KENTUCKY POWER COMPANY
SELECTED FINANCIAL DATA
Year Ended December 31,
1998 1997 1996 1995 1994
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $362,999 $340,635 $323,321 $328,144 $307,443
Operating Expenses 311,106 293,779 281,978 279,123 261,354
Operating Income 51,893 46,856 41,343 49,021 46,089
Nonoperating Income (Loss) (1,726) (464) (594) 3 (102)
Income Before Interest Charges 50,167 46,392 40,749 49,024 45,987
Interest Charges 28,491 25,646 23,776 23,896 20,714
Net Income $ 21,676 $ 20,746 $ 16,973 $ 25,128 $ 25,273
December 31,
1998 1997 1996 1995 1994
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,043,711 $1,006,955 $951,602 $879,657 $851,912
Accumulated Depreciation
and Amortization 315,546 296,318 286,640 270,590 259,984
Net Electric Utility Plant $ 728,165 $ 710,637 $664,962 $609,067 $591,928
Total Assets $ 921,847 $ 886,671 $833,579 $772,198 $739,795
Common Stock and
Paid-in Capital $ 199,200 $ 179,200 $159,200 $129,200 $119,200
Retained Earnings 71,452 78,076 84,090 91,381 89,173
Total Common Shareholder's
Equity $ 270,652 $ 257,276 $243,290 $220,581 $208,373
Long-term Debt(a) $ 368,838 $ 341,051 $293,198 $292,525 $253,583
Total Capitalization and
Liabilities $ 921,847 $ 886,671 $833,579 $772,198 $739,795
(a) Including portion due within one year.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS
OF RESULTS OF OPERATIONS
Net Income Increases
Net income for 1998 increased $0.9 million or 4% largely as a
result of growth in wholesale power marketing, trading and
transmission service revenues.
Operating Revenues Increase
Operating revenues increased $22.4 million or 7% due to
increased revenues from wholesale sales and transmission services.
The increase in operating revenues is as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Retail:
Residential $(1.2)
Commercial 1.4
Industrial (0.4)
(0.2) (0.1)
Wholesale 17.0 24.1
Transmission 3.9 65.7
Other 1.7 41.1
Total $22.4 6.6
The Company as part of the American Electric Power (AEP) System
shares the benefits and costs of the System's generating facilities
through the AEP System Power Pool (AEP Power Pool). The cost of
the 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 the
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 each Company's member load ratio (MLR). MLR
determines each Company's percentage share of AEP Power Pool
revenues and costs. During 1998 the Company's MLR decreased
resulting in the Company being allocated a smaller share of
wholesale revenues and expenses from the AEP Power Pool.
In 1997 management decided to develop a power marketing and
trading business. The power marketing and trading business is
conducted by the AEP Power Pool and its revenues and expenses are
allocated to AEP Power Pool members based on MLR. During 1998 the
trading and marketing volume grew substantially by reflecting
management's decision to grow the marketing and trading business.
Trading revenues are recorded net of purchases.
The increase in wholesale revenues was due to increased sales
of energy to the AEP Power Pool and the Company's share of
increased power marketing and net trading revenues. Sales to the
AEP Power Pool rose due to the unavailability to the AEP Power Pool
of an affiliate's nuclear plant which is on an extended outage.
Power marketing revenues are from the sale of power at wholesale to
unaffiliated companies. The power is either generated by the AEP
Power Pool or purchased from other unaffiliated companies.
Transmission service revenues increased due to a substantial
rise in the volume of energy transmitted for other entities over
the AEP System's transmission lines. The issuance of open access
transmission rules by the Federal Energy Regulatory Commission
facilitated the growth in transmission services. The Company
receives its MLR share of the AEP System transmission revenues.
Operating Expenses Increase
Operating expenses increased $17.3 million or 6% primarily due
to increased fuel, purchased power and maintenance expenses.
Changes in the components of operating expenses were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Fuel $ 6.2 8.1
Purchased Power 5.6 5.9
Other Operation (3.7) (7.3)
Maintenance 6.0 24.8
Depreciation and Amortization 1.6 6.1
Taxes Other Than Federal Income Taxes 0.3 3.1
Federal Income Taxes 1.3 13.0
Total $17.3 5.9
The increase in fuel expense reflects increased generation to
meet the increase in demand and an increase in the average cost of
fuel consumed.
Purchased power expense increased mainly due to the Company's
share of purchases of electricity by the AEP Power Pool for resale
to other utilities and power marketers. The increase was partially
offset by reduced energy and capacity charges from the Power Pool
reflecting the unavailability of nuclear generation and a decrease
in MLR, respectively.
The decrease in other operation expense reflects an increase in
transmission credits received under the AEP System Transmission
Equalization Agreement. The 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. Although MLR declined,
the Company's additional investment in transmission plant relative
to the investment of the other AEP System companies resulted in the
increase in Transmission Equalization Agreement credits.
Expenditures to repair storm damage and to restore distribution
service after two severe snowstorms accounted for the increase in
maintenance expense.
The increase in depreciation and amortization expense reflects
additional investment in depreciable plant to make improvements to
the Company's transmission and distribution system.
Federal income tax expense attributable to operations increased
primarily due to an increase in pre-tax operating income.
The decline in nonoperating income is due to losses from
non-regulated electricity trading activities. These trading activities
are for forward electricity sales and purchases outside of the AEP
Power Pool's traditional marketing area and also include other
electricity derivative transactions such as options, swaps, etc.
Open non-regulated trades are marked-to-market and recorded in
nonoperating income.
Interest charges rose $2.8 million or 11% due to increased
outstanding balances of long-term debt reflecting the issuance of
notes payable in November 1998 and October 1997.
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 Power Pool
exposes the Company to market price risk. Market risk represents
the risk of loss that may impact the Company due to adverse changes
in electricity commodity market prices and rates. In 1998 the
Power Pool substantially increased the volume of its wholesale
power marketing and trading activities. Various policies and
procedures have been established to manage market risk exposures
including the use of a risk measurement model utilizing Value at
Risk (VaR). Throughout the year ending December 31, 1998, the
Company's share of the highest, lowest and average quarterly VaR in
the wholesale trading portfolio was less than $1 million at a 95%
confidence level with a holding period of three business days. The
AEP Power Pool uses the variance-covariance method for calculating
VaR based on three months of daily prices. Based on this VaR
analysis, at December 31, 1998 a near term change in 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 risk resulting from 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 twenty-six
years and an average duration of three years at December 31, 1998.
The Company measures interest rate market risk exposure also
utilizing a VaR model. The model is based on the Monte Carlo
method of simulated price movements with a 95% confidence level and
a one year holding period. The volatilities and correlations are
based on three years of monthly prices. The risk of potential loss
in fair value attributable to the Company's exposure to interest
rates, primarily related to long-term debt with fixed interest
rates, was $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. Also, since the Company's rates are cost-based
regulated, the risk of interest rate changes on debt used to
finance regulated operations is mitigated.
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, 1998 and 1997, and the related
statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 1998. These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of Kentucky Power Company
as of December 31, 1998 and 1997, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted accounting
principles.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 23, 1999
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
Year Ended December 31,
1998 1997 1996
(in thousands)
OPERATING REVENUES $362,999 $340,635 $323,321
OPERATING EXPENSES:
Fuel 83,303 77,051 67,697
Purchased Power 100,620 95,030 96,485
Other Operation 47,802 51,544 46,347
Maintenance 30,462 24,417 32,793
Depreciation and Amortization 28,080 26,474 25,123
Taxes Other Than Federal Income Taxes 9,687 9,397 7,790
Federal Income Taxes 11,152 9,866 5,743
TOTAL OPERATING EXPENSES 311,106 293,779 281,978
OPERATING INCOME 51,893 46,856 41,343
NONOPERATING LOSS (1,726) (464) (594)
INCOME BEFORE INTEREST CHARGES 50,167 46,392 40,749
INTEREST CHARGES 28,491 25,646 23,776
NET INCOME $ 21,676 $ 20,746 $ 16,973
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1998 1997 1996
(in thousands)
RETAINED EARNINGS JANUARY 1 $78,076 $84,090 $91,381
NET INCOME 21,676 20,746 16,973
CASH DIVIDENDS DECLARED 28,300 26,760 24,264
RETAINED EARNINGS DECEMBER 31 $71,452 $78,076 $84,090
See Notes to Financial Statements.
KENTUCKY POWER COMPANY
BALANCE SHEETS
December 31,
1998 1997
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 260,423 $ 249,184
Transmission 326,904 303,456
Distribution 351,407 350,793
General 74,901 71,462
Construction Work in Progress 30,076 32,060
Total Electric Utility Plant 1,043,711 1,006,955
Accumulated Depreciation and Amortization 315,546 296,318
NET ELECTRIC UTILITY PLANT 728,165 710,637
OTHER PROPERTY AND INVESTMENTS 12,078 6,591
CURRENT ASSETS:
Cash and Cash Equivalents 1,935 1,381
Accounts Receivable:
Customers 23,295 24,127
Affiliated Companies 8,797 1,722
Miscellaneous 4,019 3,276
Allowance for Uncollectible Accounts (848) (525)
Fuel - at average cost 7,888 10,685
Materials and Supplies - at average cost 13,652 14,054
Accrued Utility Revenues 13,560 12,981
Energy Marketing and Trading Contracts 4,726 -
Prepayments 1,657 1,538
TOTAL CURRENT ASSETS 78,681 69,239
REGULATORY ASSETS 92,447 90,045
DEFERRED CHARGES 10,476 10,159
TOTAL $ 921,847 $ 886,671
See Notes to Financial Statements.
KENTUCKY POWER COMPANY
December 31,
1998 1997
(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 148,750 128,750
Retained Earnings 71,452 78,076
Total Common Shareholder's Equity 270,652 257,276
Long-term Debt 308,838 341,051
TOTAL CAPITALIZATION 579,490 598,327
OTHER NONCURRENT LIABILITIES 26,827 26,693
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 60,000 -
Short-term Debt 20,350 36,500
Accounts Payable - General 12,917 13,842
Accounts Payable - Affiliated Companies 11,814 10,732
Customer Deposits 4,038 3,660
Taxes Accrued 7,256 6,130
Interest Accrued 6,241 6,015
Energy Marketing and Trading Contracts 5,089 -
Other 13,612 14,935
TOTAL CURRENT LIABILITIES 141,317 91,814
DEFERRED INCOME TAXES 158,706 153,945
DEFERRED INVESTMENT TAX CREDITS 14,200 15,615
DEFERRED CREDITS 1,307 277
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $921,847 $886,671
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
Year Ended December 31,
1998 1997 1996
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 21,676 $ 20,746 $ 16,973
Adjustments for Noncash Items:
Depreciation and Amortization 28,092 26,486 25,196
Deferred Income Taxes 3,607 741 1,864
Deferred Investment Tax Credits (1,415) (1,392) (1,390)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (6,663) (283) 1,596
Fuel, Materials and Supplies 3,199 (2,320) (6,412)
Accrued Utility Revenues (579) (4,806) 5,325
Accounts Payable 157 (6,483) 9,291
Payment of Disputed Tax and Interest Related to COLI (5,376) - -
Other (net) (1,538) 8,576 (7,410)
Net Cash Flows From Operating Activities 41,160 41,265 45,033
INVESTING ACTIVITIES:
Construction Expenditures (43,769) (66,642) (75,816)
Proceeds from Sales of Property - - 250
Net Cash Flows Used For Investing Activities (43,769) (66,642) (75,566)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 20,000 20,000 30,000
Issuance of Long-term Debt 29,816 47,587 74,985
Retirement of Long-term Debt (2,203) - (74,738)
Change in Short-term Debt (net) (16,150) (15,175) 24,625
Dividends Paid (28,300) (26,760) (24,264)
Net Cash Flows From Financing Activities 3,163 25,652 30,608
Net Increase in Cash and Cash Equivalents 554 275 75
Cash and Cash Equivalents January 1 1,381 1,106 1,031
Cash and Cash Equivalents December 31 $ 1,935 $ 1,381 $ 1,106
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. KPCo is engaged in the
generation, purchase, sale, transmission and distribution of
electric power serving 170,000 retail customers in eastern Kentucky
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 Power Pool wholesale
sales to neighboring utility systems and power marketers. The
Company also sells wholesale power to municipalities. As a member
of the AEP Power Pool and a signatory company to the American
Electric Power System (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.
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 rates.
Basis of Accounting
As a cost-based rate-regulated entity, KPCo's financial
statements reflect the actions of regulators that may 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 1998, 1997 and 1996 were not significant.
Depreciation and Amortization
Depreciation 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 1998, 1997 and 1996 were as
follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production 3.8%
Transmission 1.7%
Distribution 3.5%
General 2.5%
Expenditures for the demolition and removal of plant are
charged to the accumulated provision for depreciation and 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 the accrual of electricity consumed but
unbilled at month-end as well as billed revenues. Changes in
retail jurisdictional fuel costs are deferred until reflected in
billings to customers in later months through a fuel cost recovery
mechanism. Wholesale jurisdictional fuel cost changes are expensed
and billed as incurred.
Derivative Financial Instruments
During 1998, the AEP Power Pool substantially increased the
volume of its 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 and over-the-counter
options and swaps. The majority of these transactions represent
physical forward contracts in the AEP System's traditional
marketing area and are typically settled by entering into
offsetting contracts. The net revenues from these transactions 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. These non-regulated trading
activities are included in nonoperating income and accounted for on
a mark-to-market basis. The unrealized mark-to-market gains and
losses from such non-regulated trading activity are reported as
assets and liabilities, respectively.
The Company enters into forward 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). Any resultant gains or losses are deferred and
amortized over the life of the debt issuance. There were no such
forward contracts outstanding at December 31, 1998 or 1997.
See Note 6 - Financial Instruments, Credit and Risk Management
for further discussion.
Reclassification
In the fourth quarter of 1998 the Company changed the
presentation of its trading activities from a gross basis
(purchases and sales reported separately) to a net basis (purchases
and sales are reported on a net basis as revenues). This
reclassification had no impact on net income. 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, deferred income taxes
are recorded with related regulatory assets and liabilities in
accordance with SFAS 71.
Investment Tax Credits
Investment tax credits have been accounted for under the flow-through
method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral
basis. Investment tax credits that have been deferred are being
amortized over the life of regulated plant investment.
Debt
Gains and losses on reacquisition of debt are deferred and
amortized over the remaining term of the reacquired debt in
accordance with rate-making treatment. If debt is refinanced,
reacquisition costs are deferred and amortized over the term of the
replacement debt commensurate with their recovery in rates.
Debt discount or premium and expenses of debt issuance are
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 the resultant 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 it
continues to meet the requirements to apply SFAS 71. In the event
a portion of the Company's business were to no longer meet 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,
1998 1997
(in thousands)
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $85,058 $83,904
Other 7,389 6,141
Total Regulatory Assets $92,447 $90,045
Regulatory Liabilities -
Deferred Investment Tax Credits $14,200 $15,615
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made to support
the Company's utility operations. Such commitments do not include
any expenditures for new generating capacity. Construction
expenditures for 1999-2001 are estimated to be $112 million.
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 2001 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 enables 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 $7 million at
December 31, 1998.
Clean Air Act/Air Quality
The US Environmental Protection Agency (Federal EPA) is
required by the Clean Air Act Amendments of 1990 (CAAA) to issue
rules to implement the law. In 1996 Federal EPA issued final rules
governing nitrogen oxides (NOx) emissions that must be met after
January 1, 2000 (Phase II of CAAA). The final rules will require
substantial reductions in NOx emissions from certain types of
boilers including those in the AEP System's power plants and the
Company's power plant. To comply with Phase II of CAAA, the
Company installed NOx emission control equipment at a capital cost
of $14 million.
On September 24, 1998, Federal EPA finalized rules which
require reductions in NOx emissions in 22 eastern states, including
Kentucky where the Company's generating plant is located. The
implementation of the final rules would be achieved through the
revision of state implementation plans (SIPs) by September 1999.
SIPs are a procedural method used by each state to comply with
Federal EPA rules. The final rules anticipate the imposition of a
NOx reduction on utility sources of approximately 85% below 1990
emission levels by the year 2003. On October 30, 1998, a number of
utilities, including the Company and the other operating companies
of the AEP System, filed petitions in the US Court of Appeals for
the District of Columbia Circuit seeking a review of the final
rules.
Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions. Federal EPA also proposed the
approval of portions of petitions filed by eight northeastern
states that would result in imposition of NOx emission reductions
on utility and industrial sources in upwind midwestern states.
These reductions are substantially the same as those required by
the final NOx rules and could be adopted by Federal EPA in the
event the states fail to implement SIPs in accordance with the
final rules.
Preliminary estimates indicate that compliance could result in
required capital expenditures of approximately $105 million.
Compliance costs cannot be estimated with certainty and the actual
costs incurred to comply could be significantly different from this
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers, they would have a material adverse
effect on results of operations, cash flows and possibly financial
condition.
Litigation
The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns for the years 1991
to 1993 requested a ruling from their National Office that certain
interest deductions claimed by the Company relating to AEP's
corporate owned life insurance (COLI) program should not be
allowed. As a result of a suit filed by the Company in US District
Court (discussed below) this request for ruling was withdrawn by
the IRS agents. Adjustments have been or will be proposed by the
IRS disallowing COLI interest deductions for taxable years 1992-96.
A disallowance of the COLI interest deductions through December 31,
1998 would reduce earnings by approximately $8 million (including
interest). The Company has made no provision for any possible
adverse earnings impact from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1992-97
to avoid the potential assessment by the IRS of any additional
above market rate interest on the contested amount. These payments
to the IRS are included on the balance sheet in other property and
investments pending the resolution of this matter. The Company
will seek refund, either administratively or through litigation, of
all amounts paid plus interest. In order to resolve this issue
without further delay, on March 24, 1998, the Company filed suit
against the US in the US District Court for the Southern District
of Ohio. Management believes that it has a meritorious position
and will vigorously pursue this lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
The Company is involved in a number of other legal proceedings
and claims. While management is unable to predict the 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.
4. 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 Generating 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,
1998 1997 1996
(in thousands)
Demand Charge $38,108 $39,993 $39,622
Energy Charge 29,183 28,393 27,743
Total $67,291 $68,386 $67,365
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 $43.5 million in 1998, $41.0 million
in 1997 and $28.0 million in 1996 for energy supplied to the Power
Pool.
Since the Company's internal peak demand exceeds its generating
capacity, charges for capacity reservation, which is a charge for
the right to receive power from the power pool even if the power is
not taken, and charges for energy received from the Power Pool were
included in purchased power expense as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Capacity Charge $1,169 $ 7,196 $ 6,425
Energy Charge 8,504 13,855 19,741
Total $9,673 $21,051 $26,166
Power marketing and trading operations, which are described in
Note 1, are conducted by the AEP Power Pool and shared with the
Company. The Company's operating revenues, purchased power expense
and nonoperating income includes amounts for power marketing and
trading allocated by the AEP Power Pool as follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Operating Revenues $29,237 $26,965 $26,665
Purchased Power Expense 23,656 5,596 2,956
Nonoperating Loss (2,419) (22) -
AEP System electric operating utility companies participate in
the AEP Transmission Equalization Agreement. 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 $6.0 million, $2.7 million and $3.3 million in 1998, 1997 and
1996, 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 clients 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.
5. 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. 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, 1998, 1997
and 1996, all of the Company's revenues are derived from the
generation, sale and delivery of electricity in the US.
6. 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
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, 1998 was $7 million.
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 marked to market and recorded in
nonoperating income. The Company's share of the net losses from
these non-regulated trading transactions for the year ended
December 31, 1998 was $2 million. The unrealized mark-to-market
gains and losses from such trading of financial instruments are
reported as assets and liabilities, respectively. These activities
were not material in prior periods.
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 twenty six years and an average
duration of three years at December 31, 1998. 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. Also since the Company's rates are cost-based regulated,
the risk of interest rate changes on debt used to finance regulated
operations is mitigated.
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, 1998 and 1997 are
summarized in the following table. 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. At
December 31, 1997 the notional amounts and fair values of
derivatives were not material.
Book Value Fair Value
(in thousands)
Non-Derivatives
1998
Long-term Debt $368,838 $387,500
1997
Long-term Debt $341,051 $358,500
Derivatives
1998
Fair Value Average Fair Value
(in thousands)
Trading Assets
Electric
Physicals $2,900 $2,600
Options 2,100 5,000
Swaps 200 100
Trading Liabilities
Electric
Futures (400) (100)
Physicals (3,100) (2,900)
Options (1,900) (5,600)
Swaps (500) (100)
At December 31, 1998 the notional amounts of the Company's
nonregulated electric trading physical forward contract purchases
and sales are 640 Gigawatt hours (Gwh) and 685 Gwh, respectively;
the notional amounts for fixed priced swaps purchases and sales are
23 Gwh and 25 Gwh, respectively; and the notional amounts for
options to purchase and to sell are 463 Gwh and 332 Gwh,
respectively. The Company has a net long position of 25 Gwh for
electric future contracts.
At December 31, 1998 the fair value of the assets and liabilities
related to the wholesale electric forward contracts was $23 million
and $23 million, respectively. The related notional amounts were
3,046 Gwh for purchases and 3,109 Gwh for sales. The average fair
value amounts outstanding during the period were $59 million of
assets and $56.0 million of liabilities.
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.
7. 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.
8. BENEFIT PLANS:
The Company participates in the AEP System qualified pension
plan, a defined benefit plan which covers all employees. Net
pension costs for the years ended December 31, 1998, 1997 and 1996
were $322,000, $424,000 and $812,000, 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 $2.1 million in 1998,
$2.1 million in 1997 and $2.8 million in 1996.
A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $714,000 in 1998,
$714,000 in 1997, and $687,000 in 1996.
9. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as
follows:
Year Ended December 31,
1998 1997 1996
(in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 8,387 $10,425 $ 5,118
Deferred 3,967 660 1,857
Deferred Investment Tax Credits (1,202) (1,219) (1,232)
Total 11,152 9,866 5,743
Charged (Credited) to Nonoperating
Income (net):
Current (794) (359) (473)
Deferred (360) 81 7
Deferred Investment Tax Credits (213) (173) (158)
Total (1,367) (451) (624)
Total Federal Income Taxes as Reported $ 9,785 $ 9,415 $ 5,119
The following is a reconciliation of the difference between the
amount of federal income taxes computed by multiplying book income
before federal income taxes by the statutory tax rate, and the
amount of federal income taxes reported.
Year Ended December 31,
1998 1997 1996
(in thousands)
Net Income $21,676 $20,746 $16,973
Federal Income Taxes 9,785 9,415 5,119
Pre-tax Book Income $31,461 $30,161 $22,092
Federal Income Taxes on Pre-tax Book
Income at Statutory Rate (35%) $11,011 $10,556 $ 7,732
Increase (Decrease) in Federal Income
Taxes Resulting From the Following Items:
Depreciation 1,633 1,850 1,694
Removal Costs (840) (840) (979)
Allowance For Funds Used During
Construction (373) (364) (389)
Percentage Repair Allowance (460) (456) (445)
Corporate Owned Life Insurance (134) (328) (479)
Investment Tax Credits (net) (1,415) (1,392) (1,390)
Other 363 389 (625)
Total Federal Income Taxes as Reported $ 9,785 $ 9,415 $ 5,119
Effective Federal Income Tax Rate 31.1% 31.2% 23.2%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
it:
December 31,
1998 1997
(in thousands)
Deferred Tax Assets $ 31,453 $ 34,276
Deferred Tax Liabilities (190,159) (188,221)
Net Deferred Tax Liabilities $(158,706) $(153,945)
Property Related Temporary
Differences $(112,246) $(108,850)
Amounts Due From Customers For
Future Federal Income Taxes (18,759) (18,320)
Deferred State Income Taxes (31,460) (31,561)
Other (net) 3,759 4,786
Net Deferred Tax Liabilities $(158,706) $(153,945)
KPCo joins in the filing of a consolidated federal income tax
return with its affiliates 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 determin-
ing 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 the
deductibility of interest deductions related to AEP's corporate
owned life insurance program, which is discussed under the heading,
Litigation, in Note 3, 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.
10. COMMON SHAREHOLDER'S EQUITY:
The Company received from AEP Co., Inc. cash capital
contributions of $20 million in 1998, $20 million in 1997 and $30
million in 1996 which were credited to paid-in capital. There were
no other transactions affecting common stock and paid-in capital
accounts in 1998, 1997 and 1996.
11. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1998 1997
(in thousands)
First Mortgage Bonds $177,313 $179,410
Senior Unsecured Notes 77,553 47,708
Notes Payable 75,000 75,000
Junior Debentures 38,972 38,933
368,838 341,051
Less Portion Due Within One Year 60,000 -
Total $308,838 $341,051
December 31,
1998 1997
First Mortgage Bonds (in thousands)
outstanding were as follows:
% Rate Due
7.20 1999 - December 1 $ 35,000 $ 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 15,000
7.90 2023 - June 1 25,000 25,000
Unamortized Discount (484) (590)
Total $177,313 $179,410
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,
1998 1997
(in thousands)
% Rate Due
6.91 2007 - October 1 $48,000 $48,000
6.45 2008 - November 10 30,000 -
Unamortized Discount (447) (292)
Total $77,553 $47,708
December 31,
1998 1997
Notes Payable to Banks (in thousands)
are composed of the following:
% Rate Due
6.42 1999 - April 1 $25,000 $25,000
6.57 2000 - April 1 25,000 25,000
7.445 2002 - September 20 25,000 25,000
Total $75,000 $75,000
Junior debentures are composed of the following:
December 31,
1998 1997
(in thousands)
% Rate Due
8.72 2025 - June 30 $40,000 $40,000
Unamortized Discount (1,028) (1,067)
Total $38,972 $38,933
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, 1998, annual long-term debt payments are as
follows:
Amount
(in thousands)
1999 $ 60,000
2000 25,000
2001 60,000
2002 25,000
2003 45,000
Later Years 155,797
Total Principal Amount 370,797
Unamortized Discount (1,959)
Total $368,838
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, 1998 and 1997 were available
in the amounts of $763 million and $442 million, respectively.
Facility fees of approximately 1/10 of 1% of the short-term lines
of credit are required to maintain the lines of credit.
Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1998:
Notes Payable $ 4,850 6.4%
Commercial Paper 15,500 6.0%
Total $20,350 6.1%
December 31, 1997:
Commercial Paper $36,500 6.8%
12. 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,
1998 1997 1996
(in thousands)
Lease Payments on
Operating Leases $ 931 $ 369 $ 402
Amortization of Capital Leases 4,265 3,541 2,652
Interest on Capital Leases 1,173 1,548 707
Total Lease Rental Costs $6,369 $5,458 $3,761
Properties under capital leases and related obligations
recorded on the Balance Sheets are as follows:
December 31,
1998 1997
(in thousands)
Electric Utility Plant Under Capital Leases:
Production Plant $ 2,022 $ 2,000
General Plant 26,741 24,814
Total Electric Utility Plant 28,763 26,814
Accumulated Amortization 9,786 8,089
Net Electric Utility Plant
Under Capital Leases $18,977 $18,725
Capital Lease Obligations:*
Noncurrent Liability $14,957 $15,006
Liability Due Within One Year 4,020 3,719
Total Capital Lease Obligations $18,977 $18,725
*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, 1998:
Non-cancelable
Capital Operating
Leases Leases
(in thousands)
1999 $ 5,147 $212
2000 4,355 149
2001 3,607 85
2002 3,096 26
2003 2,126 23
Later Years 4,634 275
Total Future Minimum Lease Payments 22,965 $770
Less Estimated Interest Element 3,988
Estimated Present Value of
Future Minimum Lease Payments $18,977
13. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1998 1997 1996
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $27,857 $24,490 $24,069
Income Taxes 8,607 11,359 9,012
Noncash Acquisitions under
Capital Leases 4,890 8,653 6,322
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
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
1997
March 31 88,580 15,240 9,131
June 30 78,101 9,429 3,141
September 30 84,628 10,837 4,452
December 31 89,326 11,350 4,022
See "Reclassification" section in Note 1 regarding reclassification
of prior period amounts.