Commercial 57.0 1.8
Industrial 90.1 18.2
Other 3.8 0.4
188.5 3.8 (14.3) (0.3)
Wholesale 206.8 25.9 6.1 0.8
Transmission 68.0 61.7 33.3 43.2
Miscellaneous 2.8 4.8 5.5 10.9
Total $466.1 7.9 $ 30.6 0.5
Retail revenues increased 4% in 1998 reflecting a 2% sales
increase and higher fuel recoveries. The increase in retail fuel
recoveries reflects higher cost coal fired generation and purchased
power replacing power usually generated at the Cook Nuclear Plant.
The Cook Plant has been unavailable since September 1997. Although
residential sales were flat reflecting mild winter and fall weather
in 1998, revenues from residential customers increased 2%. The
accrual of revenues for the recovery of the Cook related increased
fuel costs accounted for the increase in residential revenues. The
rise in commercial revenues resulted from a 4% increase in sales
reflecting increased usage and growth in the number of customers.
Industrial revenues increased 6% reflecting a sales increase of 2%
following the resumption of operations by a major industrial
customer after an extended labor strike. Also contributing to the
increase in industrial revenues were favorable contract price
adjustments to certain major industrial customers and the pass-through of
higher power costs during periods of peak demand.
In 1997 retail revenues decreased slightly although retail
sales rose one half of a percent. Residential revenues and sales
each declined 2% reflecting mild weather. Sales to commercial
customers increased slightly causing a small increase in commercial
revenues. Industrial sales increased 2% accounting for the
increase in industrial revenues. The increase in lower priced
sales to industrial customers resulted from increased usage.
The 26% increase in wholesale revenues in 1998 is attributable
to trading of electricity with other utilities and power marketers
in the Company's traditional marketing area and increased power
marketing sales. Revenues from the trading of electricity are
recorded net of purchases. Regulated trading activities are
conducted as part of AEP's electric power wholesale marketing and
trading operations and involve the purchase and sale of substantial
amounts of electricity. Power marketing sales are for the resale
of power purchased from unaffiliated companies to other
unaffiliated companies. Although wholesale revenues rose, total
wholesale sales declined due to a reduction in coal conversion
service sales. These sales are for the generation of electricity
from the purchaser's coal and as a result do not include fuel
costs. Consequently, the drop in coal conversion service sales did
not have a significant effect on wholesale revenues.
In 1997 wholesale revenues increased slightly primarily due to
the commencement of trading activities in July 1997 and a
significant increase in coal conversion service sales. Since the
price of coal conversion service sales is for the generation of
electricity from coal provided by the electricity purchaser and
excludes fuel cost, a large change in coal conversion service sales
has a small impact on revenues.
The 62% increase in transmission service revenues in 1998 is
attributable to a substantial rise in the quantity of energy
transmitted for other entities over AEP's transmission lines. The
increase in 1997 of 43% in transmission service revenues was also
due to an increase in the volume of other companies' electricity
transmitted through AEP's transmission system. The issuance in
1996 of open transmission access rules by the FERC facilitated the
growth in transmission services.
The level of wholesale transactions, including transmission
services, tends to fluctuate due to the highly competitive nature
of the short-term energy market and other factors, such as
affiliated and unaffiliated generating plant availability, the
weather and the economy. The FERC rules which introduced a greater
degree of competition into the wholesale energy market have had a
major effect on wholesale sales and increased transmission service
revenues as more electricity is traded in the short-term (spot)
market. The Company's sales and in turn its results of operations
were impacted by the quantities of energy and services sold to
wholesale customers as well as the sale prices and cost of goods
sold. Future results of operations will be affected by the
quantity and price of both retail and wholesale transactions which
often depend on factors the Company does not control including the
level of competition, the weather and affiliated and unaffiliated
power plant availability. However, we work to keep abreast of
these factors and to take advantage of them whenever possible.
Operating Expenses Increase
Operating expenses increased 10% in 1998 and 1% in 1997.
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1998 1997
Amount % Amount %
Fuel $ 90.1 5.5 $ 26.4 1.6
Purchased Power 301.7 223.9 48.6 56.5
Other Operation 75.7 6.2 17.3 1.4
Maintenance 59.7 12.3 (19.6) (3.9)
Depreciation and Amortization (11.1) (1.9) (9.7) (1.6)
Taxes Other Than Federal
Income Taxes 2.8 0.6 (8.0) (1.6)
Federal Income Taxes (25.1) (7.3) (0.9) (0.3)
Total $493.8 10.1 $ 54.1 1.1
Fuel expense increased in 1998 and 1997 primarily due to an
increase in the average cost of fuel consumed reflecting the
reduced availability of lower cost nuclear generation due to the
unplanned shutdown of both of AEP's nuclear units which began in
September 1997 and continued throughout 1998.
The significant increases in purchased power expense in both
1998 and 1997 were primarily due to purchases of electricity for
resale to other utilities and power marketers and for replacement
of energy usually generated at the Cook Plant. The increase in
purchases made for resale to other entities reflects an expanding
and evolving wholesale marketplace.
Other operation expenses increased in 1998 due to the extended
Cook Plant outage, power marketing and trading compensation and
severance accruals for reductions in power generation and energy
delivery staff.
Maintenance expense increased in 1998 largely due to
expenditures to prepare the Cook Plant units for restart and to
restore service interrupted by two severe snowstorms.
The decrease in federal income tax expense attributable to
operations in 1998 was primarily due to a decrease in pre-tax
operating income.
Nonoperating Income
The significant decline in nonoperating income in 1998 was due
to losses from non-regulated energy trading activity and the write-down of
Yorkshire's investment in Ionica ($30 million). The
trading of gas and electricity outside of AEP's traditional
marketing area is marked-to-market and recorded in nonoperating
income.
The increase in nonoperating income in 1997 was mainly due to
income from the Company's share of earnings from its April 1997
investment in Yorkshire. The $34 million of equity in Yorkshire
earnings included $10 million of tax benefits related to a
reduction of the UK corporate income tax rate from 33% to 31%
effective April 1, 1997. The utilization of foreign tax credits
also contributed to the increase in nonoperating income.
Interest Charges and Preferred Stock Dividend Requirements
In 1997 interest charges on both long-term and short-term debt
increased reflecting additional borrowing primarily to fund the
Company's investment in non-regulated operations including the
investment in Yorkshire. Preferred stock dividend requirements of
the subsidiaries decreased in 1997 due to the reacquisition of over
4 million shares of cumulative preferred stock.
Financial Condition
AEP's financial condition continues to be strong. The 1998
payout ratio was 85.4%. It has been a management objective to
reduce the payout ratio through efforts to increase earnings in
order to enhance AEP's ability to invest in new energy based
businesses that can leverage our core competencies and improve
shareholder value. AEP's three-year total shareholder return
ranked 14th among the companies in the S&P Electric Utility Index.
While this placed us just below the midpoint, it has been and
continues to be management's goal to be in the top quartile of the
S&P Electric Utility Index for three-year total shareholder return.
Capital Investments
The total consideration paid by AEP to acquire CitiPower was
approximately $1.1 billion which was financed by the issuance of
debt in Australia and an equity investment by AEP Resources, Inc.
(AEPR). The purchase, for approximately $340 million, of domestic
gas assets in Louisiana was funded with part of the proceeds from
an issuance of $400 million of 6-1/2% senior notes by AEPR. For
more information see Note 6 of the Notes to Consolidated Financial
Statements. Also AEP's 70% interest in the construction of two 125
MW units in China required approximately $61 million of investment
during 1998.
Consolidated construction expenditures for all subsidiaries are
expected to be $2.4 billion over the next three years. All
expenditures for domestic electric utility construction, estimated
to be $2.2 billion for the next three years, are expected to be
financed with internally generated funds.
Capital Resources - Structure and Liquidity
AEP's ratio of common equity to total capitalization including
amounts due within one year was 40.3% for 1998, compared with 45.5%
for 1997 and 45.3% for 1996. The decline in 1998 reflects
borrowing to support the acquisitions which were completed in
December.
The Company and its subsidiaries issued $1.9 billion principal
amount of long-term obligations in 1998 at interest rates ranging
from 5% to 10.53%. The Company also increased its borrowing under
a long-term revolving credit agreement which expires in June 2000
by $270 million. The principal amount of long-term debt
retirements, including maturities, totaled $563 million with
interest rates ranging from 2.85% to 9.60%. The operating
subsidiaries senior secured debt/first mortgage bond ratings are
listed in the following table:
Company Moody's S&P Fitch D & P
APCo A3 A A A
CSPCo A3 A- A- A
I&M Baa1 A- BBB+ BBB+
KPCo Baa1 A BBB+ BBB+
OPCo A3 A- A- A
The operating subsidiaries generally issue short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds. They periodically reduce their
outstanding short-term debt through issuances of long-term debt and
additional capital contributions by the parent company. The
companies formed to pursue non-regulated businesses use short-term
debt (through a revolving credit facility) which is replaced with
long-term debt when financial market conditions are favorable and
capital contributions by the parent company. They also assume
outstanding debt as part of the acquisition of existing business
entities. Short-term debt increased $62 million from the prior
year-end balance and increased by $235 million in 1997. At
December 31, 1998, AEP Co., Inc. (the parent company) and its
subsidiaries had unused short-term lines of credit of $763 million,
and several of AEP's subsidiaries engaged in non-regulated energy
investments and businesses had available $60 million under a $600
million revolving credit agreement which expires in June 2000. The
sources of funds available to AEP are dividends from its
subsidiaries, short-term and long-term borrowings and proceeds from
the issuance of common stock. AEP issued 1,826,000 shares of
common stock in 1998, 1,755,000 shares in 1997 and 1,600,000 shares
in 1996 through a Dividend Reinvestment and Direct Stock Purchase
Plan and the Employee Savings Plan raising $86 million, $77 million
and $65 million, respectively. Additional sales of common stock
and/or equity linked securities may be necessary in the future to
support the Company's growth.
Unless the domestic electric operating utility subsidiaries
meet certain earnings or coverage tests, they cannot issue
additional mortgage bonds. In order to issue mortgage bonds
(without refunding existing debt), each subsidiary must have pre-tax earnings
equal to at least two times the annual interest
charges on mortgage bonds after giving effect to the issuance of
the new debt.
The following debt coverages of AEP's principal domestic
electric operating utility subsidiaries remained strong in 1998:
Coverages at
December 31, 1998
Mortgage
APCo 3.88
CSPCo 6.36
I&M 6.39
KPCo 4.40
OPCo 13.43
As the above table indicates, the major domestic electric
operating utility subsidiaries presently exceed the minimum
coverage requirements.
Market Risks
The Company as a major power producer and a trader of wholesale
electricity and natural gas has certain market risks inherent in
its business activities. The trading of electricity and natural
gas and related financial derivative instruments exposes the
Company to market risk. Market risk represents the risk of loss
that may impact the Company due to adverse changes in commodity
market prices and rates. In 1998 the Company substantially
increased the volume of its wholesale electricity and natural gas
marketing and trading activities. Various policies and procedures
have been established to manage market risk exposures including the
use of a risk measurement model utilizing Value at Risk (VaR).
Throughout the year ending December 31, 1998, the highest, lowest
and average quarterly VaR in the wholesale trading portfolio was
less than $11 million at a 95% confidence level with a holding
period of three business days. The Company used the variance-covariance method
for calculating VaR based on three months of
daily prices. Based on this VaR analysis, at December 31, 1998 a
near term change in commodity prices is not expected to have a
material effect on the Company's results of operations, cash flows
or financial condition. At December 31, 1997, the exposure for
financial derivatives in electricity and natural gas marketing
activities were not material to the Company's consolidated results
of operations, financial position or cash flows.
Investments in foreign ventures expose the Company to risk of
foreign currency fluctuations. The Company's exposure to changes
in foreign currency exchange rates related to these foreign
ventures and investments is not expected to be significant for the
foreseeable future since these foreign investments are considered
long-term and not expected to be liquidated in the near-term. The
Company does not presently utilize derivatives to manage its
exposures to foreign currency exchange rate movements.
The Company is exposed to changes in interest rates primarily
due to short- and long-term borrowings to fund its business
operations. The debt portfolio has both fixed and variable
interest rates, terms from one day to forty years and an average
duration of five years at December 31, 1998.
The Company measures interest rate market risk exposure
utilizing a VaR model. The model is based on the Monte Carlo
method of simulated price movements with a 95% confidence level and
a one year holding period. The volatilities and correlations were
based on three years of monthly prices. The risk of potential loss
in fair value attributable to the Company's exposure to interest
rates, primarily related to long-term debt with fixed interest
rates, was $589 million at December 31, 1998 and $501 million at
December 31, 1997. The Company would not expect to liquidate its
entire debt portfolio in a one year holding period. Therefore, a
near term change in interest rates should not materially affect
results of operations or the consolidated financial position of the
Company. The Company is currently utilizing interest rate swaps to
manage its exposure to interest rate fluctuations in Australia.
The Company has investments in debt and equity securities which
are held in nuclear trust funds. Approximately 85% of the trust
fund value is invested in tax exempt and taxable bonds, short-term
debt instruments or cash. The trust investments and their fair
value are discussed in Note 11 of the Notes to Consolidated
Financial Statements. Instruments in the trust funds have not been
included in the market risk calculation for interest rates as these
instruments are marked-to-market and changes in market value are
reflected in a corresponding decommissioning liability. Any
differences between the trust fund assets and the ultimate
liability should be recoverable from ratepayers.
Inflation affects AEP's cost of replacing utility plant and the
cost of operating and maintaining its plant. The rate-making
process limits our recovery to the historical cost of assets
resulting in economic losses when the effects of inflation are not
recovered from customers on a timely basis. However, economic
gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
Other Matters
Year 2000 Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are 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 (DOE) 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 second NERC report, dated January 11, 1999 and entitled:
Preparing the Electric Power Systems of North American for
Transition to the Year 2000 - A Status Report and Work Plan, Fourth
Quarter 1998, states that: "With more than 44% of mission critical
components tested through November 30, 1998, findings continue to
indicate that transition through critical Year 2000 (Y2K) rollover
dates is expected to have minimal impact on electric system
operations in North America." The Company continues to set a
target date of June 30, 1999 for having all mission critical and
high priority systems and components Y2K ready.
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, including AEP, are working together to
assess specific vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Year 2000 readiness of the
Company.
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, the physical
generation and delivery of energy and communications; 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 December 31, 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% 2/15/1999 99%
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 37%
replacing or retiring 70%
those mission critical and
high priority digital-based
systems with problems Client
processing dates past the Server:
Year 2000. Testing these 18%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
The above chart does not reflect progress of recently acquired
midstream gas operations and CitiPower. The mission critical
systems for the midstream gas operations are expected to be ready
by June 30, 1999 and the mission critical systems for CitiPower are
expected to be ready by October 1, 1999.
Costs to Address the Company's Year 2000 Issues - Through
December 31, 1998, the Company has spent $21 million on the Year
2000 project and estimates spending an additional $35 million to
$47 million to achieve Year 2000 readiness. Most Year 2000 costs
are for software, IT consultants and salaries 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 compliant 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 Y2K 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.
CitiPower operates under a legal and regulatory regime which
may expose it to customer claims, that may differ from claims under
the US legal and regulatory regime, for service interruptions
and/or power quality problems resulting from Y2K problems.
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 - To address possible failures of
electric generation and delivery of electrical energy due to Year
2000 related failures, we have established a draft Year 2000
contingency plan and submitted it to the East Central Area
Reliability Council (ECAR) in December 1998 as part of NERC's
review of regional and individual electric utility contingency
plans in 1999. NERC's target date is June 1999 for the completion
of this contingency plan. In addition, the Company intends to
establish contingency plans for its business units to address
alternatives if Year 2000 related failures occur. AEP's
contingency plans will be developed by the end of 1999. AEP's
plans build upon the disaster recovery, system restoration, and
contingency planning that we have had in place.
New Accounting Standards
In 1997 the FASB issued SFAS 130 "Reporting Comprehensive
Income" and SFAS No. 131 "Disclosures About Segments of an
Enterprise and Related Information." SFAS 130 establishes 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. The Company adopted SFAS 130 in the first quarter of
1998. For 1998 there were no material differences between net
income and comprehensive income.
SFAS 131 initiates reporting standards for annual and interim
financial statements about operating segments of a business for
which separate financial information is available and regularly
evaluated by the chief operating decision maker in allocating
resources and reviewing performance. Information about products
and services and geographic areas is to be reported at an
enterprise-level instead of by segment. SFAS 131 was required to
be adopted by the Company for the year ended December 31, 1998 with
restatement of prior period comparative information. Adoption of
SFAS 131 did not have any effect on results of operations, cash
flows or financial condition.
In the first quarter of 1998 the Company adopted the American
Institute of Certified Public Accountants' (AICPA) 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
had to 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.
In February 1998, the FASB issued SFAS 132 "Employers'
Disclosure about Pensions and Other Postretirement Benefits" which
revised employers' disclosures about pensions and other
postretirement benefit plans and suggested that the disclosure be
combined. It did not change the measurement or recognition
requirements for postretirement benefit accounting. The adoption
of SFAS 132 did not have a material effect on results of
operations, cash flows or financial condition. Prior periods were
restated to comply with SFAS 132 presentation requirements.
EITF 98-10 "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities" was issued in November 1998 to
address the application of mark-to-market accounting for energy
trading contracts. Under the provisions of this standard, which
must be adopted by the Company in January 1999, energy trading
contracts can no longer be accounted for on a settlement basis.
Instead they are to be marked-to-market. Adoption of EITF 98-10 is
not expected to have a significant impact on results of operations,
cash flows or financial condition.
The FASB issued SFAS 133 "Accounting for Derivative Instruments
and Hedging Activities" in June 1998. SFAS 133 establishes
accounting and reporting standards for derivative instruments. It
requires that all derivatives be recognized as either an asset or
a liability and measured at fair value in the financial statements.
If certain conditions are met a derivative may be designated as a
hedge of possible changes in fair value of an asset, liability or
firm commitment; variable cash flows of forecasted transactions; or
foreign currency exposure. The accounting/reporting for changes in
a derivative's fair value (gains and losses) depend on the intended
use and resulting designation of the derivative. Management is
currently studying the provisions of SFAS 133 to determine the
impact of its adoption on January 1, 2000 on results of operations,
cash flows and financial condition.
In April 1998 the AICPA issued SOP 98-5 "Reporting on the Costs
of Start-up Activities". The SOP clarifies the accounting and
reporting for one time start-up activities and organization costs,
requiring that they be expensed as incurred. The adoption of this
standard in January 1999 is not expected to have a material effect
on results of operations, cash flows or financial condition.
Litigation
Corporate Owned Life Insurance
The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a ruling
from their National Office that certain interest deductions claimed
by the Company relating to AEP's corporate owned life insurance
(COLI) program should not be allowed. As a result of a suit filed
by AEP in United States District Court (discussed below) this
request for ruling was withdrawn by the IRS agents. Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the COLI
interest deductions through December 31, 1998 would reduce earnings
by approximately $316 million (including interest). The Company has
made no provision for any possible adverse earnings impact from
this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount. The payments
to the IRS are included on the 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 plus interest. 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
the event the resolution of this matter is unfavorable, it will
have a material adverse impact on results of operations, cash flows
and possibly financial condition.
AEP is involved in a number of other legal proceedings and
claims. While we are unable to predict the outcome of such
litigation, it is not expected that the ultimate resolution of
these matters will have a material adverse effect on the results of
operations, cash flows and/or financial condition.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
Year Ended December 31,
1998 1997 1996
OPERATING REVENUES $6,345,902 $5,879,820 $5,849,234
OPERATING EXPENSES:
Fuel 1,717,177 1,627,066 1,600,659
Purchased Power 436,388 134,718 86,095
Other Operation 1,303,084 1,227,368 1,210,027
Maintenance 542,935 483,268 502,841
Depreciation and Amortization 579,997 591,071 600,851
Taxes Other Than Federal Income Taxes 493,386 490,595 498,567
Federal Income Taxes 316,201 341,280 342,222
TOTAL OPERATING EXPENSES 5,389,168 4,895,366 4,841,262
OPERATING INCOME 956,734 984,454 1,007,972
NONOPERATING INCOME (net) 9,463 59,572 2,212
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 966,197 1,044,026 1,010,184
INTEREST CHARGES 419,088 405,815 381,328
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 10,926 17,831 41,426
INCOME BEFORE EXTRAORDINARY ITEM 536,183 620,380 587,430
EXTRAORDINARY LOSS - UK WINDFALL TAX - (109,419) -
NET INCOME $ 536,183 $ 510,961 $ 587,430
AVERAGE NUMBER OF SHARES OUTSTANDING 190,774 189,039 187,321
EARNINGS PER SHARE:
Before Extraordinary Item $2.81 $3.28 $3.14
Extraordinary Loss - (0.58) -
Net Income $2.81 $2.70 $3.14
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
Year Ended December 31,
1998 1997 1996
RETAINED EARNINGS JANUARY 1 $1,605,017 $1,547,746 $1,409,645
NET INCOME 536,183 510,961 587,430
DEDUCTIONS:
Cash Dividends Declared 457,638 453,453 449,353
Other 1 237 (24)
RETAINED EARNINGS DECEMBER 31 $1,683,561 $1,605,017 $1,547,746
See Notes to Consolidated Financial Statements.
/TABLE
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(in thousands - except share data)
December 31,
1998 1997
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 9,591,211 $ 9,493,158
Transmission 3,570,717 3,501,580
Distribution 4,779,772 4,654,234
General (including mining assets and nuclear fuel) 1,641,676 1,604,671
Construction Work in Progress 562,891 342,842
Total Electric Utility Plant 20,146,267 19,596,485
Accumulated Depreciation and Amortization 8,416,397 7,963,636
NET ELECTRIC UTILITY PLANT 11,729,870 11,632,849
OTHER PLANT 841,451 62,213
OTHER PROPERTY AND INVESTMENTS 2,515,103 1,294,291
CURRENT ASSETS:
Cash and Cash Equivalents 172,985 91,481
Accounts Receivable:
Customers 557,382 559,203
Miscellaneous 360,783 115,075
Allowance for Uncollectible Accounts (11,075) (6,760)
Fuel - at average cost 215,699 224,967
Materials and Supplies - at average cost 279,823 263,613
Accrued Utility Revenues 186,006 189,191
Energy Marketing and Trading Contracts 372,380 2,306
Prepayments and Other 83,686 81,366
TOTAL CURRENT ASSETS 2,217,669 1,520,442
REGULATORY ASSETS 1,846,718 1,817,540
DEFERRED CHARGES 332,391 288,011
TOTAL $19,483,202 $16,615,346
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31,
1998 1997
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock-Par Value $6.50:
1998 1997
Shares Authorized. .600,000,000 300,000,000
Shares Issued. . . .200,816,469 198,989,981
(8,999,992 shares were held in treasury) $ 1,305,307 $ 1,293,435
Paid-in Capital 1,852,912 1,778,782
Retained Earnings 1,683,561 1,605,017
Total Common Shareholders' Equity 4,841,780 4,677,234
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 46,002 46,724
Subject to Mandatory Redemption 127,605 127,605
Long-term Debt* 6,799,641 5,129,463
TOTAL CAPITALIZATION 11,815,028 9,981,026
OTHER NONCURRENT LIABILITIES 1,428,968 1,246,537
CURRENT LIABILITIES:
Long-term Debt Due Within One Year* 206,476 294,454
Short-term Debt 616,604 555,075
Accounts Payable 618,019 353,256
Taxes Accrued 381,905 380,771
Interest Accrued 75,184 76,361
Obligations Under Capital Leases 81,661 101,089
Energy Marketing and Trading Contracts 360,248 1,983
Other 461,540 322,687
TOTAL CURRENT LIABILITIES 2,801,637 2,085,676
DEFERRED INCOME TAXES 2,601,402 2,560,921
DEFERRED INVESTMENT TAX CREDITS 350,946 376,250
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 222,042 231,320
DEFERRED CREDITS 263,179 133,616
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $19,483,202 $16,615,346
*See Accompanying Schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
1998 1997 1996
OPERATING ACTIVITIES:
Net Income $ 536,183 $ 510,961 $ 587,430
Adjustments for Noncash Items:
Depreciation and Amortization 619,557 608,217 590,657
Deferred Federal Income Taxes 41,449 (6,549) (21,478)
Deferred Investment Tax Credits (25,304) (25,241) (25,808)
Amortization of Operating Expenses
and Carrying Charges (net) 14,786 12,001 55,458
Equity in Earnings of Yorkshire
Electricity Group plc (38,459) (33,780) -
Extraordinary Item - UK Windfall Tax - 109,419 -
Deferred Costs Under Fuel Clause Mechanisms (73,219) (52,469) 51
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (141,637) (136,186) (39,049)
Fuel, Materials and Supplies 2,108 (1,427) 35,831
Accrued Utility Revenues 3,185 (14,225) 32,953
Accounts Payable 200,195 147,029 (13,915)
Taxes Accrued (826) (33,402) (6,019)
Payment of Disputed Tax and Interest
Related to COLI (302,739) (3,080) -
Other (net) 194,247 116,654 40,951
Net Cash Flows From Operating Activities 1,029,526 1,197,922 1,237,062
INVESTING ACTIVITIES:
Construction Expenditures (792,118) (760,394) (577,691)
Investment in Yorkshire Electricity Group plc - (363,436) -
Investment in CitiPower (1,054,081) - -
Investment in Gas Assets (340,131) - -
Other (26,370) 2,142 12,283
Net Cash Flows Used For
Investing Activities (2,212,700) (1,121,688) (565,408)
FINANCING ACTIVITIES:
Issuance of Common Stock 85,515 76,745 65,461
Issuance of Long-term Debt 2,491,113 880,522 407,291
Retirement of Cumulative Preferred Stock (547) (433,329) (70,761)
Retirement of Long-term Debt (915,294) (348,157) (601,278)
Change in Short-term Debt (net) 61,529 235,380 (45,430)
Dividends Paid on Common Stock (457,638) (453,453) (449,353)
Net Cash Flows From (Used For)
Financing Activities 1,264,678 (42,292) (694,070)
Net Increase (Decrease) in Cash and
Cash Equivalents 81,504 33,942 (22,416)
Cash and Cash Equivalents January 1 91,481 57,539 79,955
Cash and Cash Equivalents December 31 $ 172,985 $ 91,481 $ 57,539
See Notes to Consolidated Financial Statements.
/TABLE
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
Organization - American Electric Power (AEP or the Company) is one
of the United States' (US) largest investor-owned public utility
holding companies engaged in the generation, purchase, transmission
and distribution of electric power to 3 million retail customers in
its seven state service territory which covers portions of Ohio,
Michigan, Indiana, Kentucky, West Virginia, Virginia and Tennessee.
Electric power is also supplied at wholesale to neighboring utility
systems and power marketers. AEP also has other energy holdings in
the US, the United Kingdom (UK), China and Australia.
The organization of AEP consists of American Electric Power
Company, Inc. (AEP Co., Inc.), the parent holding company; seven
domestic regulated electric utility operating companies (domestic
utility subsidiaries); a domestic generating subsidiary, AEP
Generating Company (AEGCo); three active coal-mining companies; a
service company, American Electric Power Service Corporation
(AEPSC); AEP Resources, Inc. (AEPR) which invests in, owns and
operates non-regulated energy-related domestic and international
projects; AEP Energy Services, Inc. (AEPES) which markets and
trades energy commodities; and other subsidiaries that provide non-regulated
energy and communication services.
The following domestic utility subsidiaries pool their generating
and transmission facilities and operate them as an integrated
system: Appalachian Power Company (APCo), Columbus Southern Power
Company (CSPCo), Indiana Michigan Power Company (I&M), Kentucky
Power Company (KPCo) and Ohio Power Company (OPCo). The remaining
two domestic utility subsidiaries, Kingsport Power Company (KGPCo)
and Wheeling Power Company (WPCo) are distribution companies that
purchase power from APCo and OPCo, respectively. AEPSC provides
management and professional services to the AEP System
subsidiaries. The active coal-mining companies are wholly-owned by
OPCo and sell most of their production to OPCo. AEGCo has a 50%
interest in the Rockport Plant which is comprised of two of the AEP
System's six 1,300 megawatt (mw) generating units. AEPR owns 50%
of Yorkshire Electricity Group plc (Yorkshire), a supply and
distribution electric company in the UK (see Note 7); 70% of a
joint venture which is constructing a two-unit power plant nearing
completion in China; 20% of Pacific Hydro, an Australian
hydroelectric generating company; all of the assets of a midstream
natural gas operation in Louisiana and 100% of CitiPower, a
Melbourne, Australia distribution utility. The acquisitions of the
midstream natural gas assets and CitiPower were completed in
December 1998 (see Note 6). AEPES currently markets and trades
natural gas. The non-regulated subsidiaries are engaged in
providing power engineering, consulting and management services
around the world and fiber, wireless and information communication
services in the US.
Although the domestic utility subsidiaries are managed centrally by
AEPSC and operate as American Electric Power they and AEPSC have
not changed their names and remain separate legal entities.
Rate Regulation - The AEP System is subject to regulation by the
Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935 (1935 Act). The rates charged by the
domestic utility subsidiaries are approved by the Federal Energy
Regulatory Commission (FERC) or the state utility commissions as
applicable. The FERC regulates wholesale rates and the state
commissions regulate retail rates.
Principles of Consolidation - The consolidated financial statements
include AEP Co., Inc. and its wholly-owned and majority-owned
subsidiaries consolidated with their wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Yorkshire and Pacific Hydro are accounted for using the equity
method.
Basis of Accounting - As the owner of cost-based rate-regulated
electric public utility companies, AEP Co., Inc.'s consolidated
financial statements reflect the actions of regulators that result
in the recognition of revenues and expenses in different time
periods than enterprises that are not rate regulated. In
accordance with Statement of Financial Accounting Standards (SFAS)
71, "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities
(deferred income) are recorded to reflect the economic effects of
regulation and to match expenses with regulated revenues.
Use of Estimates - The preparation of these financial statements in
conformity with generally accepted accounting principles requires
in certain instances the use of estimates. Actual results could
differ from those estimates.
Regulated Utility Plant - Electric utility plant, which represents
the costs of service rate-regulated fixed assets of the domestic
electric utility subsidiaries, is stated at original cost and is
generally subject to first mortgage liens. Additions, major
replacements and betterments are added to the plant accounts.
Retirements from the plant accounts and associated removal costs,
net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overheads incurred to operate and
maintain regulated domestic utility plant are included in operating
expenses. The distribution utility plant assets of CitiPower are
included in other plant.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a
noncash nonoperating income item that is recovered over the service
life of utility plant through depreciation and represents the
estimated cost of borrowed and equity funds used to finance
construction projects. The amounts of AFUDC for 1998, 1997 and
1996 were not significant.
Depreciation, Depletion and Amortization - Depreciation is provided
on a straight-line basis over the estimated useful lives of
property other than coal-mining property and is calculated largely
through the use of composite rates by functional class. The annual
composite depreciation rates for regulated utility plant for 1998,
1997 and 1996 were as follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.7% to 3.4%
Transmission 1.7% to 2.7%
Distribution 3.3% to 4.2%
General 2.5% to 3.8%
The domestic utility subsidiaries presently recover amounts to be
used for demolition and removal of non-nuclear plant through
depreciation charges included in rates. Depreciation, depletion
and amortization of coal-mining assets is provided over each
asset's estimated useful life or the estimated life of the mine,
whichever is shorter, ranging up to 30 years, and is calculated
using the straight-line method for mining structures and equipment.
The units-of-production method is used to amortize coal rights and
mine development costs based on estimated recoverable tonnages at
a current average rate of $1.85 per ton in 1998, $1.91 per ton in
1997 and $1.49 per ton in 1996. These costs are included in the
cost of coal charged to fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include
temporary cash investments with original maturities of three months
or less.
Foreign Currency Translation - The financial statements of
subsidiaries outside the US are measured using the local currency
as the functional currency. Assets and liabilities are translated
to US dollars at year-end rates of exchange and revenues and
expenses are translated at monthly average exchange rates
throughout the year. Currency translation gain and loss
adjustments are accumulated in shareholders' equity. The
accumulated total of such adjustments at December 31, 1998 and 1997
is not material. Currency transaction gains and losses are
recorded in income.
Derivative Financial Instruments - During 1998, the Company
substantially increased the volume of its wholesale electricity and
natural gas marketing and trading transactions (trading
activities). Trading activities involve the sale of energy under
physical forward contracts at fixed and variable prices and the
trading of energy contracts including exchange traded futures and
options, over-the-counter options and swaps. The majority of these
transactions represent physical forward contracts in the Company's
traditional marketing area and are typically settled by entering
into offsetting contracts. The net revenues from these
transactions in the Company's traditional economic marketing area
are included in regulated revenues for ratemaking, regulatory
accounting and reporting purposes.
The Company has also purchased and sold electricity and gas
options, futures and swaps, and entered into forward purchase and
sale contracts for electricity outside its traditional marketing
area. These transactions represent non-regulated trading
activities that are included in nonoperating income. The
unrealized mark-to-market gains and losses from such non-regulated
trading activity are reported as assets and liabilities,
respectively.
The Company enters into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued. These
anticipatory debt instruments are entered into in order to manage
the change in interest rates between the time a debt offering is
initiated and the issuance of the debt (usually a period of 60
days). Gains or losses are deferred and amortized over the life of
the debt issuance. There were no such forward contracts
outstanding at December 31, 1998 or 1997.
See Note 11 - Financial Instruments, Credit and Risk Management for
further discussion.
Operating Revenues and Fuel Costs - Revenues include the accrual of
electricity consumed but unbilled at month-end as well as billed
revenues. Fuel costs are matched with revenues in accordance with
rate commission orders. Generally in the retail jurisdictions,
changes in fuel costs are deferred or revenues accrued until
approved by the regulatory commission for billing or refund to
customers in later months. Wholesale jurisdictional fuel cost
changes are expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs - In accordance with
SFAS 71 incremental operation and maintenance costs associated with
refueling outages at I&M's Cook Plant are deferred and amortized
over the period beginning with the commencement of an outage and
ending with the beginning of the next outage.
Income Taxes - The Company follows the liability method of
accounting for income taxes as prescribed by SFAS 109, "Accounting
for Income Taxes." Under the liability method, deferred income
taxes are provided for all temporary differences between the book
cost and tax basis of assets and liabilities which will result in
a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in rates,
deferred income taxes are recorded with related regulatory assets
and liabilities in accordance with SFAS 71.
Investment Tax Credits - Investment tax credits have been accounted
for under the flow-through method except where regulatory
commissions have reflected investment tax credits in the rate-making process
on a deferral basis. Deferred investment tax
credits are being amortized over the life of the related plant
investment.
Debt and Preferred Stock - Gains and losses on reacquisition of
debt are deferred and amortized over the remaining term of the
reacquired debt in accordance with rate-making treatment. If the
debt is refinanced, the reacquisition costs are deferred and
amortized over the term of the replacement debt commensurate with
their recovery in rates.
Discount or premium and expenses of debt issuances are amortized
over the term of the related debt, with the amortization included
in interest charges.
Redemption premiums paid to reacquire preferred stock are included
in paid-in capital and amortized to retained earnings commensurate
with their recovery in rates. The excess of par value over costs
of preferred stock reacquired is credited to paid-in capital and
amortized to retained earnings.
Other Plant - Other plant is comprised primarily of the plant and
its related construction work in progress for midstream gas
operations, an Australian distribution company and a Chinese
generation project.
Other Property and Investments - Other property and investments are
comprised primarily of nuclear decommissioning and spent nuclear
fuel disposal trust funds; licenses for operating franchises and
goodwill for the Australian distribution company; amounts for
corporate owned life insurance and a related disputed tax payment;
and the investment in Yorkshire and Pacific Hydro which are
accounted for under the equity method of accounting. Securities
held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are recorded at market value in
accordance with SFAS 115, "Accounting for Certain Investments in
Debt and Equity Securities." Securities in the trust funds have
been classified as available-for-sale due to their long-term
purpose. Unrealized gains and losses from securities in these
trust funds are not reported in equity but result in adjustments to
the liability account for the nuclear decommissioning trust funds
and to regulatory assets or liabilities for the spent nuclear fuel
disposal trust funds. Excluding decommissioning and spent nuclear
fuel disposal trust funds and the investment in Yorkshire and
Pacific Hydro, other property and investments are stated at cost.
EPS - Earnings per share is determined based upon the weighted
average number of shares outstanding. There are no dilutive
potential common shares. Therefore, the computation of earnings
per share is the same for basic earnings per share and diluted
earnings per share.
Comprehensive Income - There were no material differences between
net income and comprehensive income.
Reclassification - In the fourth quarter of 1998 the Company
changed the presentation of its trading activities from a gross
basis (purchases and sales reported separately) to a net basis (net
amount from transactions reported as revenues). This
reclassification had no impact on net income. Certain prior year
amounts have been reclassified to conform to current year
presentation. Such reclassification had no impact on previously
reported net income.
2. Rate Matters:
OPCo's Recovery of Fuel Costs - Under the terms of a 1992
stipulation agreement the cost of coal burned at the Gavin Plant is
subject to a 15-year predetermined price of $1.575 per million
Btu's with quarterly escalation adjustments through November 2009.
A 1995 Settlement Agreement set the fuel component of the electric
fuel component (EFC) factor at 1.465 cents per Kwh for the period
June 1, 1995 through November 30, 1998. With the end of the period
covered by the 1995 Settlement Agreement, the escalated Gavin
predetermined price cap under the stipulation agreement will
determine Ohio jurisdictional fuel recoveries. To the extent the
actual cost of coal burned at the Gavin Plant is below the
predetermined prices, the stipulation agreement provides OPCo with
the opportunity to recover over its term the Ohio jurisdictional
share of OPCo's investment in and the liabilities and future shut-down costs
of its affiliated mines as well as any fuel costs
incurred above the predetermined rate. The Company announced plans
to close the Muskingum mine which supplies all of its output to
OPCo. The mine will be closed in October 1999 and efforts will
begin to reclaim the properties, sell or scrap all mining
equipment, terminate both capital and operating leases and perform
other miscellaneous activities necessary to shut down the mine.
Reclamation activities should be completed approximately two years
after shutdown, postremediation monitoring is anticipated to
continue for five years after completion of reclamation. The
Company established a liability for mine closing costs of $44.6
million comprised of a curtailment loss of $24.7 million,
provisions for workers compensation claims incurred through October
1998 of $4.7 million, severance costs of $4.1 million (related to
approximately 200 employees), postremediation monitoring costs of
$4.9 million, write-off of remaining materials and supplies of $4.6
million and other mine site closure costs of $1.6 million.
Pursuant to terms of the agreements, $18.5 million of these accrued
mine closure costs have been deferred for the Muskingum mine, the
remainder are included in fuel expense on the Consolidated
Statements of Income. For the three years ended December 31, 1998,
1997 and 1996 revenues and net income from the Muskingum mining
operation were $110.2 million and $1,000; $66.3 million and zero;
and $65.5 million and $1.8 million; respectively. After full
recovery of the deferrals or after November 2009, whichever comes
first, the price that OPCo can recover for coal from its affiliated
Meigs mine which supplies the Gavin Plant will be limited to the
lower of cost or market price at the time. Pursuant to these
agreements OPCo has deferred for future recovery $106 million at
December 31, 1998.
Based on the estimated future cost of coal burned at Gavin Plant,
management believes that the Ohio jurisdictional portion of the
investment in and liabilities and closing costs of the affiliated
mining operations including deferred amounts will be recovered
under the terms of the predetermined price agreement. Management
intends to seek from non-Ohio jurisdictional ratepayers recovery of
the non-Ohio jurisdictional portion of the investment in and the
liabilities and closing costs of the affiliated Meigs, Muskingum
and Windsor mines. The non-Ohio jurisdictional portion of shutdown
costs for these mines which includes the investment in the mines,
leased asset buy-outs, reclamation costs and employee benefits is
estimated to be approximately $100 million after tax at December
31, 1998.
Management anticipates closing the Windsor mine in December 2000 in
order to comply with the Phase II requirements of the Clean Air Act
Amendments of 1990 (CAAA) or it could close earlier depending on
the economics of continued operation under the terms of the above
stipulation agreement. Unless the cost of affiliated coal
production and/or shutdown costs of the Meigs, Muskingum and
Windsor mines can be recovered, results of operations, cash flows
and possibly financial condition would be adversely affected.
3. Effects of Regulation and Phase-In Plans:
In accordance with SFAS 71 the consolidated financial statements
include assets (deferred expenses) and liabilities (deferred
income) recorded in accordance with regulatory actions to match
expenses and revenues from cost-based rates. Regulatory assets are
expected to be recovered in future periods through the rate-making
process and regulatory liabilities are expected to reduce future
cost recoveries. Management has reviewed the evidence currently
available and concluded that it continues to meet the requirements
to apply SFAS 71. In the event a portion of the Company's business
no longer met these requirements, net regulatory assets would have
to be written off for that portion of the business and assets
attributable to that portion of the business would have to be
tested for possible impairment and if required an impairment loss
recorded unless the net regulatory assets and impairment losses are
recoverable as a stranded cost.
Recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
1998 1997
(in thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,324,217 $1,372,926
Deferred Fuel Costs 193,430 75,552
Unamortized Loss on Reacquired Debt 90,997 96,793
Other 238,074 272,269
Total Regulatory Assets $1,846,718 $1,817,540
Regulatory Liabilities:
Deferred Investment Tax Credits $350,946 $376,250
Other Regulatory Liabilities* 147,569 78,802
Total Regulatory Liabilities $498,515 $455,052
* Included in Deferred Credits on Consolidated Balance Sheets
At January 1, 1997 rate phase-in plan deferrals existed for the
Zimmer Plant and Rockport Plant Unit 1. The Zimmer Plant is a
1,300 mw coal-fired plant which commenced commercial operation in
1991. CSPCo owns 25.4% of the plant with the remainder owned by
two unaffiliated companies. As a result of an Ohio Supreme Court
decision, in January 1994 the PUCO approved a temporary 3.39%
surcharge effective February 1, 1994. In June 1997 the Company
completed recovery of its Zimmer Plant phase-in plan deferrals and
discontinued the 3.39% temporary rate surcharge. In 1997 and 1996
$15.4 million and $31.5 million, respectively, of net phase-in
deferrals were collected through the surcharge.
The Rockport Plant consists of two 1,300 mw coal-fired units. I&M
and AEGCo each own 50% of one unit (Rockport 1) and lease a 50%
interest in the other unit (Rockport 2) from unaffiliated lessors
under an operating lease. The gain on the sale and leaseback of
Rockport 2 was deferred and is being amortized, with related taxes,
over the initial lease term which expires in 2022. Rate phase-in
plans in the Indiana and the FERC jurisdictions provided for the
recovery and straight-line amortization of deferred Rockport Plant
Unit 1 costs over a ten year period that ended in 1997. In 1997
and 1996 amortization and recovery of the deferred Rockport Plant
Unit 1 phase-in plan costs were $11.9 million and $15.6 million,
respectively. During the recovery period net income was unaffected
by the recovery of the phase-in deferrals.
4. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial
construction commitments to support its utility operations
including the replacement of the Cook Plant Unit 1 steam
generators. Such commitments do not presently include any
expenditures for new generating capacity. Aggregate construction
expenditures for 1999-2001 are estimated to be $2.4 billion
including construction cost estimates for the newly acquired
CitiPower and midstream gas assets.
Long-term domestic fuel supply contracts contain clauses for
periodic price adjustments, and most domestic jurisdictions have
fuel clause mechanisms that provide for recovery of changes in the
cost of fuel with the regulators' review and approval. The
contracts are for various terms, the longest of which extends to
the year 2014, and contain various clauses that would release the
Company from its obligation under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,100 mw of
capacity domestically on a long-term basis to unaffiliated
utilities. Certain contracts totaling 750 mw of capacity are unit
power agreements requiring the delivery of energy only if the unit
capacity is available. The power sales contracts expire from 1999
to 2010.
Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook
Plant under licenses granted by the Nuclear Regulatory Commission
(NRC). The operation of a nuclear facility involves special risks,
potential liabilities, and specific regulatory and safety
requirements. Should a nuclear incident occur at any nuclear power
plant facility in the US, the resultant liability could be
substantial. By agreement I&M is partially liable together with
all other electric utility companies that own nuclear generating
units for a nuclear power plant incident. In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds
and recovery in rates is not possible, results of operations, cash
flows and financial condition could be negatively affected.
Nuclear Plant Shutdown - I&M shut down both units of the Cook
Nuclear Plant in September 1997 due to questions, which arose
during a NRC architect engineer design inspection, regarding the
operability of certain safety systems. 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 remaining open issue in the letter.
In April 1998 the NRC notified I&M that it had convened a Restart
Panel for Cook Plant. A list of required restart activities was
provided by the NRC in July 1998 and in October the NRC expanded
the list. In order to identify and resolve the issues necessary to
restart the Cook units, I&M is and will be meeting with the Panel
on a regular basis, until the units are returned to service.
In January 1999 I&M announced that it will conduct additional
engineering reviews at the Cook Plant that will delay restart of
the units. Previously, the units were scheduled to return to
service at the end of the first and second quarters of 1999. The
decision to delay restart resulted from internal assessments that
indicated a need to conduct expanded system readiness reviews. A
new restart schedule will be developed based on the results of the
expanded reviews and should be available in June 1999. 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. Until these additional reviews are completed, management
is unable to determine when the units will be returned to service.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows and possibly financial
condition.
The incremental cost incurred in 1997 and 1998 for restart of the
Cook units were $6 million and $78 million, respectively, and
recorded as operation and maintenance expense. Currently
incremental restart expenses are approximately $12 million a month.
In July 1998 I&M received an "adverse trend letter" from the NRC
indicating that NRC senior managers determined that there had been
a slow decline in performance at the Cook Plant during the 18 month
period preceding the letter. The letter indicated that the NRC
will closely monitor efforts to address issues at Cook Plant
through additional inspection activities. In October 1998 the NRC
issued 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 1997 and April 1998. I&M
paid the penalty.
The cost of electricity supplied to certain retail customers rose
due to the outage of the two units since higher cost coal-fired
generation and coal based purchased power were substituted for low
cost nuclear generation. I&M's Indiana and Michigan retail
jurisdictional 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. The Indiana Utility Regulatory Commission
approved, subject to future reconciliation or refund, agreements
authorizing I&M, during the billing months of July 1998 through
March 1999, to include in rates a fuel cost adjustment factor less
than that requested by I&M. 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. A regulatory
asset in the amount of $65 million has been recorded at December
31, 1998.
Historically, the Company has been permitted to recover through the
fuel recovery mechanism the cost of replacement energy during
outages. Management believes that it should be allowed to recover
the deferred Cook replacement energy costs; however, if recovery of
the replacement costs is denied, future results of operations and
cash flows would be adversely affected by the writeoff of the
regulatory asset.
Nuclear Incident Liability - Public liability is limited by law to
$9 billion should an incident occur at any licensed reactor in the
United States. Commercially available insurance provides $200
million of coverage. In the event of a nuclear incident at any
nuclear plant in the US the remainder of the liability would be
provided by a deferred premium assessment of $88 million on each
licensed reactor payable in annual installments of $10 million. As
a result, I&M could be assessed $176 million per nuclear incident
payable in annual installments of $20 million. The number of
incidents for which payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide $3
billion of property damage, decommissioning and decontamination
coverage for the Cook Plant. Additional insurance provides
coverage for extra costs resulting from a prolonged accidental Cook
Plant outage. Some of the policies have deferred premium
provisions which could be triggered by losses in excess of the
insurer's resources. The losses could result from claims at the
Cook Plant or certain other unaffiliated nuclear units. I&M could
be assessed up to $23.2 million annually under these policies.
Spent Nuclear Fuel (SNF) Disposal - Federal law provides for
government responsibility for permanent SNF disposal and assesses
nuclear plant owners fees for SNF disposal. A fee of one mill per
kilowatthour for fuel consumed after April 6, 1983 is being
collected from customers and remitted to the US Treasury. Fees and
related interest of $190 million for fuel consumed prior to April
7, 1983 have been recorded as long-term debt. I&M has not paid the
government the pre-April 1983 fees due to continued delays and
uncertainties related to the federal disposal program. At December
31, 1998, funds collected from customers towards payment of the
pre-April 1983 fee and related earnings thereon approximate the
liability.
Decommissioning and Low Level Waste Accumulation Disposal -
Decommissioning costs are accrued over the service life of the Cook
Plant. The licenses to operate the two nuclear units expire in
2014 and 2017. After expiration of the licenses the plant is
expected to be decommissioned through dismantlement. The Company's
latest estimate for decommissioning and low level radioactive waste
accumulation disposal costs ranges from $700 million to $1,152
million in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions including the estimated length of time SNF
may need to be stored at the plant site subsequent to ceasing
operations. This, in turn, depends on future developments in the
federal government's SNF disposal program. Continued delays in the
federal fuel disposal program can result in increased
decommissioning costs. I&M is recovering estimated decommissioning
costs in its three rate-making jurisdictions based on at least the
lower end of the range in the most recent decommissioning study at
the time of the last rate proceeding. I&M records decommissioning
costs in other operation expense and records an increase in its
noncurrent liabilities equal to the decommissioning cost recovered
in rates; such amounts were $29 million in 1998, $28 million in
1997 and $27 million in 1996. Decommissioning costs recovered from
customers are deposited in external trusts. Trust fund earnings
increase the fund assets and the recorded liability and decrease
the amount needed to be recovered from ratepayers. During 1998 I&M
withdrew $3 million and expects to withdrawal $8 million in 1999
for decommissioning of original steam generators removed from Unit
2. At December 31, 1998 and 1997, I&M has recognized a
decommissioning liability of $446 million and $381 million,
respectively, which is included in other noncurrent liabilities.
Clean Air Act/Air Quality - The US Environmental Protection Agency
(Federal EPA) is required by the CAAA to issue rules to implement
the law. In 1996 Federal EPA issued final rules governing nitrogen
oxides (NOx) emissions that must be met after January 1, 2000
(Phase II of CAAA). The final rules will require substantial
reductions in NOx emissions from certain types of boilers including
those in AEP's power plants. To comply with Phase II of CAAA, the
Company plans to install NOx emission control equipment on certain
units and switch fuel at other units. Total capital costs to meet
the requirements of Phase II of CAAA are estimated to be
approximately $90 million of which $69 million has been incurred
through December 31, 1998.
On September 24, 1998, Federal EPA finalized 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 state implementation plans (SIPs) by September 1999.
SIPs are a procedural method used by each state to comply with
Federal EPA rules. The final rules anticipate the imposition of a
NOx reduction on utility sources of approximately 85% below 1990
emission levels by the year 2003. On October 30, 1998, a number of
utilities, including the operating companies of the AEP System,
filed petitions in the US 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 petitions filed by eight northeastern
states that would result in imposition of NOx emission reductions
on utility and industrial sources in upwind midwestern states.
These reductions are substantially the same as those required by
the final NOx rules and could be adopted by Federal EPA in the
event the states fail to implement SIPs in accordance with the
final rules.
Preliminary estimates indicate that compliance costs could result
in required capital expenditures of approximately $1.2 billion for
the AEP System. Compliance costs cannot be estimated with
certainty and the actual costs incurred to comply could be
significantly different from this preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
Litigation - The Internal Revenue Service (IRS) agents auditing the
AEP System's consolidated federal income tax returns requested a
ruling from their National Office that certain interest deductions
claimed by the Company relating to AEP's corporate owned life
insurance (COLI) program should not be allowed. As a result of a
suit filed in US District Court (discussed below) this request for
ruling was withdrawn by the IRS agents. Adjustments have been or
will be proposed by the IRS disallowing COLI interest deductions
for taxable years 1991-96. A disallowance of the COLI interest
deductions through December 31, 1998 would reduce earnings by
approximately $316 million (including interest). The Company has
made no provision for any possible adverse earnings impact from
this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount. The payments
to the IRS are included on the 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 plus interest. In order to resolve this issue
without further delay, on March 24, 1998, the Company filed suit
against the US in the US District Court for the Southern District
of Ohio. Management believes that it has a meritorious position
and will vigorously pursue this lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations, cash flows and possibly
financial condition.
The Company is involved in a number of other legal proceedings and
claims. While management is unable to predict the ultimate outcome
of litigation, it is not expected that the resolution of these
matters will have a material adverse effect on the results of
operations, cash flows or financial condition.
5. Proposed Merger
In December 1997 the Company and Central and South West Corporation
(CSW) agreed to merge. At the 1998 annual meeting AEP shareholders
approved the issuance of common shares to effect the merger and
approved an increase in the number of authorized shares of AEP
Common Stock from 300,000,000 to 600,000,000 shares. CSW
stockholders approved the merger at their May 1998 annual meeting.
Approval of the merger has been requested from the FERC, the SEC,
the NRC and all of CSW's state regulatory commissions: Arkansas,
Louisiana, Oklahoma and Texas. In the near future, AEP and CSW
plan to make the final two filings associated with approval of the
merger with the Federal Communications Commission and the
Department of Justice.
Regulatory approvals for the merger have been received from the
Arkansas Public Service Commission (APSC) and the NRC. In December
1998 the APSC approved a stipulated agreement related to a proposed
merger regulatory plan submitted by the Company, CSW and CSW's
Arkansas operating subsidiary, Southwestern Electric Power Company.
The regulatory plan, agreed to with the APSC staff, provides for a
sharing of net merger savings through a $6 million rate reduction
over 5 years following the completion of the merger.
The application to the NRC by CSW's operating subsidiary, Central
Power and Light Company (CPL), requesting permission to transfer
indirect control of the license from CSW to AEP for CPL's interest
in the South Texas Project nuclear generating station was approved
by the NRC in November 1998.
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
sufficient information regarding the potential impact of the merger
on the retail electric market in Oklahoma. An amended application
was filed in Oklahoma in February 1999. Submission of the amended
application will reset Oklahoma's 90-day statutory time period for
OCC action on the merger phase of the application.
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
signatories. The settlement provides for, among other things, rate
reductions totaling approximately $180 million over a six year
period following completion of the merger to share net merger
savings of $84 million and settle existing rate issues of $96
million. Hearings are scheduled for April 1999.
In July 1998 the FERC issued an order which confirmed that a 250
megawatt firm contract path with the Ameren System is available.
The contract path was obtained by AEP and CSW to meet the
requirement of the 1935 Act that the two systems operate on an
integrated and coordinated basis.
In November 1998 the FERC issued an order establishing hearing
procedures for the merger and scheduled the hearings to begin on
June 1, 1999. The FERC 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 which was done in January
1999.
The proposed merger of CSW into AEP would result in common
ownership of two UK regional electricity companies (RECs),
Yorkshire and Seeboard, plc. AEP has a 50% interest in Yorkshire
and CSW has a 100% interest in Seeboard. Although the merger of
CSW into AEP is not subject to approval by UK regulatory
authorities, the common ownership of two UK RECs could be referred
by the UK Secretary of State for Trade and Industry to the UK
Monopolies and Mergers Commission for investigation.
AEP has received a request from the staff of the Kentucky Public
Service Commission (KPSC) to file an application seeking KPSC
approval for the indirect change in control of Kentucky Power
Company that will occur as a result of the proposed merger.
Although AEP does not believe that the KPSC has the jurisdictional
authority to approve the merger, management will prepare a merger
application filing to be made with the KPSC, which is expected to
be filed by April 15, 1999. Under the governing statute the KPSC
must act on the application within 60 days. Therefore this is not
expected to impact the timing of the merger.
The merger is conditioned upon, among other things, the approval of
the above state and federal regulatory agencies. The transaction
must satisfy many conditions a number of which may not be waived by
the parties, including the condition that the merger must be
accounted for as a pooling of interests. The merger agreement will
terminate on December 31, 1999 unless extended by either party as
provided in the merger agreement. Although consummation of the
merger is expected to occur in the fourth quarter of 1999, the
Company is unable to predict the outcome or the timing of the
required regulatory proceedings.
As of December 31, 1998 the Company had deferred $20 million of
incremental costs incurred in connection with the proposed merger.
The amounts deferred are included in deferred charges on the
Consolidated Balance Sheets.
6. Acquisitions
The Company completed two non-regulated energy related acquisitions
in 1998 through a subsidiary, AEPR. Both acquisitions have been
included in the December 31, 1998 consolidated financial statements
using the purchase method of accounting. The first acquisition was
of CitiPower, an Australian distribution utility, that serves
approximately 240,000 customers in Melbourne with 3,100 miles of
distribution lines in a service area of approximately 100 square
miles. All of the stock of CitiPower was acquired on December 31,
1998 for approximately $1.1 billion. The acquisition of CitiPower
had no effect on the results of operations for 1998. The financial
statements reflect a preliminary purchase price allocation.
Estimated goodwill of $557 million has been recorded in other
property and investments which will be amortized over a period of
not more than 40 years.
The second acquisition was of midstream gas operations that include
a fully integrated natural gas gathering, processing, storage and
transportation operation in Louisiana and a gas trading and
marketing operation in Houston. The gas operations were acquired
for approximately $340 million, including working capital funds, on
December 1, 1998 with one month of earnings reflected in AEP's
consolidated results of operations for the year ended December 31,
1998. The financial statements reflect a preliminary purchase
price allocation. Estimated goodwill of approximately $158 million
for the midstream gas storage operations and $17 million for the
gas trading and marketing operation has been recorded in other
property and investments and is being amortized on a straight-line
basis over not more than 40 years and 10 years, respectively.
7. Yorkshire Acquisition and UK Windfall Tax
In April 1997 the Company and New Century Energies, Inc. through an
equally owned joint venture, Yorkshire Power Group Limited (YPG),
acquired all of the outstanding shares of Yorkshire. Total
consideration paid by the joint venture was approximately $2.4
billion which was financed by a combination of equity and non-recourse debt.
The Company uses the equity method of accounting
for its investment in YPG. The Company's investment in the joint
venture was $325.8 million and $287.4 million at December 31, 1998
and 1997, respectively, and is included in other property and
investments.
In July 1997 the British government enacted a new law that imposed
a one-time windfall tax on a revised privatization value which
originally had been computed in 1990 on certain privatized
utilities. The windfall tax is actually an adjustment by the UK
government of the original privatization price. The windfall tax
liability for Yorkshire was 134 million pounds sterling ($219
million) and was paid in two equal installments made in December
1997 and December 1998. The Company's $109.4 million share of the
tax is reported as an extraordinary loss in 1997.
The 1998 equity earnings from the Yorkshire investment are $38.5
million and are included in nonoperating income. Equity earnings
from the Yorkshire investment for 1997, excluding the extraordinary
loss, were $34 million.
The following amounts which are not included in AEP's consolidated
financial statements represent summarized consolidated financial
information of YPG:
December 31,
1998 1997
(in millions)
Assets:
Property, Plant and Equipment $1,602.2 $1,644.6
Current Assets 552.2 602.2
Goodwill (net) 1,547.3 1,602.5
Other Assets 294.5 292.9
Total Assets $3,996.2 $4,142.2
Capitalization and Liabilities:
Common Shareholders' Equity $ 666.4 $ 542.1
Long-term Debt 2,121.3 704.3
Other Noncurrent Liabilities 413.5 488.7
Long-term Debt Within One Year 13.3 1,776.4
Current Liabilities 781.7 630.7
Total Capitalization and
Liabilities $3,996.2 $4,142.2
Twelve Months Ended Nine Months Ended
December 31, 1998 December 31, 1997
(in millions)
Income Statement Data:
Operating Revenues $2,284.0 $1,492.9
Operating Income 298.0 202.3
Income Before
Extraordinary Item 76.9 67.5
Net Income (Loss) 76.9 (151.3)
8. Staff Reductions
During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing an optimum
organizational structure for a competitive generation market. The
study was completed in October 1998 and called for the elimination
of approximately 450 positions. In addition, a review of energy
delivery staffing levels in 1998 identified 65 positions for
elimination.
Severance accruals totaling $25.5 million were recorded in December
1998 for reductions in power generation and energy delivery staffs
and were charged to other operation expense in the Consolidated
Statements of Income. In January 1999, employment terminated for
65 energy delivery employees. In February 1999 the power
generation staff reductions were made.
9. Benefit Plans:
AEP System Pension and Other Postretirement Benefit Plans - The AEP
System sponsors a qualified pension plan and a nonqualified pension
plan. All employees, except participants in the United Mine
Workers of America (UMWA) pension plans are covered by one or both
of the pension plans. Other Postretirement Benefit Plans (OPEB)
are sponsored by the AEP System to provide medical and death
benefits for retired employees.
The following tables provide a reconciliation of the changes in the
plans' benefit obligations and fair value of assets over the two-year
period ending December 31, 1998, and a statement of the funded
status as of December 31 for both years:
Pension Plan OPEB
1998 1997 1998 1997
(in thousands)
Reconciliation of benefit
obligation:
Obligation at January 1 $1,909,400 $1,676,200 $ 849,700 $726,400
Service Cost 45,100 36,000 17,500 14,000
Interest Cost 133,200 128,600 59,300 55,900
Participant Contributions - - 5,900 5,300
Plan Amendments (a) 48,400 - - -
Actuarial Loss 96,000 170,500 133,100 90,900
Acquisitions (b) 100 - 2,800 -
Benefit Payments (105,900) (101,900) (46,600) (42,800)
Obligation at December 31 $2,126,300 $1,909,400 $1,021,700 $849,700
Reconciliation of fair value
of plan assets:
Fair value of plan assets at
January 1 $2,370,300 $2,009,500 $311,900 $232,500
Actual Return on Plan Assets 385,900 462,700 52,600 44,100
Company Contributions 400 - 72,600 72,800
Participant Contributions - - 5,900 5,300
Benefit Payments (105,900) (101,900) (46,600) (42,800)
Fair value of plan assets at
December 31 $2,650,700 $2,370,300 $396,400 $311,900
Funded status:
Funded status at December 31 $ 524,400 $ 460,900 $(625,300)$(537,800)
Unrecognized Net Transition
(Asset) Obligation (49,200) (59,100) 360,700 416,400
Unrecognized Prior-Service Cost 157,400 123,500 - -
Unrecognized Actuarial
(Gain) Loss (756,300) (640,800) 175,000 66,100
Accrued Benefit Liability $(123,700) $(115,500) $ (89,600)$ (55,300)
(a) Early retirement factors for the Company pension plan were changed to
provide more generous benefits to participants retiring between ages
55 and 60.
(b) On December 1, 1998 the Company acquired midstream gas operations resulting
in approximately 170 new employees becoming participants in the Company's
pension and OPEB plans.
The following table provides the amounts recognized in the
consolidated balance sheets as of December 31 of both years:
Pension Plan OPEB
1998 1997 1998 1997
(in thousands)
Accrued Benefit Liability $(123,700) $(115,500) $(89,600) $(55,300)
Additional Minimum Liability (3,400) (900) - -
Intangible Asset 3,400 900 - -
Net Amount Recognized $(123,700) $(115,500) $(89,600) $(55,300)
The Company's nonqualified pension plan had an accumulated benefit
obligation in excess of plan assets of $25 million and $19.4
million at December 31, 1998 and 1997, respectively. There are no
plan assets in the nonqualified plan due to the nature of the plan.
The Company's OPEB plans had accumulated benefit obligations in
excess of plan assets of $625.3 million and $537.8 million at
December 31, 1998 and 1997, respectively.
The following table provides the components of net periodic benefit
cost for the plans for fiscal years 1998 and 1997:
Pension Plan OPEB
1998 1997 1998 1997
(in thousands)
Service cost $ 45,100 $ 36,000 $ 17,500 $ 14,000
Interest cost 133,200 128,600 59,300 55,900
Expected return on
plan assets (172,000) (154,200) (28,500) (22,200)
Amortization of transition
(asset) obligation (9,900) (9,900) 32,000 32,000
Amortization of prior-service
cost 14,400 13,800 - -
Amortization of net actuarial
(gain) loss (2,600) (4,700) 200 (400)
Net periodic benefit cost 8,200 9,600 80,500 79,300
Curtailment loss - - 24,100(a) -
Net periodic benefit cost
after curtailments $ 8,200 $ 9,600 $104,600 $ 79,300
(a) Curtailment charges were recognized during 1998 in anticipation of the
October 31, 1999 shutdown of Muskingum Mine by Central Ohio Coal Company, a
subsidiary of AEP.
The assumptions used in the measurement of the Company's benefit
obligation are shown in the following table:
Pension Plan OPEB
1998 1997 1998 1997
Weighted-average assumptions
as of December 31
Discount rate 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets 9.00% 9.00% 8.75% 8.75%
Rate of compensation increase 3.2% 3.2% N/A N/A
For measurement purposes, a 5.5% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 1999.
The rate was assumed to decrease gradually each year to a rate of
4.25% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on
the amounts reported for the OPEB health care plans. A 1% change
in assumed health care cost trend rates would have the following
effects:
1% Increase 1% Decrease
(in thousands)
Effect on total of service and
interest cost components of
net periodic postretirement
health care benefit cost $ 9,700 $ (8,400)
Effect on the health care
component of the accumulated
postretirement benefit obligation 113,000 (99,800)
CitiPower, a subsidiary acquired on December 31, 1998 sponsors a
defined benefit pension plan. At December 31, 1998, the fair value
of the plan assets was $24.6 million and the accumulated benefit
obligation of this plan was $25.3 million. This plan's actuarial
assumptions are not significantly different from AEP's.
AEP System Savings Plan - The AEP System Savings Plan is a defined
contribution plan offered to non-UMWA employees. The cost for
contributions to this plan totaled $20.5 million in 1998, $19.6
million in 1997 and $19 million in 1996.
Other UMWA Benefits - The Company provides UMWA pension, health and
welfare benefits for certain unionized mining employees, retirees,
and their survivors who meet eligibility requirements. The
benefits are administered by UMWA trustees and contributions are
made to their trust funds. Contributions based on hours worked are
expensed as paid as part of the cost of active mining operations
and were not material in 1998, 1997 and 1996. Based upon the UMWA
actuary estimate, the Company's share of unfunded pension liability
was $28 million at June 30, 1998. In the event the Company should
significantly reduce or cease mining operations or contributions to
the UMWA trust funds, a withdrawal obligation will be triggered for
both the pension and health and welfare plans. If the mining
operations had been closed on December 31, 1998 the estimated
annual withdrawal liability for all UMWA benefit plans would have
been $6.5 million. The UMWA withdrawal liability for the
anticipated shutdown of Central Ohio Coal Company's Muskingum mine
has been included as a curtailment loss in the net periodic benefit
cost under the Company's OPEB plans in 1998.
10. Business Segments
As of December 31, 1998, the Company adopted SFAS 131, "Disclosure
about Segments of an Enterprise and Related Information." SFAS 131
established standards for reporting information about operating
segments in annual financial statements and requires selected
information about operating segments in interim financial reports
issued to shareholders. It also established standards for related
disclosures about products and services, and geographic areas.
Operating segments are defined as components of an enterprise about
which separate financial information is available and evaluated
regularly by the chief operating decision maker.
The Company's reportable segments are primarily differentiated
based on whether the business activity is conducted within a
regulated environment. The Company manages its operations on this
basis because of the substantial impact of regulatory oversight on
business processes, cost structures and operating results.
The Company's principal business segment is its cost based rate
regulated Domestic Electric Utilities business consisting of seven
regulated utility operating companies providing retail, commercial,
industrial and wholesale electric services in seven Atlantic and
Midwestern states. Also included in this segment are the Company's
electric power wholesale marketing and trading activities that are
conducted as part of regulated operations and subject to regulatory
ratemaking oversight. The World Wide Energy Investments segment
represents principally international investments in energy-related
projects and operations. It also includes the development and
management of such projects and operations. Such investment
activities include electric generation, supply and distribution,
and natural gas pipeline, storage and other natural gas services.
Other business segments include non-regulated electric and gas
trading activities, telecommunication services, and the marketing
of various energy saving products and services. Intersegment
revenues, ie. revenues from transactions with operating segments,
are not material. As of December 31, 1998 and 1997 less than 6% of
long-lived assets were located in foreign countries.
World
Regulated Domestic Wide Energy Reconciling AEP
Year Electric Utilities Investments Other Adjustments Consolidated
(in thousands)
1998
Revenues from
external customers $6,345,900 $57,600 $(28,300) $(29,300) $6,345,900
Revenues from transactions
with other operating
segments - 1,600 1,900 (3,500) -
Interest revenues 400 200 600
Interest expense 399,200 16,900 3,000 419,100
Depreciation, depletion and
amortization expense 580,000 1,000 1,400 (2,400) 580,000
Net income (loss) for equity
method subsidiaries - 38,600 - 38,600
Income tax expense (benefit) 299,100 (15,300) (21,200) 262,600
Segment net income (loss) 563,400 12,300 (39,500) 536,200
Total assets 16,837,300 2,063,300 582,600 19,483,200
Investments in equity method
subsidiaries 100 335,200 - 335,300
Gross property additions 699,700 1,481,000 23,000 2,203,700
1997
Revenues from
external customers $5,879,800 $14,600 $ 2,200 $(16,800) $5,879,800
Revenues from transactions
with other operating
segments - - - - -
Interest revenues - 1,700 - 1,700
Interest expense 390,300 14,900 600 405,800
Depreciation, depletion and
amortization expense 591,100 - - - 591,100
Net income for equity method
subsidiaries - 33,300 - - 33,300
Income tax expense (benefit) 330,100 (25,000) (6,600) 298,500
Extraordinary Loss -
UK Windfall Tax - (109,400) - - (109,400)
Segment net income (loss) 602,900 (79,600) (12,300) 511,000
Total assets 16,223,700 367,100 24,500 16,615,300
Investments in equity method
subsidiaries 100 287,300 - 287,400
Gross property additions 694,400 62,400 3,600 760,400
1996
Revenues from
external customers $5,849,200 $12,500 $ - $(12,500) $5,849,200
Revenues from transactions
with other operating
segments - 100 - (100) -
Interest revenues - - - - -
Interest expense 381,000 300 - - 381,300
Depreciation, depletion and
amortization expense 600,900 - - - 600,900
Income tax expense (benefit) 325,500 (1,000) (1,900) 322,600
Segment net income (loss) 597,600 (6,600) (3,600) 587,400
Total assets 15,858,900 5,100 19,000 15,883,000
Investments in equity method
subsidiaries 100 - - 100
Gross property additions 577,700 - - 577,700
11. Financial Instruments, Credit and Risk Management
The Company is subject to market risk as a result of changes in
commodity prices, foreign currency exchange rates, and interest
rates. The Company has a wholesale electricity and gas trading and
marketing operation that manages the exposure to commodity price
movements using physical forward purchase and sale contracts at
fixed and variable prices, and financial derivative instruments
including exchange traded futures and options, over-the-counter
options, swaps and other financial derivative contracts at both
fixed and variable prices. Physical forward electricity contracts
and certain qualifying hedges within AEP's traditional economic
market area are recorded as net operating revenues in the month
when the physical contract settles. Net gains for the year ended
December 31, 1998 were $111 million. Physical forward electricity
contracts outside AEP's traditional marketing area, and all
financial electricity trading transactions which do not qualify as
a hedge, and/or where the underlying physical commodity is outside
AEP's traditional economic market area are marked to market and
recorded net in nonoperating income. Net losses for the year ended
December 31, 1998 were $37 million. All physical and financial
instruments for natural gas are marked to market and are included
on a net basis in nonoperating income. Net gains for the year
ended December 31, 1998 were $6 million. The unrealized mark-to-market
gains and losses from such trading of financial instruments
are reported as assets and liabilities, respectively. These
activities were not material in prior periods.
Investment in foreign ventures exposes the Company to risk of
foreign currency fluctuations. Also, the Company is exposed to
changes in interest rates primarily due to short- and long-term
borrowings used to fund its business operations. The debt
portfolio has both fixed and variable interest rates with terms
from one day to forty years and an average duration of 5 years at
December 31, 1998. The Company does not presently utilize
derivatives to manage its exposures to foreign currency exchange
rate movements.
Market Valuation - The book value amounts of cash and cash
equivalents, accounts receivable, short-term debt and accounts
payable approximate fair value because of the short-term maturity
of these instruments. The book value amount of the pre-April 1983
spent nuclear fuel disposal liability approximates the Company's
best estimate of its fair value.
The book value amounts and fair values of the Company's significant
financial instruments at December 31, 1998 are summarized in the
following table. The fair values of long-term debt and preferred
stock are based on quoted market prices for the same or similar
issues and the current dividend or interest rates offered for
instruments of the same remaining maturities. The fair value of
those financial instruments that are marked-to-market are based on
management's best estimates using over-the-counter quotations,
exchange prices, volatility factors and valuation methodology. The
estimates presented herein are not necessarily indicative of the
amounts that the Company could realize in a current market
exchange.
Book Value Fair Value
(in thousands)
Non-Derivatives
1998
Long-term Debt $7,006,100 $7,291,200
Preferred Stock 127,600 134,100
1997
Long-term Debt 5,423,900 5,670,400
Preferred Stock 127,600 136,000
Derivatives
Trading Assets
Notional Amount Fair Value Average Fair Value
(in thousands)
Electric
Physicals $ (62,000) $ 46,100 $ 40,800
Options (4,700) 32,200 79,000
Swaps (15,600) 3,400 1,000
Gas
Futures (70,300) 5,900 1,900
Physicals (285,200) 43,600 29,900
Options (3,600) 18,000 11,700
Swaps 1,477,900 245,600 143,000
Trading Liabilities
Electric
Futures 20,300 (7,200) (1,800)
Physicals 27,500 (50,600) (46,300)
Options 9,700 (28,700) (78,300)
Swaps 16,200 (7,700) (1,900)
Gas
Physicals 283,900 (42,400) (28,700)
Options 4,700 (22,600) (14,100)
Swaps (1,524,900) (231,200) (135,700)
At December 31, 1998 the fair value of the assets and liabilities
related to the wholesale electric forward contracts was $367
million and $356 million, respectively. The respective notional
amounts were $828 million and $772 million, respectively. The
average fair value amounts outstanding during the period were $922
million of assets and $882 million of liabilities.
AEP routinely enters into exchange traded futures and options
transactions for electricity and natural gas as part of its
wholesale trading operations. These transactions are executed
through brokerage accounts with brokers who are registered with the
Commodity Futures Trading Commission. Brokers require cash or cash
related instruments to be deposited on these accounts as margin
calls against the customer's open position. The amount of these
deposits at December 31, 1998 was $10 million.
Credit and Risk Management - In addition to market risk associated
with price movements, AEP is also subject to the credit risk
inherent in its risk management activities. Credit risk refers to
the financial risk arising from commercial transactions and/or the
intrinsic financial value of contractual agreements with trading
counter parties, by which there exists a potential risk of
nonperformance. The Company has established and enforced credit
policies that minimize or eliminate this risk. AEP accepts as
counter parties to forwards, futures, and other derivative
contracts primarily those entities that are classified as
Investment Grade, or those that can be considered as such due to
the effective placement of credit enhancements and/or collateral
agreements. Investment Grade is the designation given to the four
highest debt rating categories (i.e., AAA, AA, A, BBB) of the major
rating services, e.g., ratings BBB- and above at Standard & Poor's
and Baa3 and above at Moody's. When adverse market conditions have
the potential to negatively affect a counter party's credit
position, the Company will require further enhancements to mitigate
risk. Since the formation of the trading business in July of 1997,
the Company has experienced no significant losses due to the credit
risk associated with its risk management activities; furthermore,
the Company does not anticipate any future material effect on its
results of operations, cash flow or financial condition as a result
of counter party nonperformance.
Other Financial Instruments - Nuclear Trust Funds Recorded at
Market Value - The trust investments, reported in other property
and investments, are recorded at market value in accordance with
SFAS 115 and consist of tax-exempt municipal bonds and other
securities.
At December 31, 1998 and 1997 the fair values of the trust
investments were $648 million and $566 million, respectively, and
had a cost basis of $584 million and $527 million, respectively.
Accumulated gross unrealized holding gains were $65 million and $41
million at December 31, 1998 and 1997, respectively and accumulated
gross unrealized holding losses were $1.1 million and $1.2 million
at December 31, 1998 and 1997, respectively. The change in market
value in 1998, 1997, and 1996 was a net unrealized holding gain of
$24 million, $19.1 million, and $2.6 million, respectively.
The trust investments' cost basis by security type were:
December 31,
1998 1997
(in thousands)
Tax-Exempt Bonds $326,239 $335,358
Equity Securities 95,854 74,398
Treasury Bonds 71,194 44,200
Corporate Bonds 10,661 9,167
Cash, Cash Equivalents and
Accrued Interest 80,065 63,392
Total $584,013 $526,515
Proceeds from sales and maturities of securities of $225 million
during 1998 resulted in $8.2 million of realized gains and $2.8
million of realized losses. Proceeds from sales and maturities of
securities of $147.3 million during 1997 resulted in $3.9 million
of realized gains and $1.4 million of realized losses. Proceeds
from sales and maturities of securities of $115.3 million during
1996 resulted in $2.6 million of realized gains and $2.1 million of
realized losses. The cost of securities for determining realized
gains and losses is original acquisition cost including amortized
premiums and discounts.
At December 31, 1998, the year of maturity of trust fund
investments other than equity securities, was:
(in thousands)
1999 $106,316
2000 - 2003 157,224
2004 - 2008 175,751
After 2008 48,868
Total $488,159
An AEP Resources' subsidiary established a non-recourse variable-rate credit
facility in the aggregate amount of $775 million on
December 31, 1998. Certain assets of the subsidiary support the
facility. The facility is comprised of three tranches: $244
million maturing on December 31, 2000, $488 million maturing on
December 31, 2003, and a $43 million short-term capital facility.
As of December 31, 1998 $732 million were outstanding at an average
interest rate of 5.833%.
The subsidiary entered into several interest rate swap agreements
for $586 million of the borrowings under the credit facility. The
swap agreements involve the exchange of floating-rate for fixed-rate
interest payments. Interest is recognized currently based on
the fixed rate of interest resulting from use of these swap
agreements. Market risks arise from the movements in interest
rates. If counterparties to an interest rate swap agreement were
to default on contractual payments, the subsidiary could be exposed
to increased costs related to replacing the original agreement.
However, the subsidiary does not anticipate non-performance by any
counterparty to any interest rate swap in effect as of December 31,
1998. As of December 31, 1998, the subsidiary was a party to
interest rate swaps having a aggregate notional amount of $586
million, with $342 million maturing on December 31, 2000, and $244
million maturing on December 31, 2003. The average fixed interest
rate payable on the aggregate of the interest rate swaps is 5.32%.
The floating rate for interest rate swaps was 4.9% at December 31,
1998. The estimated fair value of the interest rate swaps, which
represents the estimated amount the subsidiary would pay to
terminate the swaps at December 31, 1998, based on quoted interest
rates, is a net liability of $5 million.
In accordance with the debt covenants included in the financing
provisions of this facility, the subsidiary must hedge at least 80%
of its energy purchase requirements through energy trading
derivative instruments entered into with market participants,
predominantly generators. As of December 31, 1998, the subsidiary
had outstanding energy trading derivatives with a total contracted
load of 12,545 GWh's. These contracts have maturities in the range
of 3 months to twelve years. Management's estimate of the fair
value of these derivatives as of December 31, 1998, is $3.3 million
in excess of book value.
12. Federal Income Taxes:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $294,139 $346,290 $375,528
Deferred 37,877 11,124 (17,008)
Deferred Investment Tax Credits (15,815) (16,134) (16,298)
Total 316,201 341,280 342,222
Charged (Credited) to Nonoperating Income (net):
Current (47,718) (16,038) (5,636)
Deferred 3,572 (17,673) (4,470)
Deferred Investment Tax Credits (9,489) (9,107) (9,510)
Total (53,635) (42,818) (19,616)
Total Federal Income Tax as Reported $262,566 $298,462 $322,606
The following is a reconciliation of the difference between the
amount of federal income taxes computed by multiplying book income
before federal income taxes by the statutory tax rate, and the
amount of federal income taxes reported.
Year Ended December 31,
1998 1997 1996
(in thousands)
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $547,109 $ 638,211 $628,856
Extraordinary Loss - UK Windfall Tax (Note 7) - (109,419) -
Federal Income Taxes 262,566 298,462 322,606
Pre-Tax Book Income $809,675 $ 827,254 $951,462
Federal Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $283,386 $289,539 $333,012
Increase (Decrease) in Federal Income Tax
Resulting from the Following Items:
Depreciation 57,663 53,239 50,537
Corporate Owned Life Insurance (16,428) (18,240) (12,009)
Investment Tax Credits (net) (25,304) (25,241) (25,813)
Extraordinary Loss - UK Windfall Tax - 38,297 -
Other (36,751) (39,132) (23,121)
Total Federal Income Taxes as Reported $262,566 $298,462 $322,606
Effective Federal Income Tax Rate 32.4% 36.1% 33.9%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences:
December 31,
1998 1997
(in thousands)
Deferred Tax Assets $ 879,322 $ 807,226
Deferred Tax Liabilities (3,480,724) (3,368,147)
Net Deferred Tax Liabilities $(2,601,402) $(2,560,921)
Property Related Temporary Differences $(2,170,077) $(2,161,484)
Amounts Due From Customers For Future
Federal Income Taxes (395,605) (410,255)
Deferred State Income Taxes (193,867) (201,843)
All Other (net) 158,147 212,661
Total Net Deferred Tax Liabilities $(2,601,402) $(2,560,921)
The Company has settled with the IRS all issues from the audits of
the consolidated federal income tax returns for the years prior to
1991. Returns for the years 1991 through 1996 are presently being
audited by the IRS. With the exception of interest deductions
related to AEP's corporate owned life insurance program, which are
discussed under the heading, Litigation, in Note 4, management is
not aware of any issues for open tax years that upon final
resolution are expected to have a material adverse effect on
results of operations.
13. Supplementary Information:
Year Ended December 31,
1998 1997 1996
(in thousands)
Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $42,612 $29,631 $22,156
Cash was paid for:
Interest (net of capitalized amounts) $413,341 $390,491 $373,570
Income Taxes $281,709 $398,833 $404,297
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $119,188 $234,846 $136,988
Assumption of Liabilities related
to Acquisitions $151,506 $ - $ -
14. Leases:
Leases of property, plant and equipment are for periods up to 35
years and require payments of related property taxes, maintenance
and operating costs. The majority of the leases have purchase or
renewal options and will be renewed or replaced by other leases.
Lease rentals are primarily charged to operating expenses in
accordance with rate-making treatment. The components of rentals
are as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Operating Leases $254,467 $257,042 $262,451
Amortization of Capital Leases 91,359 104,732 114,050
Interest on Capital Leases 37,516 31,601 28,696
Total Rental Payments $383,342 $393,375 $405,197
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
1998 1997
(in thousands)
LEASED ASSETS IN ELECTRIC UTILITY PLANT:
Production $ 46,532 $ 47,246
Transmission 4 3
Distribution 14,650 14,660
General:
Nuclear Fuel (net of amortization) 103,939 103,939
Mining Plant and Other 530,291 516,843
Total Electric Utility Plant 695,416 682,691
Accumulated Amortization 208,548 196,145
Net Electric Utility Plant 486,868 486,546
LEASED ASSETS IN OTHER PROPERTY 54,102 57,763
Accumulated Amortization 8,387 5,917
Net Other Property 45,715 51,846
Net Property under Capital Leases $532,583 $538,392
Capital Lease Obligations:*
Noncurrent Liability $450,922 $437,303
Liability Due Within One Year 81,661 101,089
Total Capital Lease Obligations $532,583 $538,392
*Represents the present value of future minimum lease payments for plant and
nuclear fuel. The noncurrent portion of capital lease obligations is included
in other noncurrent liabilities in the Consolidated Balance Sheet.
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease rentals, consisted of the following at
December 31, 1998:
Noncancelable
Capital Operating
Leases Leases
(in thousands)
1999 $109,395 $ 239,361
2000 97,132 237,522
2001 79,976 234,147
2002 67,103 228,144
2003 45,161 227,618
Later Years 148,121 3,437,925
Total Future Minimum Lease Rentals 546,888 (a) $4,604,717
Less Estimated Interest Element 118,244
Estimated Present Value of Future
Minimum Lease Rentals 428,644
Unamortized Nuclear Fuel 103,939
Total $532,583
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are
paid in proportion to heat produced and carrying charges on the unamortized
nuclear fuel balance. There are no minimum lease payment requirements for
leased nuclear fuel.
15. Capital Stocks and Paid-In Capital:
Changes in capital stocks and paid-in capital during the period
January 1, 1996 through December 31, 1998 were:
Cumulative Preferred Stocks
Shares of Subsidiaries
Cumulative Not Subject Subject to
Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory
Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b)
(Dollars in Thousands)
January 1, 1996 195,634,992 6,709,751 $1,271,627 $1,658,524 $ 148,240 $ 522,735
Issuances 1,600,000 - 10,400 55,061 - -
Retirements and
Other - (707,518) - 1,969 (57,917) (12,835)
December 31, 1996 197,234,992 6,002,233 1,282,027 1,715,554 90,323 509,900
Issuances 1,754,989 - 11,408 65,337 - -
Retirements and
Other - (4,258,947) - (2,109) (43,599) (382,295)
December 31, 1997 198,989,981 1,743,286 1,293,435 1,778,782 46,724 127,605
Issuances 1,826,488 - 11,872 73,643 - -
Retirements and
Other - (7,220) - 487 (722) -
December 31, 1998 200,816,469 1,736,066 $1,305,307 $1,852,912 $ 46,002 $ 127,605
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
16. Lines of Credit and Commitment Fees:
At December 31, 1998 and 1997, unused short-term bank lines of
credit were available in the amounts of $763 million and $442
million, respectively. In addition several of the subsidiaries
engaged in providing non-regulated energy services share a line of
credit under a revolving credit agreement. The amounts of credit
available under the revolving credit agreement were $60 million and
$330 million at December 31, 1998 and 1997, respectively. The
short-term bank lines of credit and the revolving credit agreement
require the payment of facility fees of approximately 1/10 of 1% on
the daily amount of such commitments.
Outstanding short-term debt consisted of:
December 31,
1998 1997
(dollars in thousands)
Balance Outstanding:
Notes Payable $197,304 $199,285
Commercial Paper 419,300 355,790
Total $616,604 $555,075
Year-End Weighted
Average Interest Rate:
Notes Payable 5.8% 6.3%
Commercial Paper 6.2% 6.8%
Total 6.1% 6.6%
17. Unaudited Quarterly Financial Information:
Quarterly Periods Ended
1998
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,509,410 $1,560,944 $1,845,228 $1,430,320
Operating Income 255,932 227,190 311,579 162,033
Net Income 150,586 118,084 195,365 72,148
Earnings per Share 0.79 0.62 1.02 0.38
Fourth quarter 1998 earnings declined primarily as a result of
unseasonably mild weather, severance accruals and the negative
impact of the extended Cook Plant outage.
Quarterly Periods Ended
1997
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,492,069 $1,382,158 $1,507,075 $1,498,518
Operating Income 271,978 221,255 275,090 216,131
Income Before
Extraordinary Item 172,562 121,139 201,746 124,933
Net Income 172,562 121,139 91,181 126,079
Earnings per Share
Before Extraordinary
Item* 0.92 0.64 1.07 0.66
Earnings per Share 0.92 0.64 0.48 0.66
*Amounts for 1997 do not add to $3.28 earnings per share due to
rounding.
The third quarter of 1997 includes an extraordinary loss of $110.6
million or $0.59 per share for a UK Windfall Tax which
retroactively adjusted upward Yorkshire's privatization price
discussed in Note 7.
See "Reclassification" in Note 1 regarding reclassification of
prior period amounts.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1998
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 460,016 $ 46,002
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795
7% (f) (f) 250,000 250,000 25,000
Total Subject to Mandatory
Redemption (c) $127,605
______________________________________________________________________________________________________
December 31, 1997
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 467,236 $ 46,724
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 38,810
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 63,795
7% (f) (f) 250,000 250,000 25,000
Total Subject to Mandatory
Redemption (c) $127,605
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call price
plus accrued dividends.
The involuntary liquidation preference is $100 per share for all outstanding shares.
(b) As of December 31, 1998 the subsidiaries had 7,193,024, 22,200,000 and 7,583,313 shares of $100, $25
and no par value preferred stock, respectively, that were authorized but unissued.
(c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds
(genera lly at par) and reacquisitions of shares in anticipation of future requirements.
The subsidiaries reacquired enough shares in 1997 to meet all sinking fund
requirements on certain series until 2008 and on certain series until 2009
when all remaining outstanding shares must be redeemed.The sinking fund provisions of the series
subject to mandatory redemption aggregate $5,000,000 eachyear for the years
2000, 2001, 2002 and $15,000,000 in 2003.
(d) Not callable prior to 2003; after that the call price is $100 per share.
(e) Not callable prior to 2000; after that the call price is $100 per share.
(f) With sinking fund. Redemption is restricted prior to 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1998 1998 1997 1998 1997
(in thousands)
FIRST MORTGAGE BONDS
1998-2002 7.23% 6.35%-8.95% 6.35%-9.15% $ 759,000 $1,131,411
2003-2006 6.70% 6%-8% 6%-8% 846,000 846,000
2022-2025 7.90% 7.10%-8.80% 7.10%-8.80% 1,020,768 1,120,419
INSTALLMENT PURCHASE CONTRACTS (a)
1998-2002 4.40% 4.05%-5.15% 3.70%-7-1/4% 145,000 189,500
2007-2025 6.42% 5.00%-7-7/8% 5.45%-7-7/8% 776,245 756,745
NOTES PAYABLE (b)
1998-2008 5.97% 5.49%-9.60% 5.29%-9.60% 1,493,360 527,681
SENIOR UNSECURED NOTES
2003-2008 6.54% 6.24%-6.91% 6.73%-6.91% 786,000 144,000
2038 7.30% 7.20%-7-3/8% - 340,000 -
JUNIOR DEBENTURES
2025 - 2038 8.05% 7.60%-8.72% 7.92%-8.72% 620,000 495,000
OTHER LONG-TERM DEBT (c) 269,319 250,357
Unamortized Discount (net) (49,575) (37,196)
Total Long-term Debt
Outstanding (d) 7,006,117 5,423,917
Less Portion Due Within One Year 206,476 294,454
Long-term Portion $6,799,641 $5,129,463
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment.
Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from
banks and standby bond purchase agreements support certain series.
(b) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving
credit agreements with a number of banks and other financial institutions. At expiration all notes then
issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates
generally relate to specified short-term interest rates.
(c) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear
fuel (see Note 4 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease
back agreements.
(d) Long-term debt outstanding at December 31, 1998 is payable as follows:
Principal Amount (in thousands)
1999 $ 206,476
2000 786,222
2001 512,028
2002 294,546
2003 934,547
Later Years 4,321,873
Total Principal
Amount 7,055,692
Unamortized
Discount 49,575
Total $7,006,117
Management's Responsibility
The management of American Electric Power Company, Inc. is
responsible for the integrity and objectivity of the information and
representations in this annual report, including the consolidated
financial statements. These statements have been prepared in conformity
with generally accepted accounting principles, using informed estimates
where appropriate, to reflect the Company's financial condition and
results of operations. The information in other sections of the annual
report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for
determining that management has fulfilled its obligation in the
preparation of the financial statements and in the ongoing examination
of the Company's established internal control structure over financial
reporting. The Audit Committee, which consists solely of outside
directors and which reports directly to the Board of Directors, meets
regularly with management, Deloitte & Touche LLP - Certified Public
Accountants and the Company's internal audit staff to discuss
accounting, auditing and reporting matters. To ensure auditor
independence, both Deloitte & Touche LLP and the internal audit staff
have unrestricted access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche
LLP, whose report appears on the next page. The auditors provide an
objective, independent review as to management's discharge of its
responsibilities insofar as they relate to the fairness of the Company's
reported financial condition and results of operations. Their audit
includes procedures believed by them to provide reasonable assurance
that the financial statements are free of material misstatement and
includes a review of the Company's internal control structure over
financial reporting.
Independent Auditors' Report
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of
American Electric Power Company, Inc. and its subsidiaries as of
December 31, 1998 and 1997, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for
our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of American
Electric Power Company, Inc. and its subsidiaries as of December 31,
1998 and 1997, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1998 in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 23, 1999