KENTUCKY POWER COMPANY
SELECTED FINANCIAL DATA
Year Ended December 31,
1999 1998 1997 1996 1995
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $373,982 $362,999 $340,635 $323,321 $328,144
Operating Expenses 319,307 311,106 293,779 281,978 279,123
Operating Income 54,675 51,893 46,856 41,343 49,021
Nonoperating Income (Loss) (327) (1,726) (464) (594) 3
Income Before Interest Charges 54,348 50,167 46,392 40,749 49,024
Interest Charges 28,918 28,491 25,646 23,776 23,896
Net Income $ 25,430 $ 21,676 $ 20,746 $ 16,973 $ 25,128
December 31,
1999 1998 1997 1996 1995
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,079,048 $1,043,711 $1,006,955 $951,602 $879,657
Accumulated Depreciation
and Amortization 340,008 315,546 296,318 286,640 270,590
Net Electric Utility Plant $ 739,040 $ 728,165 $ 710,637 $664,962 $609,067
Total Assets $ 986,638 $ 921,847 $ 886,671 $833,579 $772,198
Common Stock and
Paid-in Capital $ 209,200 $ 199,200 $ 179,200 $159,200 $129,200
Retained Earnings 67,110 71,452 78,076 84,090 91,381
Total Common Shareholder's
Equity $ 276,310 $ 270,652 $ 257,276 $243,290 $220,581
Long-term Debt(a) $ 365,782 $ 368,838 $ 341,051 $293,198 $292,525
Total Capitalization and
Liabilities $ 986,638 $ 921,847 $ 886,671 $833,579 $772,198
(a) Including portion due within one year.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS
OF RESULTS OF OPERATIONS
Kentucky Power 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
serving 171,000 retail customers in eastern Kentucky and does
business as American Electric Power (AEP). The Company as a member
of the AEP System Power Pool (AEP Power Pool) shares in 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.
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 AEP Power Pool revenues and costs.
The result of this calculation is the member load ratio (MLR) which
determines each Company's percentage share of AEP Power Pool
revenues or costs. Since the Company's MLR increased in 1999, the
AEP Power Pool is allocating a larger share of certain revenues and
expenses to the Company.
Net Income Increases
Net income increased $3.8 million or 17% in 1999 primarily as
a result of an increase in retail revenues and net rental revenues
for attachments to the Company's poles and a decrease in
maintenance expenses.
Operating Revenues Increase
Operating revenues increased $11 million or 3% due to
adjustments in 1999 of estimates for rental revenues for pole
attachments. Changes in the components of operating revenues were
as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Retail:
Residential $ 2.0 1.9
Commercial 2.5 4.2
Industrial 2.5 2.6
7.0 2.7
Wholesale (6.9) (7.9)
Transmission 0.4 4.5
Other 10.5 179.2
Total $11.0 3.0
Retail revenues increased due to increased fuel clause revenues
reflecting the recovery of previously deferred fuel costs. Under
the fuel clause recovery mechanism, changes in fuel costs are
deferred until reflected in billings to customers. As a result
these revenues do not affect earnings.
The decrease in wholesale revenues was due to a decline in
margins on the Company's MLR share of increased power marketing
sales and net energy trading transactions. Power marketing
revenues are for the sale of power at wholesale to unaffiliated
companies. The power is either generated by the AEP System or
purchased from other unaffiliated companies. Power trading
transactions involve the forward purchase and sale of substantial
amounts of electricity and are conducted by the AEP Power Pool.
Revenues from regulated trading activities are allocated to AEP
Power Pool members based on MLR and recorded net of purchases. The
decline in margins reflect the moderation in 1999 of extreme
weather in 1998 and capacity shortages experienced in the summer of
1998.
In 1999 other revenues increased substantially due to a
favorable adjustment to estimated rental income reflecting agreed
to revisions in the billings for pole attachments with
telecommunications companies. In the fourth quarter of 1999 the
Company completed an evaluation of existing pole attachments and
related billings which resulted in adjustments to recover net
revenues from telecommunications companies for their use of the
Company's poles.
Operating Expenses Increase
Operating expenses increased $8.2 million primarily due to
increased purchased power and other operation expenses partially
offset by a decline in maintenance costs. Changes in the
components of operating expenses were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Fuel $ 1.1 1.3
Purchased Power 7.1 7.1
Other Operation 4.7 9.8
Maintenance (9.0) (29.6)
Depreciation and Amortization 1.1 4.1
Taxes Other Than Federal
Income Taxes 1.2 12.0
Federal Income Taxes 2.0 18.2
Total $ 8.2 2.6
Purchased power expense increased mainly due an increase in
capacity charges from the AEP Power Pool reflecting an increase in
the Company's MLR.
The increase in other operation expense reflects the above
discussed adjustment in rental costs for the use of
telecommunication companies' poles.
Expenditures to repair storm damage and restore distribution
service after two severe snowstorms in 1998 and for an extended
maintenance outage at the Company's generating plant in 1998 and
cost control efforts including staff reductions in the Company's
power generation operations in 1999 accounted for the decline in
maintenance expense.
Federal income tax expense attributable to operations increased
primarily due to an increase in pre-tax operating income.
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
highest, lowest and average VaR in the wholesale electricity
trading portfolio was less than $1 million. Based on this VaR
analysis, at December 31, 1999 a near term change in electricity
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 26 years and an average duration
of three years at December 31, 1999. The Company measures interest
rate market risk exposure also 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 are 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 $25 million at December 31, 1999 and
$13 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 financial position
of the Company.
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of
Directors of Kentucky Power Company:
We have audited the accompanying balance sheets of Kentucky Power
Company as of December 31, 1999 and 1998, and the related
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 financial statements present fairly, in all
material respects, the financial position of Kentucky Power Company
as of December 31, 1999 and 1998, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1999 in conformity with generally accepted accounting
principles.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2000
(March 3, 2000 as to Note 6)
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
Year Ended December 31,
1999 1998 1997
(in thousands)
OPERATING REVENUES $373,982 $362,999 $340,635
OPERATING EXPENSES:
Fuel 84,369 83,303 77,051
Purchased Power 107,763 100,620 95,030
Other Operation 52,468 47,802 51,544
Maintenance 21,452 30,462 24,417
Depreciation and Amortization 29,221 28,080 26,474
Taxes Other Than Federal Income Taxes 10,854 9,687 9,397
Federal Income Taxes 13,180 11,152 9,866
TOTAL OPERATING EXPENSES 319,307 311,106 293,779
OPERATING INCOME 54,675 51,893 46,856
NONOPERATING LOSS (327) (1,726) (464)
INCOME BEFORE INTEREST CHARGES 54,348 50,167 46,392
INTEREST CHARGES 28,918 28,491 25,646
NET INCOME $ 25,430 $ 21,676 $ 20,746
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1999 1998 1997
(in thousands)
RETAINED EARNINGS JANUARY 1 $71,452 $78,076 $84,090
NET INCOME 25,430 21,676 20,746
CASH DIVIDENDS DECLARED 29,772 28,300 26,760
RETAINED EARNINGS DECEMBER 31 $67,110 $71,452 $78,076
See Notes to Financial Statements.
KENTUCKY POWER COMPANY
BALANCE SHEETS
December 31,
1999 1998
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 268,618 $ 267,201
Transmission 355,442 326,989
Distribution 372,752 351,407
General 67,608 68,038
Construction Work in Progress 14,628 30,076
Total Electric Utility Plant 1,079,048 1,043,711
Accumulated Depreciation and Amortization 340,008 315,546
NET ELECTRIC UTILITY PLANT 739,040 728,165
OTHER PROPERTY AND INVESTMENTS 20,416 12,078
CURRENT ASSETS:
Cash and Cash Equivalents 674 1,935
Accounts Receivable:
Customers 18,952 23,295
Affiliated Companies 15,223 8,797
Miscellaneous 8,343 4,019
Allowance for Uncollectible Accounts (637) (848)
Fuel - at average cost 10,441 7,888
Materials and Supplies - at average cost 18,113 13,652
Accrued Utility Revenues 13,737 13,560
Energy Marketing and Trading Contracts 33,919 4,726
Prepayments 1,450 1,657
TOTAL CURRENT ASSETS 120,215 78,681
REGULATORY ASSETS 96,296 92,447
DEFERRED CHARGES 10,671 10,476
TOTAL $ 986,638 $ 921,847
See Notes to Financial Statements.
KENTUCKY POWER COMPANY
December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $50:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $ 50,450
Paid-in Capital 158,750 148,750
Retained Earnings 67,110 71,452
Total Common Shareholder's Equity 276,310 270,652
Long-term Debt 260,782 308,838
TOTAL CAPITALIZATION 537,092 579,490
OTHER NONCURRENT LIABILITIES 23,797 26,827
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 105,000 60,000
Short-term Debt 39,665 20,350
Accounts Payable - General 9,923 12,917
Accounts Payable - Affiliated Companies 19,743 11,814
Customer Deposits 4,143 4,038
Taxes Accrued 9,860 7,256
Interest Accrued 4,843 6,241
Energy Marketing and Trading Contracts 33,094 5,089
Other 12,020 13,612
TOTAL CURRENT LIABILITIES 238,291 141,317
DEFERRED INCOME TAXES 165,007 158,706
DEFERRED INVESTMENT TAX CREDITS 12,908 14,200
DEFERRED CREDITS 9,543 1,307
COMMITMENTS AND CONTINGENCIES (Notes 4 and 6)
TOTAL $986,638 $921,847
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
Year Ended December 31,
1999 1998 1997
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 25,430 $ 21,676 $ 20,746
Adjustments for Noncash Items:
Depreciation and Amortization 29,228 28,092 26,486
Deferred Income Taxes 2,596 3,607 741
Deferred Investment Tax Credits (1,292) (1,415) (1,392)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (6,618) (6,663) (283)
Fuel, Materials and Supplies (7,014) 3,199 (2,320)
Accrued Utility Revenues (177) (579) (4,806)
Accounts Payable 4,935 157 (6,483)
Payment of Disputed Tax and Interest Related to COLI (567) (5,376) -
Other (net) 413 (1,538) 8,576
Net Cash Flows From Operating Activities 46,934 41,160 41,265
INVESTING ACTIVITIES:
Construction Expenditures (44,339) (43,769) (66,642)
Proceeds from Sales of Property 168 - -
Net Cash Flows Used For Investing Activities (44,171) (43,769) (66,642)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 10,000 20,000 20,000
Issuance of Long-term Debt 79,740 29,816 47,587
Retirement of Long-term Debt (83,307) (2,203) -
Change in Short-term Debt (net) 19,315 (16,150) (15,175)
Dividends Paid (29,772) (28,300) (26,760)
Net Cash Flows From (Used For)
Financing Activities (4,024) 3,163 25,652
Net Increase (Decrease) in Cash and Cash Equivalents (1,261) 554 275
Cash and Cash Equivalents January 1 1,935 1,381 1,106
Cash and Cash Equivalents December 31 $ 674 $ 1,935 $ 1,381
See Notes to Financial Statements.
NOTES TO FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Kentucky Power Company (the Company or KPCo) 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 serving 171,000 retail customers in eastern Kentucky
and does business as American Electric Power (AEP). Under the
terms of the AEP System Power Pool (AEP Power Pool) and the AEP
System Transmission Equalization Agreement, the Company's
generating 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.
Regulation
As a subsidiary of AEP Co., Inc., the Company is subject to
regulation by the Securities and Exchange Commission (SEC) under
the Public Utility Holding Company Act of 1935 (1935 Act). Retail
rates are regulated by the Kentucky Public Service Commission
(KPSC). The Federal Energy Regulatory Commission (FERC) regulates
the Company's wholesale and transmission rates.
Basis of Accounting
As a cost-based rate-regulated entity, the Company's 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 and Amortization
Depreciation of electric utility plant is provided on a
straight-line basis over the estimated useful lives of property and
is calculated largely through the use of composite rates by
functional class. The annual composite depreciation rates for
1999, 1998 and 1997 were as follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production 3.8%
Transmission 1.7%
Distribution 3.5%
General 2.5%
Amounts for demolition and removal of plant are recovered
through depreciation charges included in rates.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments
with original maturities of three months or less.
Operating Revenues and Fuel Cost
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 in later months
through a fuel cost recovery mechanism. Wholesale fuel cost
changes are expensed and billed as incurred.
Energy Marketing and Trading Transactions
The AEP Power Pool implements and administers 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 represents physical forward electricity
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'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
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 cost of service on a settlement basis for rate-making
purposes. The Company's share of non-regulated open trading
contracts are accounted for on a mark-to-market basis in
non-operating income. 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 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 8 - 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 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 regulated plant investment.
Debt
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.
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. EFFECTS OF REGULATION:
In accordance with SFAS 71 the 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.
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 $88,764 $85,058
Other 7,532 7,389
Total Regulatory Assets $96,296 $92,447
Regulatory Liabilities -
Deferred Investment Tax Credits $12,908 $14,200
3. RATE MATTERS:
Transmission
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 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.
Retail
In December 1997, AEP Co., Inc. and Central and South West
Corporation announced their plan to merge. In compliance with a
request from the staff of the KPSC, AEP Co., Inc. filed in April
1999 an application seeking KPSC approval for the indirect change
in control of KPCo that will occur as a result of the proposed
merger. Although AEP Co., Inc. did not believe that the KPSC has
the jurisdictional authority to approve the merger, AEP Co., Inc.
reached a merger settlement agreement on May 24, 1999 with key
parties in Kentucky which the KPSC approved on June 14, 1999.
Under the terms of the Kentucky settlement, AEP Co., Inc. has
agreed to share net merger savings with Kentucky customers for
eight years; establish performance standards that will maintain or
improve customer service and system reliability; and to establish
rules to protect consumers and promote fair competition. The
Kentucky customers' share of the net merger savings are expected to
be approximately $28 million over eight years. The key parties to
the Kentucky settlement agreed not to oppose the merger in the FERC
or the SEC proceedings.
4. 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 $103
million for 2000-2002.
Long-term fuel supply contracts generally contain clauses that
provide for periodic price adjustments. The contracts are for
various terms, the longest of which extends to the year 2004 and
contain various clauses that would release the Company from its
obligation under certain force majeure conditions. A KPSC fuel
adjustment mechanism generally provides for recovery of changes in
the cost of fuel.
A constructive marketing program discontinued in 1997 enabled
residential customers to borrow from area banks to purchase energy
efficient electrical equipment, such as heat pumps. KPCo
guarantees the loan principal plus interest. The guaranteed
amounts totaled $5 million at December 31, 1999.
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 the U.S. Environmental Protection Agency (Federal EPA), filed a
complaint in the U.S. District Court for the Southern District of
Ohio that alleges certain AEP System companies made modifications
to generating units at certain of their 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 certain 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 AEP System companies under the Clean Air Act. On November
18, 1999 a number of environmental groups filed a lawsuit against
power plants owned by AEP System companies 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 AEP System 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
energy.
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 1992-1996. A disallowance of the COLI interest
deductions through December 31, 1999 would reduce earnings by
approximately $8 million (including interest).
The Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1992-1998 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are
included on the Balance Sheets in other property and investments
pending the resolution of this matter. The Company is seeking
refunds of all amounts paid plus interest.
In order to resolve this issue, AEP Co., Inc. 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 deductions 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 and cash flows.
The Company is involved in a number of other legal proceedings
and claims. While management is unable to predict the ultimate
outcome of litigation, it is not expected that the resolution of
these matters will have a material adverse effect on the results of
operations, cash flows or financial condition.
5. RELATED-PARTY TRANSACTIONS:
KPCo has a Unit Power Purchase Agreement with AEP Generating
Company (AEGCo) an affiliated company, which expires in 2004. The
agreement provides for the Company to purchase 15% of the total
output of the two unit 2,600-mw capacity Rockport Plant. Under the
Unit Power Purchase Agreement there is a demand charge for the
right to receive the power, which is payable even if the power is
not taken. The amount of the demand charge is such that when added
to other amounts received by AEGCo, it will enable AEGCo to recover
all its fixed expenses including a FERC-approved rate of return on
common equity.
Demand charges payable even if the power is not taken
and energy purchases under the Unit Power Purchase Agreement were
included in purchased power expense as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Demand Charge $37,008 $38,108 $39,993
Energy Charge 27,490 29,183 28,393
Total $64,498 $67,291 $68,386
Benefits and costs of the AEP System's generating plants are
shared by the Company and the other affiliated members of the AEP
Power Pool. Under the terms of the System Interconnection
Agreement, capacity charges and credits are designed to allocate
the cost of the System's generating reserves 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.
Operating revenues include $43.2 million in 1999, $43.5 million
in 1998 and $41.0 million in 1997 for energy supplied to the Power
Pool.
Since the allocation of the AEP System's capacity to the
Company, which is based on the ratio of its peak demand to the
total peak demand of all AEP Power Pool members, exceeds its
generating capacity, the Company incurs charges for capacity
reservation. Such capacity charges are for the right to receive
power from the AEP Power Pool even if the power is not taken. The
charges for capacity and for energy received from the AEP Power
Pool are included in purchased power expense as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Capacity Charge $ 8,763 $1,169 $ 7,196
Energy Charge 10,739 8,504 13,855
Total $19,502 $9,673 $21,051
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 $27,938 $29,237 $26,965
Purchased Power Expense 23,763 23,656 5,596
Nonoperating Income (Loss) 650 (2,419) (22)
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 of those facilities 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 greater than its relative peak demand, other
operation expense includes equalization credits of $4.3 million,
$6.0 million and $2.7 million in 1999, 1998 and 1997, respectively.
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
expensed or capitalized depending on the nature of the services
rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
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 and its
AEP System affiliates' generating plants are located. A number of
utilities, including the Company and its AEP System affiliates, 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 Section
126 of the Clean Air Act. Federal EPA approved portions of the
states' petitions that would impose 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 portions of the northeastern states'
petitions. In 1999, three additional northeastern states and the
District of Columbia filed Section 126 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 and its AEP System affiliates, 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 $106 million for the Company. Since
compliance costs cannot be estimated with certainty the actual
costs incurred to comply could be significantly different from this
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates, transition
charges and/or reflected in the future market price of electricity,
they will have an adverse effect on future results of operations,
cash flows and possibly financial condition.
7. SEGMENT INFORMATION:
Effective December 31, 1998, the Company adopted SFAS 131,
"Disclosure about Segments of an Enterprise and Related
Information." The Company has one reportable segment, a regulated
vertically integrated electricity generation and energy delivery
business. 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. 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.
8. 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 $2 million and $7 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
nonoperating 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 years ended December 31,
1999 and 1998 was $1 million and $(2) 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 Statements of
Income of marking open regulated 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 including forward purchase
contracts 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 fixed interest
rates with terms from one day to 26 years and an average duration
of three 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 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 tables. The fair values of long-term
debt are based on quoted market prices for the same or similar
issues and the current interest rates offered for instruments of
the same remaining maturities. The fair value of those financial
instruments that are marked-to-market are based on management's
best estimates using over-the-counter quotations, exchange prices,
volatility factors and valuation methodology. The estimates
presented herein are not necessarily indicative of the amounts that
the Company could realize in a current market exchange.
Book Value Fair Value
(in thousands)
Non-Derivatives
Long-term Debt
1999 $365,782 $359,100
1998 $368,838 $387,500
Derivatives
1999 1998
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
(Dollars in thousands)
Trading Assets
GWH GWH
Electric
NYMEX Futures
and Options 15 $ 114 $ 49 - $ - $ -
Physicals 4,707 39,074 35,477 3,717 2,900 2,600
Options 420 2,773 4,353 246 2,100 5,000
Swaps 12 26 21 18 200 100
Trading Liabilities
GWH GWH
Electric
NYMEX Futures
and Options - $ - $ - 45 $ (400) $ (100)
Physicals 5,063 (36,422) (34,180) 3,662 (3,100) (2,900)
Options 603 (2,900) (3,949) 186 (1,900) (5,600)
Swaps 12 (24) (20) 31 (500) (100)
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.
9. 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 36 power generation and energy delivery positions
were identified for elimination.
Severance accruals totaling $1.9 million were recorded by the
Company in December 1998 for reductions in power generation and
energy delivery staffs and were charged to other operation expense
in the 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.
10. BENEFIT PLANS:
The Company participates in the AEP System qualified pension
plan, a defined benefit plan which covers all employees. Net
pension costs (credits) for the years ended December 31, 1999, 1998
and 1997 were $(393,000), $322,000 and $424,000, respectively.
Postretirement benefits other than pensions are provided for
retired employees for medical and death benefits under an AEP
System plan. The annual accrued costs were $2.7 million in 1999,
$2.1 million in 1998 and $2.1 million in 1997.
A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $561,000 in 1999,
$714,000 in 1998 and $714,000 in 1997.
11. 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 $12,134 $ 8,387 $10,425
Deferred 2,239 3,967 660
Deferred Investment Tax Credits (1,193) (1,202) (1,219)
Total 13,180 11,152 9,866
Charged (Credited) to Nonoperating
Income (net):
Current (445) (794) (359)
Deferred 357 (360) 81
Deferred Investment Tax Credits (99) (213) (173)
Total (187) (1,367) (451)
Total Federal Income Taxes as Reported $12,993 $ 9,785 $ 9,415
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 $25,430 $21,676 $20,746
Federal Income Taxes 12,993 9,785 9,415
Pre-tax Book Income $38,423 $31,461 $30,161
Federal Income Taxes on Pre-tax Book
Income at Statutory Rate (35%) $13,448 $11,011 $10,556
Increase (Decrease) in Federal Income
Taxes Resulting From the Following Items:
Depreciation 1,843 1,633 1,850
Removal Costs (420) (840) (840)
Investment Tax Credits (net) (1,292) (1,415) (1,392)
Other (586) (604) (759)
Total Federal Income Taxes as Reported $12,993 $ 9,785 $ 9,415
Effective Federal Income Tax Rate 33.8% 31.1% 31.2%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
it:
December 31,
1999 1998
(in thousands)
Deferred Tax Assets $ 32,186 $ 31,453
Deferred Tax Liabilities (197,193) (190,159)
Net Deferred Tax Liabilities $(165,007) $(158,706)
Property Related Temporary
Differences $(114,903) $(112,246)
Amounts Due From Customers For
Future Federal Income Taxes (19,616) (18,759)
Deferred State Income Taxes (32,715) (31,460)
Other (net) 2,227 3,759
Net Deferred Tax Liabilities $(165,007) $(158,706)
KPCo joins in the filing of a consolidated federal income tax
return with its 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 4,
management is not aware of any issues for open tax years that upon
final resolution are expected to have a material adverse effect on
results of operations.
12. COMMON SHAREHOLDER'S EQUITY:
The Company received from AEP Co., Inc. cash capital
contributions of $10 million in 1999, $20 million in 1998 and $20
million in 1997 which were credited to paid-in capital. There were
no other transactions affecting common stock and paid-in capital
accounts in 1999, 1998 and 1997.
13. 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 $119,270 $177,313
Senior Unsecured Notes 157,502 77,553
Notes Payable 50,000 75,000
Junior Debentures 39,010 38,972
365,782 368,838
Less Portion Due Within One Year 105,000 60,000
Total $260,782 $308,838
First Mortgage Bonds outstanding were as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
7.20 1999 - December 1 $ - $ 35,000
8.95 2001 - May 10 20,000 20,000
8.90 2001 - May 21 40,000 40,000
6.65 2003 - May 1 15,000 15,000
6.70 2003 - June 1 15,000 15,000
6.70 2003 - June 1 15,000 15,000
7.90 2023 - June 1 - 12,797
7.90 2023 - June 1 14,500 25,000
Unamortized Discount (230) (484)
Total $119,270 $177,313
Certain first mortgage bond indentures contain maintenance and
replacement provisions requiring the deposit of cash or bonds with
a trustee or, in lieu thereof, certification of unfunded property
additions.
Senior Unsecured Notes are composed of the following:
December 31,
1999 1998
(in thousands)
% Rate Due
Variable (a) 2000 - November 2 $ 80,000 $ -
6.91 2007 - October 1 48,000 48,000
6.45 2008 - November 10 30,000 30,000
Unamortized Discount (498) (447)
Total $157,502 $77,553
(a) Rate adjusted monthly based on specified short-term interest
rates. Rate was 7.23% at December 31, 1999.
Notes Payable to Banks are composed of the following:
December 31,
1999 1998
(in thousands)
% Rate Due
6.42 1999 - April 1 $ - $25,000
6.57 2000 - April 1 25,000 25,000
7.445 2002 - September 20 25,000 25,000
Total $50,000 $75,000
Junior debentures are composed of the following:
December 31,
1999 1998
(in thousands)
% Rate Due
8.72 2025 - June 30 $40,000 $40,000
Unamortized Discount (990) (1,028)
Total $39,010 $38,972
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.
At December 31, 1999, annual long-term debt payments are as
follows:
Amount
(in thousands)
2000 $105,000
2001 60,000
2002 25,000
2003 45,000
2004 -
Later Years 132,500
Total Principal Amount 367,500
Unamortized Discount (1,718)
Total $365,782
Short-term debt borrowings are limited by provisions of the
1935 Act to $150 million. Lines of credit are shared with 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 lines of credit require the 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:
Commercial Paper $39,665 6.2%
December 31, 1998:
Notes Payable $ 4,850 6.4%
Commercial Paper 15,500 6.0%
Total $20,350 6.1%
14. 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 $ 199 $ 931 $ 369
Amortization of Capital Leases 4,299 4,265 3,541
Interest on Capital Leases 1,162 1,173 1,548
Total Lease Rental Costs $5,660 $6,369 $5,458
Properties under capital leases and related obligations
recorded on the Balance Sheets are as follows:
December 31,
1999 1998
(in thousands)
Electric Utility Plant Under Capital Leases:
Production Plant $ 2,022 $ 2,022
General Plant 24,225 26,741
Total Electric Utility Plant
Under Capital Leases 26,247 28,763
Accumulated Amortization 11,106 9,786
Net Electric Utility Plant
Under Capital Leases $15,141 $18,977
Capital Lease Obligations:*
Noncurrent Liability $11,830 $14,957
Liability Due Within One Year 3,311 4,020
Total Capital Lease Obligations $15,141 $18,977
*Represents the present value of future minimum lease payments.
Capital lease obligations are included in other noncurrent and
other current liabilities on the Balance Sheets. Properties under
operating leases and related obligations are not included in the
Balance Sheets.
Future minimum lease payments consisted of the following at
December 31, 1999:
Non-cancelable
Capital Operating
Leases Leases
(in thousands)
2000 $ 4,198 $104
2001 3,521 29
2002 3,087 26
2003 2,267 23
2004 1,635 22
Later Years 3,446 252
Total Future Minimum Lease Payments 18,154 $456
Less Estimated Interest Element 3,013
Estimated Present Value of
Future Minimum Lease Payments $15,141
15. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1999 1998 1997
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $29,845 $27,857 $24,490
Income Taxes 12,050 8,607 11,359
Noncash Acquisitions under
Capital Leases 2,219 4,890 8,653
16. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1999
March 31 $ 90,741 $15,360 $8,209
June 30 86,231 10,233 2,995
September 30 94,939 14,244 7,197
December 31 102,071 14,838 7,029
1998
March 31 $ 87,345 $12,091 $5,017
June 30 84,021 9,631 2,413
September 30 104,922 16,551 8,442
December 31 86,711 13,620 5,804