OHIO POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
1999 1998 1997 1996 1995
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $2,039,263 $2,105,547 $1,892,110 $1,911,708 $1,822,997
Operating Expenses 1,750,434 1,816,175 1,615,717 1,614,547 1,550,837
Operating Income 288,829 289,372 276,393 297,161 272,160
Nonoperating Income 7,000 588 14,822 6,374 11,240
Income Before Interest
Charges 295,829 289,960 291,215 303,535 283,400
Interest Charges 83,672 80,035 82,526 85,880 93,953
Net Income 212,157 209,925 208,689 217,655 189,447
Preferred Stock
Dividend Requirements 1,417 1,474 2,647 8,778 14,668
Earnings Applicable to
Common Stock $ 210,740 $ 208,451 $ 206,042 $ 208,877 $ 174,779
December 31,
1999 1998 1997 1996 1995
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $5,400,917 $5,257,841 $5,155,797 $4,996,621 $4,915,222
Accumulated Depreciation
and Amortization 2,621,711 2,461,376 2,349,995 2,216,534 2,091,148
Net Electric Utility Plant $2,779,206 $2,796,465 $2,805,802 $2,780,087 $2,824,074
Total Assets $4,677,209 $4,344,680 $4,163,202 $4,092,166 $4,156,564
Common Stock and
Paid-in Capital $ 783,577 $ 783,536 $ 783,497 $ 781,863 $ 780,675
Retained Earnings 587,424 587,500 590,151 584,015 518,029
Total Common Shareholder's
Equity $1,371,001 $1,371,036 $1,373,648 $1,365,878 $1,298,704
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 16,937 $ 17,370 $ 17,542 $ 38,532 $ 41,240
Subject to Mandatory
Redemption (a) 8,850 11,850 11,850 109,900 115,000
Total Cumulative
Preferred Stock $ 25,787 $ 29,220 $ 29,392 $ 148,432 $ 156,240
Long-term Debt (a) $1,151,511 $1,084,928 $1,095,226 $1,069,729 $1,227,632
Obligations Under Capital
Leases (a) $ 136,543 $ 142,635 $ 157,487 $ 131,285 $ 131,926
Total Capitalization and
Liabilities $4,677,209 $4,344,680 $4,163,202 $4,092,166 $4,156,564
(a) Including portion due within one year.
OHIO POWER COMPANY AND SUBSIDIARIES
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 ability to recover generation-related
regulatory assets and other transition costs including stranded
costs as the generation portion of the retail business moves from
cost-based rates to market prices beginning January 1, 2001; new
legislation and government regulations; the ability of the Company
to successfully control its costs; the economic climate and growth
in our service territory; the outcome of litigation with the
Internal Revenue Service (IRS) related to certain interest
deductions for a corporate owned life insurance program; the
ability of the Company to successfully challenge new environmental
regulations and to successfully litigate claims that the Company
violated the Clean Air Act; inflationary trends; changes in
electricity market prices; interest rates; and other risks and
unforeseen events.
Ohio Power Company (the Company) is a wholly-owned subsidiary
of American Electric Power Company, Inc. (AEP Co., Inc.), a public
utility holding company. The Company is engaged in the generation,
purchase, sale, transmission and distribution of electric power and
provides electric power to 691,000 retail customers in
northwestern, east central, eastern and southern sections of Ohio
and does business as American Electric Power (AEP). The Company
supplies electric power to the AEP System Power Pool (AEP Power
Pool) and shares the revenues and costs of the AEP Power Pool's
wholesale sales to neighboring utility systems and power marketers.
The Company also sells wholesale power to municipalities and
cooperatives.
The cost of the AEP System's generating capacity is
allocated among the AEP Power Pool members based on their relative
peak demands and generating reserves through the payment or receipt
of capacity charges and credits. AEP Power Pool members are also
compensated for their out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP
Power Pool.
The AEP Power Pool calculates each Company's prior twelve month
peak demand relative to the total peak demand of all member
companies as a basis for sharing revenues and costs. The result of
this calculation is the member load ratio (MLR) which determines
each Company's percentage share of revenues or costs. Since the
Company's MLR decreased during 1999 and increased during 1998, the
AEP Power Pool is allocating a smaller share and a larger share,
respectively, of wholesale revenues and expenses to the Company.
Results of Operations
Net income increased $2 million or 1% in 1999 and $1 million or
less than 1% in 1998. The increase in net income in 1999 was
primarily due to a decline in operation and maintenance costs
reflecting cost containment efforts. The increase in 1998 was
mainly due to increased retail, wholesale, and transmission
revenues.
Operating Revenues and Energy Sales
Operating revenues declined 3% in 1999 primarily due to a
decline in margins on wholesale sales and net power trading
transactions and decreased sales to the AEP Power Pool. The 11%
increase in operating revenues in 1998 was primarily due to
increased retail, wholesale and transmission service revenues. The
changes in the components of revenues were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1999 1998
Amount % Amount %
Retail:
Residential $ 7.5 $ 4.1
Commercial 0.4 12.9
Industrial (5.0) 52.2
Other - 0.1
2.9 0.2 69.3 5.3
Wholesale (71.9) (11.2) 120.6 23.0
Transmission (5.0) (7.8) 19.3 43.0
Miscellaneous 7.7 48.0 4.2 35.6
Total $(66.3) (3.1) $213.4 11.3
Although retail revenues were unchanged in 1999, wholesale
revenues declined due to decreased sales to the AEP Power Pool and
reduced margins on the Company's MLR share of power marketing sales
and net energy trading transactions. The decrease in sales to the
AEP Power Pool reflects a reduction in demand by the AEP System's
wholesale customers. The margins on power marketing sales and
energy trading transactions declined as a result of the moderation
in 1999 of extreme weather in 1998 and unaffiliated capacity
shortages experienced in the summer of 1998 in AEP Power Pool's
marketing area.
Revenues from retail customers increased in 1998 reflecting a
5% increase in commercial sales and a 3% rise in industrial sales.
The rise in commercial sales resulted from growth in the number of
commercial customers. The increase in industrial sales was
primarily due to a return to work following a labor dispute which
idled a major industrial customer's manufacturing facilities from
October 1996 through most of the third quarter of 1997.
The increase in revenues from wholesale customers of 23% in
1998 was primarily due to increased sales to the AEP Power Pool and
the Company's share of increased AEP Power Pool power marketing
sales and net trading transactions. The increase in power
marketing and trading reflects the growth in the AEP Power Pool's
power trading business. The increase in the Company's sales to the
AEP Power Pool were required to replace the energy of an
affiliate's nuclear plant which has been on an extended outage
since September 1997.
The increase in transmission revenues in 1998 was primarily due
to a substantial rise in the volume of energy transmitted for
unaffiliated entities. The Federal Energy Regulatory Commission's
(FERC) issuance of open access transmission rules facilitated the
growth in the demand for transmission services. The Company
received its MLR share of the increase in transmission revenues.
Operating Expenses
Operating expenses decreased 4% in 1999 after increasing 12% in
1998. The operating expense decline in 1999 reflects cost
containment efforts and lower fuel costs due mainly to a decrease
in generation reflecting lower demand for wholesale energy. The
increase in 1998 was attributable to increased fuel, purchased
power and other operation expenses mainly due to the increased
demand for power and costs associated with growth of the power
marketing and trading operation. Changes in the components of
operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1999 1998
Amount % Amount %
Fuel $(50.8) (6.9) $ 96.4 15.0
Purchased Power 12.4 8.2 78.6 108.9
Other Operation (26.1) (7.4) 31.1 9.7
Maintenance (18.3)(13.1) (4.2) (2.9)
Depreciation and Amortization 4.6 3.2 3.7 2.6
Taxes Other Than Federal
Income Taxes (3.5) (2.0) 0.9 0.5
Federal Income Taxes 16.0 13.3 (6.0) (4.7)
Total Operating Expenses $(65.7) (3.6) $200.5 12.4
Fuel expense decreased in 1999 due to a 6% decrease in
generation reflecting the decline in wholesale sales. The increase
in fuel expense in 1998 was due to an increase in generation to
meet the increased demand for energy to replace the energy of an
affiliate's unavailable nuclear units and an increase in the
average cost of fuel consumed.
Purchased power expense increased significantly in 1998
primarily due to the Company's share of increased purchases of
power by the AEP Power Pool to meet the demand for wholesale power
marketing sales.
The decrease in other operation expense in 1999 was due to
lower coal-fired power plant expenses reflecting cost containment
efforts, and an increase in gains on emission allowance sales. The
cost containment efforts included staff reductions in transmission
and distribution operations, at the power plants and within the
engineering and maintenance group of AEP Service Corporation which
bills the Company for operations support services.
Other operation expense increased in 1998 primarily due to
increased costs under the AEP System Transmission Equalization
Agreement, reflecting an increase in the Company's MLR, severance
accruals for reductions in power generation and energy delivery
staff, increased expenses for emission allowances used as a result
of the increased generation to meet demand for power and increased
costs related to management's decision to grow the new power
marketing and trading business. The AEP System Transmission
Equalization Agreement combines certain AEP System companies'
investments in transmission facilities and shares the costs of
ownership in proportion to the System companies' respective peak
demands.
The decline in maintenance expense in 1999 reflects cost
containment efforts discussed above.
Federal income taxes attributable to operations increased in
1999 due to changes in certain book/tax differences accounted for
on a flow-through basis for rate-making purposes and an increase in
pre-tax operating income.
Nonoperating Income
Nonoperating income declined in 1998 primarily due to net
losses from non-regulated power trading transactions outside of the
AEP Power Pool's traditional marketing area which are marked-to-market.
Business Outlook
The most significant factors affecting the Company's future
earnings are its ability to recover regulatory assets, transition
and other stranded costs under The Ohio Electric Restructuring Act
of 1999; weather in the service territories served by the Company
and its wholesale customers; generating unit availability; the
outcome of litigation with the IRS related to certain interest
deductions for a corporate owned life insurance program; and the
outcome of ongoing environmental litigation and proposed air
quality standards. In 1999 significant progress was made related
to many of these major challenges.
Ohio Restructuring and The Transition To Market Pricing For
Generation
The Ohio Electric Restructuring Act of 1999 (the Act) became
law in October 1999. The Act provides for customer choice of
electricity supplier, a residential rate reduction of 5% for the
generation portion of rates and a freezing of the unbundled
generation rates including fuel rates beginning on January 1, 2001.
The Act also provides for a five-year transition period to move
from cost-based rates to market pricing for generation services.
It authorizes the Public Utilities Commission of Ohio (PUCO) to
address certain major transition issues including unbundling of
rates and the recovery of transition costs including stranded
costs. Transition costs include generation-related regulatory
assets, (which include, among other expense deferrals, unrecovered
deferred fuel costs, deferred tax benefits that were flowed through
to reduce past rates and deferred affiliated mine shutdown costs),
impaired tangible generating asset values, and future contract
costs. Stranded costs are those costs of generation above market
that would not be recoverable in a competitive market. Transition
costs also include customer choice education costs, development
costs of new customer choice billing and metering systems, costs of
filing a transition plan, employee severance and retraining costs
and other costs.
Retail electric services that will be competitive are defined
in the Act as electric generation service, aggregation service, and
power marketing and brokering. Under the Act the PUCO is granted
broad oversight responsibility and is required to approve by
October 31, 2000 a transition plan for each electric utility
company. Electric utility companies in Ohio were required to file
their transition plans by January 3, 2000. The Company filed its
plan in December 1999.
The Act provides Ohio electric utilities with an opportunity to
recover PUCO approved allowable transition costs through the
generation portion of transition rates paid through December 31,
2005 by customers who do not switch generation suppliers and
through a transition charge for customers who switch generation
suppliers. Under the Act recovery of the regulatory asset portion
of transition costs can, under certain circumstances with PUCO
approval, extend beyond the five-year transition period but cannot
continue beyond December 31, 2010.
The Act also provides for a reduction in property tax
assessments; exemption of electric utilities from the gross
receipts tax; and the imposition of a franchise tax, income taxes,
and a new kilowatthour (kwh) excise tax. The property tax
assessment percentage on electric generation property will be
lowered from 100% to 25% of value effective January 1, 2001 and
electric utilities will become subject to the Ohio Corporate
Franchise Tax and municipal income taxes on January 1, 2002. The
last year for which electric utilities will pay a tax based on
gross receipts is the tax year ending April 30, 2002. As of May 1,
2001 electric distribution companies will be subject to an excise
tax based on kwh sold to Ohio customers. The gross receipts tax,
which will terminate for electric utilities, is paid by the Company
at the beginning of the tax year, deferred as a prepaid expense and
amortized to expense during the tax year pursuant to the tax law
whereby the payment of the tax results in the privilege to conduct
business in the year following the payment of the tax. The change
in the tax law to impose an excise tax based on kwh sold to Ohio
customers commencing before the expiration of the gross receipts
tax privilege period will result in a 12 month period (May 1, 2001
to April 30, 2002) when the Company is recording as an expense both
the gross receipts tax and the kwh excise tax. In the Company's
Ohio transition plan filing, recovery of $50 million was sought for
this overlap of the gross receipts and excise taxes.
The PUCO is required to issue a transition order no later than
October 31, 2000 regarding the Company's transition filings which
included the following elements:
a rate unbundling plan including tariff terms and conditions
necessary for restructuring,
a corporate separation plan,
an application for transition revenues,
a plan for independent operation of transmission facilities and
other components for the implementation of restructuring.
The rate unbundling portion of the Company's transition plan
filing provides for two transition period tariffs beginning January
1, 2001, the standard tariff and the open access distribution
tariff. The Company's proposed standard tariff applies to
customers who do not choose an alternative energy supplier. This
tariff schedule includes detailed charges for generation,
transmission and distribution and riders to fund universal service,
to promote energy efficiency and to recover regulatory assets and
taxes. Taxes include charges for municipal income, excise and
franchise taxes and tax credits for gross receipts and property
taxes. For customers who choose an alternative electric supplier,
the proposed open access distribution tariff will apply. This
tariff includes charges for distribution and riders to fund
universal service, to promote energy efficiency and to recover
regulatory assets and taxes. These riders are the same as those in
the standard tariff except there is no property tax credit.
The Company's corporate separation plan proposal requires the
establishment of separate subsidiaries to own and operate its
transmission and distribution assets. The Company will retain its
generation assets. The separation plan will be implemented in a
manner that recognizes the current overlap of financing
arrangements. This would permit an orderly and economically
efficient separation so that additional transition costs from
prematurely retiring of financial instruments can be minimized.
Prior to the actual legal separation, the Company will functionally
separate generation from transmission and distribution.
The transition plan filing requests recovery of stranded
generation costs over a five year period and recovery of
generation-related regulatory assets and other transition costs of
$611 million over a 10-year period through transition revenues.
The amount requested for recovery of regulatory assets includes
current and new regulatory assets including those arising from
compliance with the electric restructuring law. Also included in
the requested recovery amount were deferred fuel and affiliated
mine closure costs.
In the Ohio jurisdiction the Company is subject to certain
limitations on the current recovery of affiliated coal costs under
PUCO approved agreements, which are discussed in Note 2 of the
Notes to Consolidated Financial Statements. Under the terms of the
agreements full recovery of the Ohio jurisdictional portion of
deferred unrecovered costs of affiliated mining operations
including future mine closure costs was expected to occur before
the expiration of the PUCO approved agreements in 2009. Management
closed the Muskingum mine in 1999 and plans to close the Windsor
mine in 2000 and the Meigs mine in 2001. Provisions for Muskingum
and Windsor mine shutdown costs totaling $45 million and $48
million were recorded in 1998 and 1999, respectively. These
provisions were deferred in the Ohio jurisdiction under the PUCO
approved agreements because management believed that these mine
shutdown cost deferrals are probable of future recovery through the
agreements. However, since the Act will supersede the agreements
effective January 1, 2001, the Company has filed under the
provisions of the Act for recovery of all of its stranded
regulatory assets including the affiliated coal and mine closure
costs deferred under the agreements of $196 million at December 31,
1999 plus the projected amount that will be deferred by the
beginning of the transition period, January 1, 2001, which includes
the accrual for the closure costs of the Meigs mine.
Included in the transition plan is a proposal to implement
independent operation of the transmission system. The Company
proposes to join a regional transmission organization whose
approval is currently pending before the FERC.
See Note 4 of the Notes to Consolidated Financial Statements
for further discussion of the Ohio restructuring plan.
Regulatory/Restructuring Accounting
Under the provisions of Statement of Financial Accounting
Standards (SFAS) 71 "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (deferred revenues) are included in the consolidated
balance sheets of cost-based regulated utilities in accordance with
regulatory actions in order to match expenses and revenues. 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 probable recovery of the regulatory assets over
future accounting periods. Management has concluded that as of
December 31, 1999 the requirements to apply SFAS 71 continue to be
met. However, the Ohio Electric Restructuring Act will result in
the discontinuance of SFAS 71 regulatory accounting for the
generation portion of the Ohio jurisdiction.
In the event a portion of the Company'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 did not anticipate or
provide accounting guidance for an extended transition period and
for recovery of stranded costs during and after a transition period
through a wires charge or regulated distribution rates. In 1997
the Financial Accounting Standards Board's (FASB) Emerging Issues
Task Force (EITF) addressed such a situation with the consensus
reached on issue 97-4 that requires that 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 competitive
market pricing from cost-based regulated rates and/or a rate order
is issued containing sufficient detail for the utility to
reasonably determine what the restructuring plan would entail and
how it will affect the utility's financial statements. The EITF
indicated that the cessation of application of SFAS 71 regulatory
accounting would require that regulatory assets and impaired
stranded plant cost applicable to the portion of the business that
was no longer cost-based regulated, be written off unless they are
recoverable in the future through transition rates and/or
post-transition cost based regulated rates.
Potential For A Write Off In Ohio
The Company's accounting for generation will continue to be in
accordance with SFAS 71 in the Ohio jurisdiction and will continue
to be considered to be cost-based regulated for accounting purposes
until the amount of transition rates and stranded cost wires
charges are determined and known. The establishment of transition
rates and wire charges should enable management to determine the
Company's ability to recover stranded costs including regulatory
assets and transition costs, a requirement under EITF 97-4 to
discontinue application of SFAS 71. When the amount of unbundled
frozen generation transition rates and distribution stranded cost
wires charges are known for the Ohio jurisdiction, the application
of SFAS 71 will be discontinued for the Ohio retail jurisdictional
portion of the Company's generation business. Management expects
this to occur when the PUCO issues its order to approve a
transition plan for the Company's Ohio jurisdiction. The Act
requires that the PUCO issue its order no later than October 31,
2000.
Upon the discontinuance of SFAS 71 the Company will have to
write off its Ohio jurisdictional generation-related regulatory
assets to the extent that they cannot be recovered under the frozen
transition rates and stranded costs distribution wires charges and
record any asset accounting impairments. An impairment loss would
be recorded (on a discounted basis) to the extent that the cost of
generation assets cannot be recovered through non-discounted
generation-related revenues during the transition period and future
market prices. Absent the determination in the regulatory process
of transition rates, any wires charge and other pertinent
information, it is not possible at this time for management to
determine if any of the Company's generating assets are impaired
for accounting purposes on an undiscounted cash flow basis.
The amount of regulatory assets recorded on the books at
December 31, 1999 applicable to the Ohio retail jurisdictional
generation business before related tax effects is estimated to be
$361 million. Due to the planned closing of the Company's
affiliated mines, including the Meigs mine, projected
generation-related regulatory assets as of December 31, 2000 (the
date thatrecoverable generation related regulatory assets are measured under
the Act) allocable to the Ohio retail jurisdiction are estimated to
exceed $520 million, before income tax effects. Recovery of these
Ohio generation related regulatory assets was sought as a part of
the Company's Ohio transition plan filing. Based on current
projections of future market prices, the Company does not
anticipate that it will experience material tangible asset
accounting impairment write-offs. Whether the Company will
experience material regulatory asset write-offs will depend on
whether the PUCO approves the Company's request for their recovery.
Determination of whether the Company will experience any asset
impairment loss regarding its Ohio retail jurisdictional generating
assets and any loss from the possible inability to recover Ohio
generation related regulatory assets and other transition costs
cannot be made until such time as the transition rates and the
wires charges are determined through the regulatory process.
Should the PUCO fail to approve transition rates and wires charges
that are sufficient to provide for recovery of the Company's
generation-related regulatory assets, any other stranded costs and
transition costs, it could have a material adverse effect on
results of operations, cash flows and possibly financial condition.
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 the Company has spent hundreds of millions of
dollars to equip our 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 while providing a vital commodity, electricity, to our
customers at a fair price.
Air Quality
In 1998 the United States (U.S.) Environmental Protection
Agency (Federal EPA) issued a final rule which requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern states,
including the states in which the Company's generating plants are
located. A number of utilities, including the Company, filed
petitions seeking a review of the final rule in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court). On
March 3, 2000, the Appeals Court issued a decision generally
upholding Federal EPA's final rule on NOx emission reductions.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to the
Clean Air Act (Section 126 Rule). The Rule approved portions of
the states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx emission reduction final rule.
The AEP System companies with coal-fired generating plants, as well
as other utility companies, filed a petition in the Appeals Court
seeking review of the Section 126 Rule. In 1999, three additional
northeastern states and the District of Columbia filed petitions
with Federal EPA similar to those originally filed by the eight
northeastern states. Since the petitions relied in part on
compliance with an 8-hour ozone standard remanded by the Appeals
Court, Federal EPA indicated its intent to decouple compliance with
the 8-hour standard and issue a revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126
Rule requiring 392 industrial plants, including certain generating
plants owned by the Company, to reduce their NOx emissions by May
1, 2003. This rule approves petitions of four northeastern states
which contend that their failure to meet Federal EPA smog standards
is due to coal-fired generating plants in upwind states, including
many of the Company's plants, and not their automobiles and other
local sources.
Preliminary estimates indicate that compliance with the Federal
EPA's final rule on NOx emission reductions that was upheld by the
Appeals Court could result in required capital expenditures of
approximately $624 million for the Company. It should be noted,
however, that compliance costs cannot be estimated with certainty
since 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 compliance costs are recovered from customers
through regulated rates, unbundled generation transition rates,
wires charges and the future market price of electricity, such
compliance costs will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
Federal EPA Complaint and Notice of Violation
Under the Clean Air Act, if a plant undergoes a major
modification that results in a significant emissions increase,
permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
On November 3, 1999, the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company and certain
other affiliated utilities made modifications to certain of their
coal-fired generating plants over the course of the past 25 years
that extend their operating lives or increase their generating
capacity in violation of the Clean Air Act. Federal EPA also
issued Notices of Violation to the Company and certain other
affiliated utilities alleging violations of certain provisions of
the Clean Air Act at certain plants including the Company's plants.
A number of unaffiliated utilities also received Notices of
Violation complaints or administration orders.
The states of New Jersey, New York and Connecticut were
subsequently allowed to join Federal EPA's action against the
Company under the Clean Air Act. On November 18, 1999, a number of
environmental groups filed a lawsuit against power plants owned by
the Company alleging similar violations to those in the Federal EPA
complaint and Notices of Violation. This action was consolidated
with the Federal EPA action. The complaints and Notices of
Violation named all of the Company's seven coal-fired generating
plants. Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act provisions and
intends to vigorously pursue its defense of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial. In the event the Company does not prevail,
any capital and operating costs of additional pollution control
equipment that may be required as well as any penalties imposed
would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through regulated rates, approved unbundled transition generation
rates, wires charges and future market prices for electricity.
Financial Condition
The Company issued $225 million principal amount of long-term
obligations in 1999 at interest rates ranging from 5.15% to 7%.
The principal amount of long-term debt retirements, including
maturities, totaled $140 million with interest rates ranging from
6.55% to 7.85%. The Company's senior secured debt/first mortgage
bond ratings are: Moody's, A3; Standard & Poor's, A-; Fitch, A-;
and Duff & Phelps, A.
Gross plant and property additions were $223 million in 1999
and $215 million in 1998. Management estimates construction
expenditures for the next three years to be $783 million. The
funds for construction of new facilities and improvement of
existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred
stock issuances and investments in common equity by the Company's
parent. However, all of the construction expenditures for the next
three years are expected to be financed with internally generated
funds.
When necessary the Company generally issues short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds. At December 31, 1999, $1,056 million
of unused short-term lines of credit shared with other AEP System
companies were available. Short-term debt borrowings are limited
by provisions of the Public Utility Holding Company Act of 1935 to
$450 million. Generally periodic reductions of outstanding
short-term debt are made through issuances of long-term debt and
through additional capital contributions by the parent company.
The Company's earnings coverage presently exceeds all minimum
coverage requirements for the issuance of mortgage bonds and
preferred stock. The minimum coverage ratios are 2.0 for mortgage
bonds and 1.5 for preferred stock. At December 31, 1999, the
mortgage bonds and preferred stock coverage ratios were 11.78 and
3.17, respectively.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates. The allocation of trading of electricity and
related financial derivative instruments through the AEP Power Pool
exposes the Company to market risk. Market risk represents the
risk of loss that may impact the Company due to adverse changes in
electricity commodity market prices and rates. Policies and
procedures have been established to identify, assess and manage
market risk exposures including the use of a risk measurement model
which calculates Value at Risk (VaR). The VaR is based on the
variance-covariance method using historical prices to estimate
volatilities and correlations and assuming a 95% confidence level
and a three-day holding period. Throughout 1999 and 1998, the
Company's share of the highest, lowest and average VaR in the
wholesale trading portfolio was less than $3.9 million and $3
million, respectively. Based on this VaR analysis, at December 31,
1999 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.
The Company is exposed to changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations. The debt portfolio has variable and fixed interest
rates with terms from one day to 39 years and an average duration
of six years at December 31, 1999. The Company measures interest
rate market risk exposure utilizing a VaR model. The interest rate
VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one year holding period. The volatilities
and correlations were based on three years of weekly 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 $157 million at December 31, 1999
and $144 million at December 31, 1998. 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.
Inflation affects the Company'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.
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 a corporate owned life insurance (COLI)
program should not be allowed. As a result of a suit filed in U.S.
District Court (discussed below) this request for ruling was
withdrawn by the IRS agents. Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions for
taxable years 1991-96. A disallowance of the COLI interest
deductions through December 31, 1999 would reduce earnings by
approximately $118 million inclusive of interest.
The Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1991-98 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are
included on the consolidated balance sheets in other property and
investments pending the resolution of this matter. The Company is
seeking refund through litigation of all amounts paid plus
interest.
In order to resolve this issue, the Company filed suit against
the U.S. in the U.S. District Court for the Southern District of
Ohio in March 1998. In 1999 a U.S. Tax Court judge decided in the
Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's
COLI deduction should be disallowed. Notwithstanding the decision
in Winn-Dixie management has made no provision for any possible
adverse earnings impact from this matter because it believes, and
has been advised by outside counsel, that it has a meritorious
position and will vigorously pursue its 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 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 or financial condition.
Other Matters
Superfund
By-products from the generation of electricity include
materials such as ash, slag, and sludge. 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. The Company is 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 authorizes Federal EPA to
administer the clean-up programs. As of year-end 1999, the Company
is involved in litigation with respect to two sites overseen by the
Federal EPA. There is one additional site for which the Company has
received an information request which could lead to a potentially
responsible party (PRP) designation. The Company has also been
named a PRP at one site under state law. The Company's liability
has been resolved for a number of sites with no significant effect
on results of operations and present estimates do not anticipate
material cleanup costs for identified sites. However, if for
reasons not currently identified significant costs are incurred for
cleanup, future results of operations, cash flows and possibly
financial condition would be adversely affected unless the costs
can be recovered from customers.
The Clean Air Act Amendments (CAAA) required Federal EPA to
issue rules to implement the law. In 1996 Federal EPA issued final
rules governing NOx emissions that must be met after January 1,
2000 (Phase II of the CAAA). The final rules required substantial
reductions in NOx emissions from certain types of boilers including
those in the power plants of the Company and its affiliates in the
AEP System. To comply with Phase II of CAAA, the Company installed
NOx emission control equipment on certain units and switched fuel
at other units. The Company is operating under the Phase II rules
which require reporting at the end of each year. The Company does
not anticipate any material problems complying with the rules.
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 U.S.,
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 U.S. Senate
for ratification, would require the U.S. to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012.
Although the U.S. has agreed to the treaty and signed it on
November 12, 1998, President Clinton 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, methodologies and guidelines
of the treaty's emissions trading and joint implementation programs
and compliance enforcement provisions have been negotiated. At the
Fourth Conference of the Parties, held in Buenos Aires, Argentina,
in November 1998, the parties agreed to a work plan to complete
negotiations on outstanding issues with a view toward approving
them at the Sixth Conference of the Parties to be held in November
2000. We will continue to work with the Administration and
Congress to develop responsible 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. It is management's
belief, that the Kyoto protocol is unlikely to be ratified or
implemented in the U.S. in its current form.
Year 2000 Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems could have produced erroneous results or failed, unless
these systems had been modified or replaced, because such systems
may have been programmed incorrectly and interpreted 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 or otherwise incorrectly
interpret a year 2000 date.
The Company has not experienced any material failures of
generation and delivery of electric energy due to Year 2000 because
of the AEP System's preparations. Such preparations included the
modification or replacement of certain computer hardware and
software to minimize Year 2000-related failures and repair. 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 was 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 sought written assurances from
third parties regarding their state of Year 2000 readiness.
Another issue addressed was the impact of electric power grid
problems that may have occurred outside of our transmission system.
Through December 31, 1999, the Company's share of the AEP
System's expenditures on the Year 2000 project was $14 million.
Most Year 2000 costs were for IT contractors and consultants and
for salaries of internal IT professionals and were expensed;
however, in certain cases the Company acquired hardware and new
software that was capitalized.
New Accounting Standards
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 and reviewing the
Company's contracts and transactions to determine the impact on the
Company's results of operations, cash flows and financial condition
when SFAS 133 is adopted on January 1, 2001.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
1999 1998 1997
(in thousands)
OPERATING REVENUES $2,039,263 $2,105,547 $1,892,110
OPERATING EXPENSES:
Fuel 687,672 738,522 642,135
Purchased Power 163,143 150,733 72,153
Other Operation 327,132 353,194 322,088
Maintenance 121,299 139,611 143,831
Depreciation and Amortization 149,055 144,493 140,807
Taxes Other Than Federal Income Taxes 165,891 169,353 168,480
Federal Income Taxes 136,242 120,269 126,223
Total Operating Expenses 1,750,434 1,816,175 1,615,717
OPERATING INCOME 288,829 289,372 276,393
NONOPERATING INCOME 7,000 588 14,822
INCOME BEFORE INTEREST CHARGES 295,829 289,960 291,215
INTEREST CHARGES 83,672 80,035 82,526
NET INCOME 212,157 209,925 208,689
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,417 1,474 2,647
EARNINGS APPLICABLE TO COMMON STOCK $ 210,740 $ 208,451 $ 206,042
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
1999 1998 1997
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 212,157 $ 209,925 $ 208,689
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 193,780 172,085 172,186
Deferred Federal Income Taxes 3,666 3,042 7,627
Deferred Investment Tax Credits (3,458) (3,525) (3,487)
Deferred Fuel Costs (net) (76,978) (44,694) (34,548)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (49,309) (12,376) (62,371)
Fuel, Materials and Supplies (60,500) 18,612 (11,127)
Accrued Utility Revenues (2,074) (5,915) 1,266
Accounts Payable 9,195 51,040 95,348
Payment of Disputed Tax and
Interest Related to COLI (6,272) (104,222) -
Change in Operating Reserves 66,573 77,811 30,294
Other (net) 48,718 42,981 38,141
Net Cash Flows From Operating Activities 335,498 404,764 442,018
INVESTING ACTIVITIES:
Construction Expenditures (193,870) (185,036) (172,477)
Proceeds from Sales of Property and Other 5,900 5,910 8,954
Net Cash Flows Used For Investing Activities (187,970) (179,126) (163,523)
FINANCING ACTIVITIES:
Issuance of Long-term Debt 222,308 186,126 146,590
Retirement of Cumulative Preferred Stock (3,392) (133) (117,624)
Retirement of Long-term Debt (158,638) (197,911) (122,127)
Change in Short-term Debt (net) 71,913 44,305 37,398
Dividends Paid on Common Stock (210,813) (211,101) (199,333)
Dividends Paid on Cumulative Preferred Stock (1,420) (1,475) (3,199)
Net Cash Flows Used For Financing Activities (80,042) (180,189) (258,295)
Net Increase in Cash and Cash Equivalents 67,486 45,449 20,200
Cash and Cash Equivalents January 1 89,652 44,203 24,003
Cash and Cash Equivalents December 31 $ 157,138 $ 89,652 $ 44,203
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1999 1998
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,713,421 $ 2,646,597
Transmission 857,420 842,318
Distribution 999,679 949,224
General (including mining assets) 713,882 689,815
Construction Work in Progress 116,515 129,887
Total Electric Utility Plant 5,400,917 5,257,841
Accumulated Depreciation and Amortization 2,621,711 2,461,376
NET ELECTRIC UTILITY PLANT 2,779,206 2,796,465
OTHER PROPERTY AND INVESTMENTS 253,668 218,311
CURRENT ASSETS:
Cash and Cash Equivalents 157,138 89,652
Accounts Receivable:
Customers 246,310 215,665
Affiliated Companies 89,215 63,922
Miscellaneous 22,055 28,139
Allowance for Uncollectible Accounts (2,223) (1,678)
Fuel - at average cost 146,317 94,914
Materials and Supplies - at average cost 95,967 86,870
Accrued Utility Revenues 45,575 43,501
Energy Marketing and Trading Contracts 134,567 19,790
Prepayments and Other 38,472 34,523
TOTAL CURRENT ASSETS 973,393 675,298
REGULATORY ASSETS 577,090 551,776
DEFERRED CHARGES 93,852 102,830
TOTAL $4,677,209 $ 4,344,680
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 462 376 462,335
Retained Earnings 587,424 587,500
Total Common Shareholder's Equity 1,371,001 1,371,036
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,937 17,370
Subject to Mandatory Redemption 8,850 11,850
Long-term Debt 1,139,834 1,073,456
TOTAL CAPITALIZATION 2,536,622 2,473,712
OTHER NONCURRENT LIABILITIES 414,837 360,330
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 11,677 11,472
Short-term Debt 194,918 123,005
Accounts Payable - General 180,383 173,369
Accounts Payable - Affiliated Companies 64,599 62,418
Taxes Accrued 179,112 161,406
Interest Accrued 16,863 14,187
Obligations Under Capital Leases 34,284 28,310
Energy Marketing and Trading Contracts 131,844 22,480
Other 96,445 97,916
TOTAL CURRENT LIABILITIES 910,125 694,563
DEFERRED INCOME TAXES 676,460 711,913
DEFERRED INVESTMENT TAX CREDITS 35,838 39,296
DEFERRED CREDITS 103,327 64,866
COMMITMENTS AND CONTINGENCIES (Notes 5 and 6)
TOTAL $4,677,209 $4,344,680
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
1999 1998 1997
(in thousands)
Retained Earnings January 1 $587,500 $590,151 $584,015
Net Income 212,157 209,925 208,689
799,657 800,076 792,704
Deductions:
Cash Dividends Declared:
Common Stock 210,813 211,101 199,333
Cumulative Preferred Stock:
4.08% Series 61 63 91
4.20% Series 97 97 127
4.40% Series 142 143 204
4-1/2% Series 460 467 581
5.90% Series 472 487 961
6.02% Series 156 186 735
6.35% Series 32 32 500
Total Dividends 212,233 212,576 202,532
Capital Stock Expense - - 21
Total Deductions 212,233 212,576 202,553
Retained Earnings December 31 $587,424 $587,500 $590,151
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Ohio Power Company (the Company or OPCo) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co.,
Inc.), a public utility holding company. The Company is engaged in
the generation, purchase, sale, transmission and distribution of
electric power to 691,000 retail customers in northwestern, east
central, eastern and southern sections of Ohio and does business as
American Electric Power (AEP). Under terms of the AEP System Power
Pool (AEP Power Pool) and AEP System Transmission Equalization
Agreement, the Company's generation and transmission facilities are
operated in conjunction with the facilities of certain other AEP
affiliated utilities as an integrated utility system. The Company
as a member of the AEP Power Pool shares in the revenues and costs
of AEP Power Pool wholesale sales to neighboring utility systems
and power marketers. The Company also sells wholesale power to
municipalities and cooperatives.
The Company has three wholly-owned coal-mining subsidiaries:
Central Ohio Coal Company (COCCo), Southern Ohio Coal Company
(SOCCo) and Windsor Coal Company (WCCo). Coal produced by SOCCo's
Meigs mine is sold to the Company at cost including a Securities
and Exchange Commission (SEC) approved return on investment. COCCo
closed the Muskingum mine in October 1999 and WCCo is scheduled to
close April 30, 2000. See Footnote 2, "Rate Matters" for further
discussion of fuel cost recovery.
Regulation
As a subsidiary of AEP Co., Inc., the Company is subject to
regulation by the SEC under the Public Utility Holding Company Act
of 1935 (1935 Act). Retail rates are regulated by the Public
Utilities Commission of Ohio (PUCO). The Federal Energy Regulatory
Commission(FERC) regulates the Company's wholesale and transmission
rates.
Principles of Consolidation
The consolidated financial statements include the revenues,
expenses, cash flows, assets, liabilities and equity of OPCo and
its wholly-owned subsidiaries. Significant intercompany items are
eliminated in consolidation.
Basis of Accounting
As a cost-based rate-regulated entity, the Company'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.
Utility Plant
Electric utility plant 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 of plant are deducted from the electric utility plant
in service account and deducted from accumulated depreciation
together with associated removal costs, net of salvage. The costs
of labor, materials and overheads incurred to operate and maintain
utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is capitalized
and recovered through depreciation over the service life of utility
plant. It represents the estimated cost of borrowed and equity
funds used to finance construction projects. The amounts of AFUDC
for 1999, 1998 and 1997 were not significant.
Depreciation, Depletion and Amortization
Depreciation of electric utility plant 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 as follows:
Functional Class Annual Composite
of Property Depreciation Rates
1999 1998 1997
Production:
Steam-Fossil-Fired 3.4% 3.4% 3.4%
Hydroelectric-Conventional 2.7% 2.7% 2.7%
Transmission 2.3% 2.3% 2.3%
Distribution 4.0% 4.0% 4.0%
General 2.7% 2.5% 2.5%
Amounts for demolition and removal of plant are recovered
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, 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 $2.32 per ton in 1999, $1.85 per ton in
1998 and $1.91 per ton in 1997. 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.
Operating Revenues and Fuel Costs
Revenues include billed revenues as well as an accrual of
electricity consumed but unbilled at month-end. Changes in retail
fuel cost are deferred until reflected in revenues through a PUCO
fuel cost recovery mechanism. See Note 2 regarding limitations on
recovery of retail jurisdictional fuel costs. Wholesale
jurisdictional fuel cost changes are expensed and billed as
incurred.
Energy Marketing and Trading Transactions
The AEP Power Pool administers and implements power marketing
and trading transactions (trading activities) in which the Company
shares. Trading activities involve the sale of electricity under
physical forward contracts at fixed and variable prices and the
trading of electricity contracts including exchange traded futures
and options, over-the-counter options and swaps. The majority of
these transactions represent physical forward electric contracts in
the AEP System's traditional marketing area and are typically
settled by entering into offsetting contracts. The net revenues
from these regulated transactions in AEP System's traditional
marketing area are included in operating revenues for ratemaking,
accounting and financial and regulatory reporting purposes.
In addition the AEP Power Pool enters into transactions for the
purchase and sale of electricity options, futures and swaps, and
for the forward purchase and sale of electricity outside of the AEP
System's traditional marketing area. The Company's share of these
non-regulated trading activities are included in nonoperating
income.
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". The EITF requires that all energy
trading contracts be marked-to-market. The effect on the
Consolidated Statements of Income of marking open trading contracts
to market is deferred as regulatory assets or liabilities for those
open trading transactions within the AEP System Power Pool's
marketing area that are included in cost of service on a settlement
basis for ratemaking purposes. The Company's share of non-regulated
open trading contracts are accounted for on a mark-to-market basis
in non-operating income. The unrealized mark-to-market gains and
losses from trading activities are reported as
assets and liabilities, respectively. The adoption of the EITF did
not have a material effect on results of operations, cash flows or
financial condition.
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 on the anticipation debt instruments are
deferred and amortized over the life of the debt issuance with the
amortization included in interest charges. There were no such
forward contracts outstanding at December 31, 1999 or 1998.
See Note 11 - Financial Instruments, Credit and Risk Management
for further discussion.
Reclassification
Certain prior year amounts have been reclassified to conform
to current year presentation. Such reclassifications had no impact
on previously reported net income.
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 (that is, deferred
taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are
recorded and related regulatory assets and liabilities are
established 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. Investment tax credits that have been deferred are being
amortized over the life of the regulated plant investment.
Debt and Preferred Stock
Gains and losses from the 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.
Debt discount or premium and debt issuance expenses are
deferred and 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 Property and Investments
Other property and investments are stated at cost.
Comprehensive Income
There were no material differences between net income and
comprehensive income.
2. RATE MATTERS:
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. The 1995 Settlement Agreement requires
for the two year period from December 1, 1998 through November 30,
2000 that coal from Central Ohio Coal Company's Muskingum mine and
Windsor Coal Company's mine be priced at the market price for
comparable quality coal. The Company is allowed to defer the
difference for future recovery. Effective December 1, 1998 the
1992 stipulation continued to control the recovery of fuel costs at
the Gavin Plant and the ability of OPCo to recover the costs to
shut down its affiliated mines. To the extent the actual cost of
coal burned at the Gavin Plant is below the predetermined prices,
the stipulation agreement provides the Company with the opportunity
to recover over its term the Ohio jurisdictional share of the
Company's investment in and the liabilities and future shutdown
costs of its affiliated mines as well as any fuel costs incurred
above the predetermined rate and deferred for future recovery under
the agreements. These agreements will be superseded effective
January 1, 2001 by the Ohio Electric Restructuring Act of 1999 (see
Note 4).
The Muskingum coal mine which supplied all of its output to
OPCo was closed in October 1999. During 1999 efforts began to
reclaim the properties, sell or scrap all mining equipment,
terminate both capital and operating leases and perform other
activities necessary to shut down the mine. Mine reclamation
activities should be completed by December 31 2002; postremediation
monitoring is anticipated to continue for five years after
completion of reclamation.
In 1999 the Company announced that the affiliated Windsor coal
mine would close April 30, 2000. After the mine closes, efforts
will begin to reclaim the property, sell or scrap all mining
equipment and perform other activities necessary to shut down the
mine. Reclamation activities should be completed within two to
three years after shutdown.
The Company recorded mine closing costs of $45 million in 1998
for the Muskingum mine and $48 million in 1999 for the Windsor
mine. Pursuant to terms of the 1992 and 1995 agreements, the
Company deferred accrued mine closure costs of $19 million in 1998
for the Muskingum mine and $25 million in 1999 for the Windsor
mine. Fuel expense included $23 million and $26 million in 1999
and 1998, respectively, of mine closure costs. At December 31,
1999, the accrued liabilities for reclamation, mine closing costs
and post shutdown costs were $119 million for the Muskingum mine
and $84 million for the Windsor mine.
Revenues and net income for the Muskingum mining operation in
1999 up to the shutdown date were $64 million and $1,000,
respectively. For the years ended December 31, 1998 and 1997
revenues and net income from the Muskingum mining operation were
$110 million and $1,000 and $66 million and zero, respectively.
For the years ended December 31, 1999, 1998 and 1997 revenues and
net income from the Windsor mining operation were $123 million and
$18,000, $65 million and $123,000, and $69 million and $1 million,
respectively.
Management believes the Ohio jurisdictional portion of the cost
of the mine shutdowns can be deferred for future recovery through
the Ohio fuel clause mechanism under terms of the Ohio fuel clause
predetermined price agreements. At December 31, 1999 the Company
has deferred $196 million under the terms of the Ohio fuel clause
predetermined price agreements. However, since the Ohio Electric
Restructuring Act of 1999 (the Act) supersedes the agreements, the
Company has filed under the provisions of the Act for recovery of
all of its generation related regulatory assets which includes the
fuel deferral at December 31, 1999 plus the projected balance that
will be deferred for the accrual of the Meigs mine closure costs by
the beginning of the transition period, January 1, 2001. Under the
provisions of the Act the Company is seeking a total of $360
million for the regulatory assets deferred under the above
agreements through transition rates and a post generation
deregulation five year wires charge. Unless the cost of the
remaining coal production and deferred mine shutdowns are recovered
through the remaining Ohio fuel clause rates and Ohio restructuring
transition rates and/or a post deregulation wires charge, future
results of operations and cash flows will be adversely affected.
Management intends to continue to recover from non-Ohio
jurisdictional ratepayers the non-Ohio jurisdictional portion of
the investment in and the liabilities and closing costs of the
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 $62 million
after tax at December 31, 1999.
Open Access Transmission Tariff
The Federal Energy Regulatory Commission (FERC) issued orders
888 and 889 in April 1996 which required each public utility that
owns or controls interstate transmission facilities to file an open
access network and point-to-point transmission tariff that offers
services comparable to the utility's own uses of its transmission
system. The orders also require utilities to functionally unbundle
their services, by requiring them to use their own transmission
service tariffs in making off-system and third-party sales. As
part of the orders, the FERC issued a pro-forma tariff which
reflects the Commission's views on the minimum non-price terms and
conditions for non-discriminatory transmission service. The FERC
orders also allow a utility to seek recovery of certain prudently-incurred
stranded costs that result from unbundled transmission
service.
In July 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain pricing
issues. The 1996 tariff incorporated transmission rates which were
the result of a settlement of a pending rate case, but which were
being collected subject to refund from certain customers who
opposed the settlement and continued to litigate the reasonableness
of AEP's transmission rates. On July 30, 1999, the FERC issued an
order in the litigated rate case which would reduce AEP's rates for
the affected customers below the settlement rate. AEP and certain
of the affected customers have sought rehearing of the Commission's
Order. The Company made a provision in September 1999 for its
share of the refund including interest.
On December 10, 1999, the AEP System filed a settlement
agreement with the FERC resolving the issues on rehearing of the
July 30, 1999 order. Under terms of the settlement, the AEP System
will make refunds retroactive to September 7, 1993 to certain
customers affected by the July 30, 1999 FERC order. The refunds
will be made in two payments. The first payment was made on
February 2, 2000 pursuant to a FERC order granting AEP's request
to make interim refunds. The remainder will be paid after the FERC
issues a final order and approves a compliance filing that the AEP
System will make pursuant to the final order. In addition, a new
rate was made effective January 1, 2000, subject to FERC approval,
for all transmission service customers and a future rate was
established to take effect upon the consummation of the AEP and
Central and South West Corporation merger unless a superseding rate
is made effective prior to the merger.
3. EFFECTS OF REGULATION:
In accordance with SFAS 71 the consolidated financial
statements include regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) recorded in accordance
with regulatory actions in order to match expenses and revenues
from cost-based rates in the same accounting period. 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. Among other things, application of
SFAS 71 requires that the Company's regulated rates be cost-based
and the recovery of regulatory assets must be probable. Management
has reviewed all the evidence currently available and concluded
that the Company continues to meet the requirements to apply SFAS
71. In the event a portion of the Company's business no longer met
those 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. See Note 4 "Ohio Restructuring Legislation" for a
discussion of deregulation of generation under an Ohio electric
restructuring law.
Recognized regulatory assets and liabilities are comprised of
the following:
December 31,
1999 1998
(In Thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $331,164 $370,468
Deferred Fuel Costs 180,336 110,602
Unamortized Loss On
Reacquired Debt 15,666 14,996
Other 49,924 55,710
Total Regulatory Assets $577,090 $551,776
Regulatory Liabilities:
Deferred Investment Tax Credits $ 35,838 $39,296
Deferred Gains From Emission
Allowance Sales* 53,738 40,000
Other* 13,043 8,170
Total Regulatory Liabilities $102,619 $87,466
*Included in Deferred Credits on Consolidated Balance Sheets.
4. OHIO RESTRUCTURING LEGISLATION:
The Ohio Electric Restructuring Act of 1999 (the Act) became
law in October 1999. The Act provides for customer choice of
electricity supplier, a residential rate reduction of 5% for the
generation portion of rates and a freezing of generation rates
including fuel rates beginning on January 1, 2001. The Act also
provides for a five-year transition period to move from cost based
rates to market pricing for generation services. It authorizes the
PUCO to address certain major transition issues including
unbundling of rates and the recovery of transition costs. Under
the Act, transition costs can include regulatory assets,
impairments of generating assets and other stranded costs, employee
severance and retraining costs, consumer education costs and other
costs. Stranded generation costs are those costs of generation
above the market price for electricity that potentially would not
be recoverable in a competitive market.
Retail electric services that will be competitive are defined
in the Act as electric generation service, aggregation service and
power marketing and brokering. Under the legislation the PUCO is
granted broad oversight responsibility and is required by the Act
to promulgate rules for competitive retail electric generation
service and transition plan filings. The Act also gives the PUCO
authority to approve a transition plan for each electric utility
company and sets a deadline of no later than October 31, 2000 for
those approvals.
The Act provides that electric utilities in Ohio with an
opportunity to recover PUCO approved allowable transition costs
through generation rates paid through December 31, 2005 by
customers who do not switch generation suppliers and through a
transition charge for customers who switch generation suppliers.
Recovery of the regulatory asset portion of transition costs can,
under certain circumstances, extend beyond the five-year transition
period but cannot continue beyond December 31, 2010.
The Act also provides for a reduction in property tax
assessments, the imposition of franchise and income taxes, and the
replacement of a gross receipts tax with a kilowatt-hour (kwh)
based excise tax. The property tax assessment percentage on
generation property will be lowered from 100% to 25% of value
effective January 1, 2001 and electric utilities will become
subject to the Ohio Corporate Franchise Tax and municipal income
taxes on January 1, 2002. The last year for which electric
utilities will pay the excise tax based on gross receipts is the
tax year ending April 30, 2002. As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kwh sold to Ohio customers. The gross receipts tax is paid at the
beginning of the tax year, deferred as a prepaid expense and
amortized to expense during the tax year pursuant to the tax law
whereby the payment of the tax results in the privilege to conduct
business in the year following the payment of the tax. The change
in the tax law to impose an excise tax based on kwh sold to Ohio
customers commencing before the expiration of the gross receipts
tax privilege period will result in a 12 month period when the
Company is recording as an expense both the gross receipts tax and
the excise tax. In the Company's Ohio transition plan filing,
recovery of $50 million was sought for this overlap of the gross
receipts and excise taxes.
The Company filed its transition plan with the PUCO on December
30, 1999. The filing included the following elements:
a rate unbundling plan including tariff
terms and conditions necessary for
restructuring,
a corporate separation plan,
an application for transition revenues,
a plan for independent operation of
transmission facilities and
other components for the implementation of
restructuring.
Under the rate unbundling plan in the transition plan filing,
the Company will offer two transition period tariffs beginning
January 1, 2001, the standard tariff and the open access
distribution tariff. The proposed standard tariff applies to
customers who do not choose an alternative energy supplier. This
tariff schedule includes detailed charges for generation,
transmission and distribution and riders to fund universal service,
to promote energy efficiency and to recover regulatory assets and
taxes. Taxes include charges for municipal income, excise and
franchise taxes and tax credits for gross receipts and property
taxes. For customers who choose an alternative electric supplier,
the proposed open access distribution tariff will apply. This
tariff includes charges for transmission and distribution and
riders to fund universal service, to promote energy efficiency and
to recover regulatory assets and taxes. These riders are the same
as those in the standard tariff except there is no property tax
credit.
The Company's corporate separation plan proposal requires
establishment of separate subsidiaries to own and operate the
transmission and distribution assets. The Company will retain
generation related assets. The separation plan will be implemented
in a manner that recognizes the current overlap of financing
arrangements. This would permit an orderly and economically
efficient separation of generation from transmission and
distribution so that additional transition costs can be minimized
from premature unwinding of existing financial instruments. Prior
to the actual legal separation, the Company will functionally
separate generation from transmission and distribution.
An application to receive transition revenues was included in
the Company's transition plan filing. It requests recovery of
stranded generation costs over a five year period and recovery of
generation-related regulatory assets of $611 million over a 10-year
period. The amount requested for recovery of regulatory assets
includes current and new regulatory assets including those arising
from compliance with the Act and closure of the affiliated mines.
Included in the transition plan is a proposal to implement
independent operation of the transmission system. The Company
proposes to join a regional transmission organization whose
approval is currently pending before the FERC. A project timeline
for activities to implement operational support systems and other
technical implementation issues to arrive at and support a
competitive electricity market are included in the transition plan.
The Company plans to provide severance, retraining, early
retirement, retention, outplacement and other assistance for
displaced employees. At this time no employees are identified as
affected by electric utility restructuring. Consequently, recovery
of such costs was not requested in transition revenues as filed
with the transition plan.
The transition plan includes a consumer education plan which
will be implemented in conjunction with other electric utilities
and the PUCO staff. The transition plan also has terms and
conditions for changing suppliers and the commitment of time a
customer must accept in a service contract which are two features
necessary to accommodate restructuring.
A proposed shopping incentive in the transition plan represents
the lower of the market price or the unbundled generation rate in
current tariff schedules.
As discussed in Note 3, "Effects of Regulation," the Company
defers as regulatory assets and liabilities certain expenses and
revenues consistent with the regulatory process in accordance with
SFAS 71. Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met since the
Company's rates for generation will continue to be cost-based
regulated until the PUCO takes action on the transition plan and
the proposed tariff schedules contained in it as provided in the
Act. The establishment, on or before the October 31, 2000
deadline, of rates and charges under the transition plan should
enable the Company to determine its ability to recover regulatory
assets, transition costs and other stranded costs, a requirement to
discontinue application of SFAS 71.
When the transition plan and tariff schedules are approved, the
application of SFAS 71 will be discontinued for the Ohio retail
jurisdictional portion of the generation business. At that time
the Company will have to write-off its Ohio jurisdictional
generation-related regulatory assets to the extent that they cannot
be recovered under the tariff schedules in the transition plan
approved by the PUCO and record any asset impairments in accordance
with SFAS 121, "Accounting for the Impairment of Long-lived Assets
and for Long-lived Assets to Be Disposed Of." An impairment loss
would be recorded to the extent that the cost of generating assets
cannot be recovered through generation-related revenues during the
transition period and future market prices. Until the PUCO
completes its regulatory process and issues an order related to the
Company's transition plan, it is not possible for management to
determine if any of the Company's generating assets are impaired in
accordance with SFAS 121. The amount of regulatory assets recorded
on the books at December 31, 1999 applicable to the Ohio retail
jurisdictional generating business is $361 million before related
tax effects. Due to the planned closing of affiliated mines and
other anticipated events, generation-related regulatory assets as
of December 31, 2000 allocable to the Ohio retail jurisdiction are
estimated to exceed $520 million, before income tax effects.
Recovery of these regulatory assets and an estimated asset
impairment are being sought as a part of the Company's Ohio
transition plan filing.
A determination of whether the Company will experience any
asset impairment loss regarding its Ohio retail jurisdictional
generating assets and any loss from a possible inability to recover
Ohio generation-related regulatory assets and other transition
costs cannot be made until the PUCO takes action on the Company's
transition plan. Management is seeking full recovery of
generation-related regulatory assets, stranded costs and other
transition costs in its transition plan filing. The PUCO is
required to complete its regulatory process including review of the
Company's transition plan filing and issue a transition order no
later than October 31, 2000. Should the PUCO fail to fully approve
the Company's transition plan and its tariff schedules which
include recovery of the Company's generation-related regulatory
assets, stranded costs and other transition costs, it could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
5. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made to support
the Company's utility operations and are estimated to be $783
million for 2000-2002.
In addition to fuel acquired from coal-mining subsidiaries and
spot-markets, the Company has long-term fuel supply contracts with
unaffiliated companies. The contracts generally contain clauses
that provide for periodic price adjustments. The Company's retail
jurisdictional fuel clause mechanism provides, with the PUCO's
review and approval, for deferral and subsequent recovery or refund
of changes in the cost of fuel. However, effective with
restructuring in Ohio, which is effective on January 1, 2001, the
fuel clause will be frozen and will eventually terminate on
December 31, 2005 with the end of the transition period. As such
the Company will be subject to market risk in the price of fuel
after January 1, 2001. The unaffiliated fuel supply contracts are
for various terms, the longest of which extends to 2012, and
contain clauses that would release the Company from its obligation
under certain force majeure conditions.
Federal EPA Complaint and Notice of Violation
Under the Clean Air Act, if a plant undertakes a major
modification that directly results in an emissions increase,
permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at certain of its coal-fired
generating plants over the course of the past 25 years that extend
unit operating lives or increase unit generating capacity without
a preconstruction permit in violation of the Clean Air Act.
Federal EPA also issued Notices of Violation to other AEP companies
alleging similar violations at certain AEP plants. A number of
unaffiliated utilities also received Notices of Violation,
complaints or administrative orders.
The states of New Jersey, New York and Connecticut were
subsequently granted leave to intervene in the Federal EPA's action
against the Company under the Clean Air Act. On November 18, 1999
a number of environmental groups filed a lawsuit against power
plants owned by the Company alleging similar violations to those in
the Federal EPA complaint and Notices of Violation. This action
has been consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts Federal EPA's contentions, could be
substantial.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and intends to
vigorously pursue its defense of this matter.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates, and as generation is deregulated, future market prices for
electricity.
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 U.S. District Court (discussed below) this request for ruling
was withdrawn by the IRS agents. Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions for
taxable years 1991-96. A disallowance of COLI interest deductions
through December 31, 1999 would reduce earnings by approximately
$118 million (including interest).
The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-98 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are
included on the consolidated balance sheets in other property and
investments pending the resolution of this matter. The Company is
seeking refund through litigation of all amounts paid plus
interest.
In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern
District of Ohio in March 1998. In 1999 a U.S. Tax Court judge
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deduction should be disallowed.
Notwithstanding the Tax Court's decision in Winn-Dixie, management
has made no provision for any possible adverse earnings impact from
this matter because it believes, and has been advised by outside
counsel, that it has a meritorious position and will vigorously
pursue its 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.
Other
The Company is involved in a number of other legal proceedings
and claims. While management is unable to predict the ultimate
outcome of these matters, it is not expected that their resolution
will have a material adverse effect on the results of operations,
cash flows or financial condition.
6. SUBSEQUENT EVENT - NOx REDUCTIONS (March 3, 2000):
On March 3, 2000, the U.S. Court of Appeals for the District
of Columbia Circuit (Appeals Court) issued a decision generally
upholding Federal EPA's final rule (the NOx rule) that requires
substantial reductions in nitrogen oxide (NOx) emissions in 22
eastern states, including the states in which the Company's
generating plants are located. A number of utilities, including the
Company, had filed petitions seeking a review of the final rule in
the Appeals Court. On May 25, 1999, the Appeals Court had
indefinitely stayed the requirement that states develop revised air
quality programs to impose the NOx reductions but did not, however,
stay the final compliance date of May 1, 2003.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to the
Clean Air Act (Section 126 Rule). The rule approved portions of
the states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx Rule. The AEP System companies
with generating plants, as well as other utility companies, filed
a petition in the Appeals Court seeking review of Federal EPA's
approval of the northeastern states' petitions. In 1999, three
additional northeastern states and the District of Columbia filed
petitions with Federal EPA similar to those originally filed by the
eight northeastern states. Since the petitions relied in part on
compliance with an 8-hour ozone standard remanded by the Appeals
Court in May 1999, Federal EPA indicated its intent to decouple
compliance with the 8-hour standard and issue a revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126
Rule not based on the 8-hour standard and ordered 392 industrial
facilities, including certain coal-fired generating plants owned by
the Company, to reduce their NOx emissions by May 1, 2003. This
rule approves portions of the petitions filed by four northeastern
states which contend that their failure to meet Federal EPA smog
standards is due to emissions from upwind states' industrial and
coal-fired generating facilities.
Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeals Court could result in required capital
expenditures of approximately $624 million for the Company. Since
compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates and/or
reflected in the future market price of electricity if generation
is deregulated, they will have an adverse effect on future results
of operations, cash flows and possibly financial condition.
7. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are
shared by members of the AEP Power Pool of which the Company is a
member. Under the terms of the System Interconnection Agreement,
capacity charges and credits are designed to allocate the cost of
the System's capacity among the AEP Power Pool members based on
their relative peak demands and generating reserves. AEP Power
Pool members are also compensated for the out-of-pocket costs of
energy delivered to the AEP Power Pool and charged for energy
received from the AEP Power Pool. The Company is a net supplier to
the pool and, therefore, receives capacity credits from the AEP
Power Pool.
Operating revenues include revenues for capacity and energy
supplied to the AEP Power Pool as follows:
Year Ended December 31,
1999 1998 1997
(In Thousands)
Capacity Revenues $148,876 $150,378 $165,604
Energy Revenues 183,619 212,965 149,436
Total $332,495 $363,343 $315,040
Purchased power expense includes charges of $20.9 million in
1999, $18.2 million in 1998 and $26.4 million in 1997 for energy
received from the Power Pool.
The AEP Power Pool allocates operating revenues, purchased
power expense and nonoperating income to the Company. Power
marketing and trading operations, which are described in Note 1,
are conducted by the AEP Power Pool and shared with the Company.
Net trading transactions are included in operating revenues if the
trading transactions are within the AEP Power Pool's traditional
marketing area and are recorded in nonoperating income if the net
trading transactions are outside of the AEP Power Pool's
traditional marketing area. The total amounts allocated by the AEP
Power Pool which includes amounts for power marketing and trading
transactions, are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Operating Revenues $138,709 $176,710 $105,377
Purchased Power Expense 94,296 101,255 21,839
Nonoperating Income (Loss) 4,776 (10,136) (72)
Purchased power expense includes $25.6 million in 1999, $12
million in 1998 and $6.2 million in 1997 for energy bought from the
Ohio Valley Electric Corporation, an affiliated company that is not
a member of the AEP Power Pool.
Operating revenues include energy sold directly to Wheeling
Power Company (WPCo) in the amounts of $55.6 million in 1999, $55.2
million in 1998 and $55.0 million in 1997. WPCo is an affiliated
distribution utility that is not a member of the AEP Power Pool.
The Company participates in the AEP Transmission Equalization
Agreement along with other AEP System electric operating utility
companies. This agreement combines certain AEP System companies'
investments in transmission facilities and shares the costs of
ownership in proportion to the System companies' respective peak
demands. Pursuant to the terms of the agreement, since the
Company's relative investment in transmission facilities is less
than its relative peak demand, other operation expense includes
equalization charges of $17.5 million, $16.9 million and $10.5
million in 1999, 1998 and 1997, respectively.
Coal-transportation costs paid to affiliated companies aggre-
gate approximately $9.1 million, $7.6 million and $8.5 million in
1999, 1998 and 1997, respectively. These charges are included in
fuel expense. The prices charged by the affiliates for coal
transportation services are computed in accordance with orders
issued by the SEC.
The Company and an affiliate, Appalachian Power Company,
jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership
interests. The Company's share of these costs is included in the
appropriate expense accounts on the Consolidated Statements of
Income and the investment is included in electric utility plant on
the Consolidated Balance Sheets.
American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies including the Company. The costs of the services are
billed by AEPSC to its affiliated companies on a direct-charge
basis whenever possible and on reasonable bases of proration for
shared services. The billings for services are made at cost and
include no compensation for the use of equity capital, which is
furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are
capitalized or expensed depending on the nature of the services
rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
8. STAFF REDUCTIONS:
During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing a better
organizational structure for a competitive generation market. The
study was completed in October 1998. In addition, a review of
energy delivery staffing levels was conducted in 1998. As a result
approximately 150 power generation and energy delivery positions
were identified for elimination.
Severance accruals totaling $8.6 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 the first quarter of 1999
the power generation and energy delivery staff reductions were
made. The amount of severance benefits paid was not significantly
different from the amount accrued.
9. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System
qualified pension plan, a defined benefit plan which covers all
employees, except participants in the United Mine Workers of
America (UMWA) pension plans. Net pension costs (credits) for the
AEP System pension plan for the years ended December 31, 1999 and
1997 were $(5.0) million and $1.4 million, respectively. There
were no pension costs in 1998.
Postretirement benefits other than pensions are provided for
retired employees for medical and death benefits under an AEP
System plan. Postretirement medical benefits for UMWA employees
who have or will retire after January 1, 1976 are the liabilities
of the Company's coal-mining subsidiaries. The annual accrued
costs for postretirement medical and death benefits were $52.5
million in 1999, $54.6 million in 1998 and $30.1 million in 1997.
A defined contribution employee savings plan required that the
Company make contributions to the plan of $3.7 million in 1999 and
$4 million each year in 1998 and 1997.
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 1999, 1998 and 1997. Based upon the UMWA actuarial
estimate, the Company's share of the unfunded pension liability was
$16.5 million at June 30, 1999. 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
the pension that equals the unfunded pension liability. If the
Meigs mining operations had been closed on December 31, 1999 the
estimated annual liability for the UMWA health and welfare plans
would have been approximately $1 million.
10. SEGMENT INFORMATION:
Effective December 31, 1998 the Company adopted SFAS 131,
"Disclosures about Segments of an Enterprise and Related
Information". The Company has one reportable segment, a regulated
vertically integrated electricity generation and energy delivery
business. All other activities are insignificant. The Company's
operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory
oversight on business processes, cost structures and operating
results. Included in the regulated electric utility segment is the
power marketing and trading activities that are discussed in Note
1 and the Company's coal mining activities. For the years ended
December 31, 1999, 1998 and 1997, all of the Company's revenues are
derived from the generation, sale and delivery of electricity in
the United States.
11. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT:
The Company is subject to market risk as a result of changes
in electricity commodity prices and interest rates. The Company
through its membership in the AEP Power Pool participates in a
power marketing and trading operation that manages the exposure to
electricity 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 within the AEP System's traditional
marketing area are recorded on a net basis as operating revenues in
the month when the physical contract settles. The Company's share
of the net gains from these regulated transactions for the year
ended December 31, 1999 and 1998 was $6 million and $31 million,
respectively. These activities were not material in 1997.
Non-regulated physical forward electricity contracts outside
AEP's traditional marketing area and all financial electricity
trading transactions where the underlying physical commodity is
outside AEP's traditional marketing area are recorded in
non-operating income. Non-regulated open trading contracts are
accounted for on a mark-to-market basis in nonoperating income.
The Company's share of the net gains (losses) from these
non-regulated trading transactions for the year ended December 31, 1999
and 1998 was $5 million and $(10) million, respectively.
In the first quarter of 1999 the Company adopted EITF 98-10
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." The EITF requires that all energy trading
contracts be marked-to-market. The effect on the Consolidated
Statements of Income of marking open trading contracts to market is
deferred as regulatory assets or liabilities for those open trading
transactions within the AEP Power Pool's marketing area that are
included in the cost of service on a settlement basis for rate-making
purposes. The unrealized mark-to-market gains and losses
from trading of financial instruments are reported as assets and
liabilities, respectively. These activities were not material in
prior periods.
The Company is exposed to risk from changes in interest rates
primarily due to short-term 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 39 years and an
average duration of six years at December 31, 1999. A near term
change in interest rates should not materially affect results of
operations or financial position since the Company would not expect
to liquidate its entire debt portfolio in a one year holding
period.
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 amounts and fair values of the Company's
significant financial instruments at December 31, 1999 and 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.
1999 1998
Book Value Fair Value Book Value Fair Value
(in thousands) (in thousands)
Non-Derivatives
Long-term Debt $1,151,511 $1,027,000 $1,084,928 $1,140,000
Preferred Stock 8,850 8,500 11,850 12,200
Derivatives
1999 1998
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
(Dollars in thousands)
Trading Assets
Electric GWH GWH
NyMex Future
and Options 61 $ 583 $ 286 - $ - $ -
Physicals 18,753 155,507 146,395 15,990 12,800 11,100
Options 1,673 9,672 9,936 1,058 8,200 21,000
Swaps 48 987 967 76 900 300
Trading Liabilities
Electric GWH GWH
NyMex Future
and Options - $ - $ - 193 $ (2,100) $ (500)
Physicals 20,171 (143,440) (135,015) 15,753 (14,700) (12,700)
Options 2,403 (11,506) (7,084) 802 (7,300) (21,400)
Swaps 49 (1,846) (1,829) 133 (2,100) (500)
Credit and Risk Management
In addition to market risk associated with electricity price
movements, the Company through the AEP Power Pool 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 AEP Power Pool has
established and enforced credit policies that minimize this risk.
The AEP Power Pool 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 AEP Power Pool requires further credit
enhancements to mitigate risk. Since the formation of the power
marketing and trading business in July of 1997, the Company has
experienced no significant losses due to the credit risk associated
with 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.
12. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $133,862 $118,189 $116,795
Deferred 4,205 3,907 11,257
Deferred Investment Tax Credits (1,825) (1,827) (1,829)
Total 136,242 120,269 126,223
Charged (Credited) to Nonoperating Income (net):
Current (3,256) (5,619) 624
Deferred (539) (865) (3,630)
Deferred Investment Tax Credits (1,633) (1,698) (1,658)
Total (5,428) (8,182) (4,664)
Total Federal Income Taxes as Reported $130,814 $112,087 $121,559
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,
1999 1998 1997
(in thousands)
Net Income $212,157 $209,925 $208,689
Federal Income Taxes 130,814 112,087 121,559
Pre-tax Book Income $342,971 $322,012 $330,248
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35%) $120,040 $112,704 $115,587
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 17,517 16,693 15,961
Corporate Owned Life Insurance 198 (5,238) (7,179)
Investment Tax Credits (net) (3,458) (3,525) (3,487)
Other (3,483) (8,547) 677
Total Federal Income Taxes as Reported $130,814 $112,087 $121,559
Effective Federal Income Tax Rate 38.1% 34.8% 36.8%
The following tables show the elements of the net deferred tax
liability and the significant temporary difference giving rise to
such deferrals:
December 31,
1999 1998
(in thousands)
Deferred Tax Assets $ 234,826 $ 197,552
Deferred Tax Liabilities (911,286) (909,465)
Net Deferred Tax Liabilities $(676,460) $(711,913)
Property Related Temporary
Differences $(599,863) $(621,562)
Amounts Due From Customers For
Future Federal Income Taxes (108,185) (122,583)
Deferred Fuel (62,832) (34,475)
Post Retirement Benefits 44,483 29,667
Deferred State Income Taxes (22,124) (20,107)
All Other (net) 72,061 57,147
Net Deferred Tax Liabilities $(676,460) $(711,913)
The Company and its subsidiaries join in the filing of a
consolidated federal income tax return with their affiliated
companies in the AEP System. The allocation of the AEP System's
current consolidated federal income tax to the System companies is
in accordance with SEC rules under the 1935 Act. These rules
permit the allocation of the benefit of current tax losses to the
System companies giving rise to them in determining their current
tax expense. The tax loss of the System parent company, AEP Co.,
Inc., is allocated to its subsidiaries with taxable income. With
the exception of the loss of the parent company, the method of
allocation approximates a separate return result for each company
in the consolidated group.
The AEP System 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 5,
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. COMMON SHAREHOLDER'S EQUITY:
In 1999, 1998 and 1997 net changes to paid-in capital of
$41,000, $39,000 and $1.6 million, respectively, represented gains
and expenses associated with cumulative preferred stock
transactions. At December 31, 1999, there were no dividend
restrictions on retained earnings. Regulatory approval is required
to pay dividends out of paid-in capital.
14. CUMULATIVE PREFERRED STOCK:
At December 31, 1999, authorized shares of cumulative preferred
stock were as follows:
Par Value Shares Authorized
$100 3,762,403
25 4,000,000
Unissued shares of the cumulative preferred stock may or may
not possess mandatory redemption characteristics upon issuance.
The cumulative preferred stock is callable at the price indicated
plus accrued dividends. The involuntary liquidation preference is
par value.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1999 Value Year Ended December 31, December 31, 1999 1999 1998
1999 1998 1997 (in thousands)
4.08% $103 $100 373 425 27,182 14,595 $ 1,460 $ 1,497
4.20% 103.20 100 - - 28,875 23,100 2,310 2,310
4.40% 104 100 330 200 55,889 31,944 3,194 3,227
4-1/2% 110 100 3,631 1,096 97,949 99,727 9,973 10,336
$16,937 $17,370
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Shares Amount
Par Number of Shares Redeemed Outstanding December 31,
Series (a) Value Year Ended December 31, December 31, 1999 1999 1998
1999 1998 1997 (in thousands)
5.90% (b) $100 10,000 - 321,500 72,500 $7,250 $ 8,250
6.02% (c) 100 20,000 - 364,000 11,000 1,100 3,100
6.35% (c) 100 - - 295,000 5,000 500 500
$8,850 $11,850
(a) Not callable until after 2002. The sinking fund provisions of
each series have been met by the purchase of shares in advance of
the due date.
(b) Commencing in 2004 and continuing through the year 2008, a
sinking fund for the 5.90% cumulative preferred stock will require
the redemption of 22,500 shares each year and the redemption of the
remaining shares outstanding on January 1, 2009, in each case at
$100 per share. Shares previously redeemed may be applied to meet
sinking fund requirements.
(c) Commencing in 2003 and continuing through 2007 cumulative
preferred stock sinking funds will require the redemption of 20,000
shares each year of the 6.02% series and 15,000 shares each year of
the 6.35% series, in each case at $100 per share. All remaining
outstanding shares must be redeemed in 2008. Shares previously
redeemed may be applied to meet the sinking fund requirements.
15. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1999 1998
(in thousands)
First Mortgage Bonds $ 323,772 $ 413,113
Installment Purchase
Contracts 233,025 232,722
Senior Unsecured Notes 408,671 234,266
Notes Payable 30,000 30,000
Junior Debentures 131,860 131,740
Other 24,183 43,087
1,151,511 1,084,928
Less Portion Due Within
One Year 11,677 11,472
Total $1,139,834 $1,073,456
First mortgage bonds outstanding were as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
6.75 2003 - April 1 $ 40,000 $ 40,000
6.875 2003 - June 1 - 40,000
6.55 2003 - October 1 32,135 40,000
6.00 2003 - November 1 25,000 25,000
6.15 2003 - December 1 50,000 50,000
8.80 2022 - February 10 50,000 50,000
7.75 2023 - April 1 40,000 40,000
7.85 2023 - June 1 - 40,000
7.375 2023 - October 1 40,000 40,000
7.10 2023 - November 1 23,000 25,000
7.30 2024 - April 1 25,000 25,000
Unamortized Discount (net) (1,363) (1,887)
Total $323,772 $413,113
Certain indentures relating to the first mortgage bonds
contain improvement, maintenance and replacement provisions
requiring the deposit of cash or bonds with the trustee or, in lieu
thereof, certification of unfunded property additions.
Installment purchase contracts have been entered into in
connection with the issuance of pollution control revenue bonds by
governmental authorities as follows:
December 31,
1999 1998
(in thousands)
Ohio Air Quality Development
7.4% Series B
due 2009 - August 1 $ - $ 50,000
5.15% Series C
due 2026 - May 1 50,000 -
Mason County, West Virginia:
5.45% Series B
due 2016 - December 1 50,000 50,000
Marshall County, West
Virginia:
5.45% Series B
due 2014 - July 1 50,000 50,000
5.90% Series D
due 2022 - April 1 35,000 35,000
6.85% Series C
due 2022 - June 1 50,000 50,000
Unamortized Discount (1,975) (2,278)
Total $233,025 $232,722
Under the terms of the installment purchase contracts, the
Company is required to pay amounts sufficient to enable the payment
of interest on and the principal (at stated maturities and upon
mandatory redemption) of related pollution control revenue bonds
issued to finance the construction of pollution control facilities
at certain plants.
Senior unsecured notes are as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
6.75% 2004 - July 1 $100,000 $ -
7.00% 2004 - July 1 75,000 -
6.73 2004 - November 1 48,000 48,000
6.24 2008 - December 4 50,000 50,000
7-3/8 2038 - June 30 140,000 140,000
Unamortized Discount (4,329) (3,734)
Total $408,671 $234,266
Notes payable outstanding are as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
6.20 2001 - January 31 $ 5,000 $ 5,000
6.20 2001 - January 31 7,000 7,000
6.20 2001 - January 31 18,000 18,000
Total $30,000 $30,000
Junior debentures outstanding were as follows:
December 31,
1999 1998
(in thousands)
8.16% Series A
due 2025 - September 30 $ 85,000 $ 85,000
7.92% Series B
due 2027 - March 31 50,000 50,000
Unamortized Discount (3,140) (3,260)
Total $131,860 $131,740
Interest may be deferred and payment of principal and interest
on the junior debentures is subordinated and subject in right to
the prior payment in full of all senior indebtedness of the
Company.
Finance obligations were entered into by the Company's coal
mining subsidiaries for mining facilities and equipment through
sale and leaseback transactions. In accordance with SFAS 98, the
transactions did not qualify as sales and leasebacks for accounting
purposes and therefore are shown as other long-term debt. The
terms on the remaining long-term debt obligation including renewals
end on December 24, 2001 and contains a bargain purchase option at
expiration of the agreement. At December 31, 1999 the interest
rate was 6.98%.
At December 31, 1999, future annual long-term debt payments
are as follows:
Amount
(in thousands)
2000 $ 11,677
2001 42,506
2002 -
2003 147,135
2004 223,000
Later Years 738,000
Total Principal Amount 1,162,318
Unamortized Discount (10,807)
Total $1,151,511
Short-term debt borrowings are limited by provisions of the
1935 Act to $450 million. Lines of credit are shared with other
AEP System companies and at December 31, 1999 and 1998 were
available in the amounts of $1,056 million and $763 million,
respectively. The short-term bank lines of credit require payment
of facility fees and do not require compensating balances.
Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1999:
Notes Payable $ 5,400 7.2%
Commercial Paper 189,518 6.6%
Total $194,918 6.6%
December 31, 1998:
Commercial Paper $123,005 6.0%
16. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1999 1998 1997
(in thousands)
Cash was paid for:
Interest (net of
capitalized
amounts) $78,739 $ 79,667 $ 81,594
Income Taxes 94,606 118,548 127,719
Noncash Acquisitions
Under Capital Leases 28,561 29,938 53,389
17. LEASES:
Leases of property, plant and equipment are for periods of up
to 30 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 for both operating and capital leases are
generally charged to operating expenses in accordance with
rate-making treatment. The components of rental costs are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Lease Payments on
Operating Leases $ 60,026 $ 59,141 $62,260
Amortization of Capital
Leases 35,622 36,585 25,275
Interest on Capital Leases 9,552 14,309 9,445
Total Lease Rental Costs $105,200 $110,035 $96,980
Properties under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
December 31,
1999 1998
(in thousands)
Electric Utility Plant Under Capital Leases:
Production Plant $ 24,428 $ 23,833
General Plant (including mining assets) 194,172 187,925
Total Electric Utility Plant Under
Capital Leases 218,600 211,758
Accumulated Amortization 90,154 77,131
Net Electric Utility Plant Under
Capital leases 128,446 134,627
Net Other Property Under Capital Leases 8,097 8,008
Net Property Under Capital Leases $136,543 $142,635
Obligations Under Capital Leases*:
Noncurrent Liability $102,259 $114,325
Liability Due Within One Year 34,284 28,310
Total Capital Lease Obligations $136,543 $142,635
* Represents the present value of future minimum lease payments.
Noncurrent capital lease obligations are included in other
noncurrent liabilities on the Consolidated Balance Sheets.
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at
December 31, 1999:
Non-Cancelable
Capital Operating
Leases Leases
(in thousands)
2000 $ 42,743 $ 51,597
2001 36,158 51,202
2002 18,679 50,903
2003 16,984 50,587
2004 13,401 50,672
Later Years 42,879 353,240
Total Future Minimum 170,844
Lease Payments $608,201
Less Estimated
Interest Element 34,301
Estimated Present Value
of Future Minimum
Lease Payments $136,543
18. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1999
March 31 $518,221 $78,956 $60,821
June 30 498,587 73,328 51,865
September 30 544,451 72,858 56,233
December 31 478,004 63,687 43,238
1998
March 31 $515,672 $79,069 $60,436
June 30 523,671 69,865 53,059
September 30 597,812 88,838 65,961
December 31 468,392 51,600 30,469
Fourth quarter 1998 net income declined primarily as a result of
unseasonably mild weather and severance accruals for staff
reductions.
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Ohio Power Company:
We have audited the accompanying consolidated balance sheets of
Ohio Power Company and its subsidiaries as of December 31, 1999
and 1998, and the related consolidated statements of income,
retained earnings, and cash flows for each of the three years
in the period ended December 31, 1999.
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 Ohio Power Company and its subsidiaries as of
December 31, 1999 and 1998, and the results
of their operations and their cash flows for each of the three
years in the period ended December 31, 1999
in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2000
(March 3, 2000 as to Note 6)