KENTUCKY POWER COMPANY
SELECTED FINANCIAL DATA
Year Ended December 31,
1997 1996 1995 1994 1993
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $359,543 $323,321 $328,144 $307,443 $294,252
Operating Expenses 312,687 281,978 279,123 261,354 255,516
Operating Income 46,856 41,343 49,021 46,089 38,736
Nonoperating Income (Loss) (464) (594) 3 (102) 59
Income Before Interest Charges 46,392 40,749 49,024 45,987 38,795
Interest Charges 25,646 23,776 23,896 20,714 20,764
Net Income $ 20,746 $ 16,973 $ 25,128 $ 25,273 $ 18,031
December 31,
1997 1996 1995 1994 1993
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,006,955 $951,602 $879,657 $851,912 $807,428
Accumulated Depreciation
and Amortization 296,318 286,640 270,590 259,984 248,673
Net Electric Utility Plant $ 710,637 $664,962 $609,067 $591,928 $558,755
Total Assets $ 886,671 $833,579 $772,198 $739,795 $695,866
Common Stock and
Paid-in Capital $ 179,200 $159,200 $129,200 $119,200 $109,200
Retained Earnings 78,076 84,090 91,381 89,173 85,296
Total Common Shareholder's
Equity $ 257,276 $243,290 $220,581 $208,373 $194,496
Long-term Debt(a) $ 341,051 $293,198 $292,525 $253,583 $253,495
Total Capitalization and
Liabilities $ 886,671 $833,579 $772,198 $739,795 $695,866
(a) Including portion due within one year.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS
OF RESULTS OF OPERATIONS
Net income for 1997 increased $3.8 million or 22.2% due mainly
to lower maintenance expenses as a result of a 1996 scheduled
maintenance outage of Big Sandy Plant Unit 2 which was out of
service for 95 days in 1996 for general boiler inspection and
repair. The unavailability of generating capability meant that the
Company had to buy replacement power to meet internal demand and
had fewer sales to the AEP System Power Pool (Power Pool) in 1996.
Operating Revenues Increase
In 1997 operating revenues increased $36.2 million or 11.2% as
revenues from wholesale sales increased significantly due to
increased sales to affiliated companies and new power marketing
transactions which began in July 1997. The substantial increase in
wholesale revenues was largely offset by increased fuel and
purchased power expenses. The following analyzes the increase in
operating revenues.
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Retail:
Price Variance . . . . . . . . $ 2.6
Volume Variance. . . . . . . . 3.0
Fuel Cost Recoveries . . . . . (3.5)
2.1 0.8
Wholesale:
Price Variance . . . . . . . . (9.8)
Volume Variance. . . . . . . . 42.0
32.2 56.3
Other Operating Revenues. . . . . 1.9
Total . . . . . . . . . . . . . $36.2 11.2
The substantial increase in wholesale revenues was due to
increased sales of energy to the Power Pool, reflecting the
increased availability of Big Sandy Plant Unit 2, and new power
marketing transactions with unaffiliated entities which began in
July 1997 when AEP began a new power marketing business as part of
developing a national power trading business. The new power
marketing transactions are for the purchase and sale of electricity
outside the AEP transmission system.
Operating Expenses Increase
Operating expenses increased $30.7 million or 10.9% due to
increases in all categories of expense except maintenance. The
changes in operating expenses can be analyzed as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Fuel. . . . . . . . . . . . . . . . . $ 9.4 13.8
Purchased Power . . . . . . . . . . . 17.5 18.1
Other Operation . . . . . . . . . . . 5.2 11.2
Maintenance . . . . . . . . . . . . . (8.4) (25.5)
Depreciation. . . . . . . . . . . . . 1.3 5.4
Taxes Other Than Federal Income Taxes 1.6 20.6
Federal Income Taxes. . . . . . . . . 4.1 71.8
Total. . . . . . . . . . . . . . $30.7 10.9
The increase in fuel expense reflects increased generation in
1997 as Big Sandy Plant Unit 2 returned to service following the
maintenance outage in 1996.
Purchased power expense increased mainly due to the Company's
share of purchases of power by AEP's new power marketing business.
The increase in other operation expense reflects the effect of
gains on the sale of emission allowances in 1996 and higher
transmission and administrative and general expenses in 1997.
Maintenance expense decreased in 1997 reflecting the cost of
scheduled steam plant maintenance work at Big Sandy Plant in 1996.
The increase in depreciation and amortization expense reflects
additional investment in depreciable plant as a result of the
capitalization of additions made to Big Sandy Plant Unit 2 in 1996
and improvements to the distribution system.
Taxes other than federal income taxes increased due to
increased Kentucky state income taxes reflecting a rise in pre-tax
operating income and the effect of favorable accrual adjustments
recorded in 1996.
The increase in federal income tax expense attributable to
operations was primarily due to an increase in pre-tax operating
income, changes in certain book/tax differences accounted for on a
flow-through basis for ratemaking purposes.
Interest charges rose $1.9 million or 7.9% due to increased
outstanding balances of long-term debt reflecting the issuance of
notes payable in 1997 and 1996.
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, 1997 and 1996, and the related
statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of its operations
and its cash flows for each of the three years in the period ended
December 31, 1997 in conformity with generally accepted accounting
principles.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 24, 1998
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
Year Ended December 31,
1997 1996 1995
(in thousands)
OPERATING REVENUES $359,543 $323,321 $328,144
OPERATING EXPENSES:
Fuel 77,051 67,697 80,337
Purchased Power 113,938 96,485 88,472
Other Operation 51,544 46,347 45,253
Maintenance 24,417 32,793 27,877
Depreciation and Amortization 26,474 25,123 24,434
Taxes Other Than Federal Income Taxes 9,397 7,790 8,431
Federal Income Taxes 9,866 5,743 4,319
TOTAL OPERATING EXPENSES 312,687 281,978 279,123
OPERATING INCOME 46,856 41,343 49,021
NONOPERATING INCOME (LOSS) (464) (594) 3
INCOME BEFORE INTEREST CHARGES 46,392 40,749 49,024
INTEREST CHARGES 25,646 23,776 23,896
NET INCOME $ 20,746 $ 16,973 $ 25,128
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1997 1996 1995
(in thousands)
RETAINED EARNINGS JANUARY 1 $84,090 $91,381 $89,173
NET INCOME 20,746 16,973 25,128
CASH DIVIDENDS DECLARED 26,760 24,264 22,920
RETAINED EARNINGS DECEMBER 31 $78,076 $84,090 $91,381
See Notes to Financial Statements.
KENTUCKY POWER COMPANY
BALANCE SHEETS
December 31,
1997 1996
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 249,184 $244,805
Transmission 303,456 264,563
Distribution 350,793 329,184
General 71,462 64,650
Construction Work in Progress 32,060 48,400
Total Electric Utility Plant 1,006,955 951,602
Accumulated Depreciation and Amortization 296,318 286,640
NET ELECTRIC UTILITY PLANT 710,637 664,962
OTHER PROPERTY AND INVESTMENTS 6,591 6,452
CURRENT ASSETS:
Cash and Cash Equivalents 1,381 1,106
Accounts Receivable:
Customers 24,127 22,862
Affiliated Companies 1,722 2,198
Miscellaneous 3,276 3,529
Allowance for Uncollectible Accounts (525) (272)
Fuel - at average cost 10,685 9,244
Materials and Supplies - at average cost 14,054 13,175
Accrued Utility Revenues 12,981 8,175
Prepayments 1,538 2,011
TOTAL CURRENT ASSETS 69,239 62,028
REGULATORY ASSETS 90,045 88,776
DEFERRED CHARGES 10,159 11,361
TOTAL $ 886,671 $833,579
See Notes to Financial Statements.
KENTUCKY POWER COMPANY
December 31,
1997 1996
(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 128,750 108,750
Retained Earnings 78,076 84,090
Total Common Shareholder's Equity 257,276 243,290
Long-term Debt 341,051 293,198
TOTAL CAPITALIZATION 598,327 536,488
OTHER NONCURRENT LIABILITIES 26,693 19,467
CURRENT LIABILITIES:
Short-term Debt 36,500 51,675
Accounts Payable - General 13,842 16,272
Accounts Payable - Affiliated Companies 10,732 14,785
Customer Deposits 3,660 3,409
Taxes Accrued 6,130 5,064
Interest Accrued 6,015 5,217
Other 14,935 9,199
TOTAL CURRENT LIABILITIES 91,814 105,621
DEFERRED INCOME TAXES 153,945 153,538
DEFERRED INVESTMENT TAX CREDITS 15,615 17,007
DEFERRED CREDITS 277 1,458
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $886,671 $833,579
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
Year Ended December 31,
1997 1996 1995
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 20,746 $ 16,973 $ 25,128
Adjustments for Noncash Items:
Depreciation and Amortization 26,486 25,196 24,507
Deferred Income Taxes 741 1,864 (2,380)
Deferred Investment Tax Credits (1,392) (1,390) (1,478)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (283) 1,596 (8,467)
Fuel, Materials and Supplies (2,320) (6,412) 5,343
Accrued Utility Revenues (4,806) 5,325 (4,372)
Accounts Payable (6,483) 9,291 2,346
Other (net) 8,576 (7,410) 1,162
Net Cash Flows From Operating Activities 41,265 45,033 41,789
INVESTING ACTIVITIES:
Construction Expenditures (66,642) (75,816) (39,264)
Proceeds from Sales of Property - 250 -
Net Cash Flows Used For Investing Activities (66,642) (75,566) (39,264)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 20,000 30,000 10,000
Issuance of Long-term Debt 47,587 74,985 38,647
Retirement of Long-term Debt - (74,738) -
Change in Short-term Debt (net) (15,175) 24,625 (28,100)
Dividends Paid (26,760) (24,264) (22,920)
Net Cash Flows From (Used For) Financing Activities 25,652 30,608 (2,373)
Net Increase in Cash and Cash Equivalents 275 75 152
Cash and Cash Equivalents January 1 1,106 1,031 879
Cash and Cash Equivalents December 31 $ 1,381 $ 1,106 $ 1,031
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, sale, purchase, transmission and distribution of
electric power serving 168,000 retail customers in eastern
Kentucky. Wholesale electric power is supplied to neighboring
utility systems, power marketers and the American Electric Power
(AEP) System Power Pool (Power Pool). As a member of the AEP Power
Pool and a signatory company to the American Electric Power System
(AEP System) Transmission Equalization Agreement, KPCo's 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
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) No. 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 1997, 1996 and 1995 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 as follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production 3.8%
Transmission 1.7%
Distribution 3.5%
General 2.5%
Expenditures to demolish and remove 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 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 adjustment
mechanism. Wholesale jurisdictional fuel cost changes are expensed
and billed as incurred.
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
Based on directives of regulatory commissions, the Company
reflected investment tax credits in rates and on its books on a
deferral basis. Commensurate with rate treatment deferred
investment tax credits are being amortized over the life of the
related plant investment. The Company's policy with regard to
investment tax credits for nonutility property is to practice the
flow-through method of accounting.
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 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 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.
2. EFFECTS OF REGULATION:
In accordance with SFAS No. 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.
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 No. 71 requires that the Company's rates be
cost-based regulated. The Company has reviewed all the evidence
currently available and concluded that it continues to meet the
requirements to apply SFAS No. 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
investment.
Recognized regulatory assets and liabilities are comprised of
the following:
December 31,
1997 1996
(in thousands)
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $83,904 $84,238
Other 6,141 4,538
Total Regulatory Assets $90,045 $88,776
Regulatory Liabilities:
Deferred Investment Tax Credits $15,615 $17,007
Other* - 1,142
Total Regulatory Liabilities $15,615 $18,149
* Included in Deferred Credits on the Balance Sheets.
3. RATE MATTERS
In a May 27, 1997 order the KPSC approved the Company's request
to establish a monthly surcharge to recover environmental compliance
costs. In approving the surcharge the KPSC denied inclusion of certain
environmental compliance costs in the surcharge. The surcharge was
applied to bills rendered on and after July 7, 1997. However, as
part of the May 27, 1997 order the KPSC directed the Company to
refund to ratepayers emission allowance sale proceeds, through a
reduction of the first twelve months of environmental surcharge
revenues. This matter is being appealed. The ultimate resolution of
this matter will not have a significant impact on results of
operation, cash flows or financial condition.
4. 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. Aggregate
construction program expenditures for 1998-2000 are estimated to be
$139 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 $12 million at
December 31, 1997.
Revised Air Quality Standards
On July 18, 1997, the United States Environmental Protection
Agency published a revised National Ambient Air Quality Standard
(NAAQS) for ozone and a new NAAQS for fine particulate matter (less
than 2.5 microns in size). The new ozone standard is expected to
result in redesignation of a number of areas of the country that
are currently in compliance with the existing standard to
nonattainment status which could ultimately dictate more stringent
emission restrictions for AEP System generating units. New
stringent emission restrictions on AEP System generating units to
achieve attainment of the fine particulate matter standard could
also be imposed. The AEP System operating companies joined with
other utilities to appeal the revised NAAQS and filed petitions for
review in August and September 1997 in the U.S. Court of Appeals
for the District of Columbia Circuit. Management is unable to
estimate compliance costs without knowledge of the reductions that
may be necessary to meet the new standards. If such costs are
significant, they could have a material adverse effect on results
of operations, cash flows and possibly financial condition unless
recovered.
Litigation
KPCo is involved in a number of 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.
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 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,
1997 1996 1995
(in thousands)
Demand Charge $39,993 $39,622 $39,608
Energy Charge 28,393 27,743 29,027
Total $68,386 $67,365 $68,635
Benefits and costs of the System's generating plants are shared
by members of the AEP Power Pool. The Company is a member of the
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 Power Pool
members based on their relative peak demands and generating
reserves. Power Pool members are also compensated for the out-of-pocket
costs of energy delivered to the Power Pool and charged for
energy received from the Power Pool.
Operating revenues include $41.0 million in 1997, $28.0 million
in 1996 and $38.9 million in 1995 for energy supplied to the Power
Pool.
Since the Company's internal peak demand exceeds its generating
capacity, charges for Power Pool capacity reservation, which is a
charge for the right to receive power even if the power is not
taken, and for energy received from the Power Pool were included in
purchased power expense as follows:
Year Ended December 31,
1997 1996 1995
(in thousands)
Capacity Charge $ 7,196 $ 6,425 $ 6,489
Energy Charge 13,855 19,741 9,493
Total $21,051 $26,166 $15,982
Power Pool members share in wholesale sales to unaffiliated
entities made by the Power Pool. The Company's share of these
wholesale power pool sales was included in operating revenues in
the amount of $45.9 million in 1997, $26.7 million in 1996 and
$19.2 million in 1995.
In addition, the Power Pool purchases power from unaffiliated
companies for resale to other unaffiliated entities. The Company's
share of these purchases was included in purchased power expense
and totaled $24.5 million (including new power marketing
transactions) in 1997, $3.0 million in 1996 and $3.9 million in
1995. Revenues from these transactions, including a transmission
fee for power that passes through the AEP System transmission
network, are included in the above Power Pool wholesale operating
revenues.
AEP System companies participate in a 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 $2.7 million,
$3.3 million and $3.5 million in 1997, 1996 and 1995, respectively.
American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies. The costs of the services are billed by AEPSC on a
direct-charge basis to the extent practicable, and on reasonable
bases of proration for indirect costs. The charges 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. BENEFIT PLANS:
KPCo participates in the AEP System pension plan, a trusteed,
noncontributory defined benefit plan covering all employees meeting
eligibility requirements. Benefits are based on service years and
compensation levels. Pension costs are allocated by first charging
each System company with its service cost and then allocating the
remaining pension cost in proportion to its share of the projected
benefit obligation. The funding policy is to make annual trust
fund contributions equal to the net periodic pension cost up to the
maximum amount deductible for federal income taxes, but not less
than the minimum required contribution in accordance with the
Employee Retirement Income Security Act of 1974. Net pension plan
costs for the years ended December 31, 1997, 1996 and 1995 were
$424,000, $812,000 and $573,000, respectively.
Postretirement benefits other than pensions (OPEB) are provided
for retired employees under an AEP System plan. Substantially all
employees are eligible for postretirement health care and life
insurance if they retire from active service after reaching age 55
and have at least 10 service years. OPEB costs are determined by
the application of AEP System actuarial assumptions to each
operating company's employee complement. The annual accrued costs,
which includes the recognition of one-twentieth of the prior
service transition obligation, were $2.1 million in 1997, $2.8
million in 1996 and $2.4 million in 1995. The funding policy for
AEP's OPEB plan is to make contributions to an external Voluntary
Employees Beneficiary Association trust fund equal to the
incremental OPEB costs (i.e., the amount that the total
postretirement benefits cost under SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions,"
exceeds the pay-as-you-go amount). Contributions were $1.1 million
in 1997, $1.3 million in 1996 and $1.6 million in 1995.
An employee savings plan is offered which allows participants
to contribute up to 17% of their salaries into various investment
alternatives, including AEP Co., Inc. common stock. An employer
matching contribution, equaling one-half of the employees'
contribution to the plan up to a maximum of 3% of the employees'
base salary, is invested in AEP Co., Inc. common stock. The
Company's annual contributions totaled $714,000 in 1997, $687,000
in 1996 and $720,000 in 1995.
7. COMMON SHAREHOLDER'S EQUITY:
The Company received from AEP Co., Inc. cash capital
contributions of $20 million in 1997, $30 million in 1996 and $10
million in 1995 which were credited to paid-in capital. There were
no other transactions affecting common stock and paid-in capital
accounts in 1997, 1996 and 1995.
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as
follows:
Year Ended December 31,
1997 1996 1995
(in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $10,425 $ 5,118 $ 7,935
Deferred 660 1,857 (2,373)
Deferred Investment Tax Credits (1,219) (1,232) (1,243)
Total 9,866 5,743 4,319
Charged (Credited) to Nonoperating
Income (net):
Current (359) (473) (163)
Deferred 81 7 (7)
Deferred Investment Tax Credits (173) (158) (235)
Total (451) (624) (405)
Total Federal Income Taxes as Reported $ 9,415 $ 5,119 $ 3,914
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,
1997 1996 1995
(in thousands)
Net Income $20,746 $16,973 $25,128
Federal Income Taxes 9,415 5,119 3,914
Pre-tax Book Income $30,161 $22,092 $29,042
Federal Income Taxes on Pre-tax Book
Income at Statutory Rate (35%) $10,556 $ 7,732 $10,165
Increase (Decrease) in Federal Income
Taxes Resulting From the Following Items:
Depreciation 1,850 1,694 (648)
Removal Costs (840) (979) (979)
Amortization of Deferred Federal Income
Tax in Excess of the Statutory Tax Rate - (339) (1,355)
Allowance For Funds Used During
Construction (364) (389) (390)
Percentage Repair Allowance (456) (445) (433)
Corporate Owned Life Insurance (328) (479) (826)
Investment Tax Credits (net) (1,392) (1,390) (1,478)
Other 389 (286) (142)
Total Federal Income Taxes as Reported $ 9,415 $ 5,119 $ 3,914
Effective Federal Income Tax Rate 31.2% 23.2% 13.5%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
it:
December 31,
1997 1996
(in thousands)
Deferred Tax Assets $ 34,276 $ 30,919
Deferred Tax Liabilities (188,221) (184,457)
Net Deferred Tax Liabilities $(153,945) $(153,538)
Property Related Temporary
Differences $(108,850) $(108,276)
Amounts Due From Customers For
Future Federal Income Taxes (18,320) (18,734)
Deferred State Income Taxes (31,561) (30,711)
Other (net) 4,786 4,183
Total Net Deferred
Tax Liabilities $(153,945) $(153,538)
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 Internal Revenue Service
(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 open and under audit by the IRS.
During the audit the IRS agents requested a ruling from their
National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed. The COLI program was established in 1992 as part
of the Company's strategy to fund and reduce the cost of medical
benefits for retired employees. AEP filed a brief with the IRS
National Office refuting the agents' position. Although no
adjustments have been proposed, a disallowance of the COLI interest
deductions through December 31, 1997 would reduce earnings by
approximately $6 million (including interest). Management
believes it has meritorious defenses and will vigorously contest
any proposed adjustments. No provisions for this amount have been
recorded. In the event the Company is unsuccessful it could have
a material adverse impact on results of operations and cash flows.
9. LEASES:
Leases of property, plant and equipment are for periods 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,
1997 1996 1995
(in thousands)
Operating Leases $ 369 $ 402 $ 564
Amortization of Capital Leases 3,541 2,652 2,111
Interest on Capital Leases 1,548 707 513
Total Rental Costs $5,458 $3,761 $3,188
Properties under capital leases and related obligations
recorded on the Balance Sheets are as follows:
December 31,
1997 1996
(in thousands)
Electric Utility Plant:
Production $ 2,000 $ 1,586
General 24,814 18,475
Total Electric Utility Plant 26,814 20,061
Accumulated Amortization 8,089 7,211
Net Properties under Capital Lease $18,725 $12,850
Capital Lease Obligations:
Noncurrent Liability $15,006 $ 9,833
Liability Due Within One Year 3,719 3,017
Total Capital Lease Obligations $18,725 $12,850
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, 1997:
Non-
cancelable
Capital Operating
Leases Leases
(in thousands)
1998 $ 4,859 $268
1999 4,448 196
2000 3,653 134
2001 2,932 66
2002 2,449 -
Later Years 4,377 -
Total Future Minimum Lease Payments 22,718 $664
Less Estimated Interest Element 3,993
Estimated Present Value of
Future Minimum Lease Payments $18,725
10. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1997 1996
(in thousands)
First Mortgage Bonds $179,410 $179,305
Senior Unsecured Notes 47,708 -
Notes Payable 75,000 75,000
Junior Debentures 38,933 38,893
Total $341,051 $293,198
December 31,
1997 1996
First Mortgage Bonds: (in thousands)
% 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 15,000 15,000
7.90 2023 - June 1 25,000 25,000
Unamortized Discount (net) (590) (695)
Total $179,410 $179,305
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.
In October 1997 the Company issued $48,000,000 of 6.91% Senior
Unsecured Notes due October 7, 2007. The unamortized discount at
December 31, 1997 is $292,000.
December 31,
1997 1996
Notes Payable to Banks: (in thousands)
% 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,
1997 1996
(in thousands)
% Rate Due
8.72 2025 - June 30 $40,000 $40,000
Unamortized Discount (1,067) (1,107)
Total $38,933 $38,893
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, 1997, annual long-term debt payments are as
follows:
Amount
(in thousands)
1998 $ -
1999 60,000
2000 25,000
2001 60,000
2002 25,000
Later Years 173,000
Total Principal Amount 343,000
Unamortized Discount (1,949)
Total $341,051
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, 1997 and 1996 were available
in the amounts of $442 million and $409 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, 1997:
Commercial Paper $36,500 6.8%
December 31, 1996:
Notes Payable $33,800 6.1%
Commercial Paper 17,875 6.5%
Total $51,675 6.2%
11. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The carrying amount of cash and cash equivalents, accounts
receivable, short-term debt and accounts payable approximates fair
value because of the short-term maturities of these instruments.
At December 31, 1997 and 1996 the fair value of long-term debt was
$359 million and $304 million, respectively, based on quoted market
prices for the same or similar issues and the current interest
rates offered for debt of the same remaining maturities. The
carrying amount for long-term debt was $341 million and $293
million at December 31, 1997 and 1996, respectively.
12. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1997 1996 1995
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $24,490 $24,069 $23,581
Income Taxes 11,359 9,012 6,453
Noncash Acquisitions under
Capital Leases 8,653 6,322 3,651
13. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
1997
March 31 $ 88,580 $15,240 $9,131
June 30 78,101 9,429 3,141
September 30 89,791 10,837 4,452
December 31 103,071 11,350 4,022
1996
March 31 $88,589 $13,158 $6,756
June 30 78,730 8,301 2,369
September 30 78,499 10,393 4,441
December 31 77,503 9,491 3,407