SELECTED FINANCIAL DATA
Year Ended December 31,
1995 1994 1993 1992 1991
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $328,144 $307,443 $294,252 $313,216 $306,832
Operating Expenses 279,123 261,354 255,516 264,964 256,517
Operating Income 49,021 46,089 38,736 48,252 50,315
Nonoperating Income (Loss) 3 (102) 59 221 139
Income Before Interest Charges 49,024 45,987 38,795 48,473 50,454
Interest Charges 23,896 20,714 20,764 21,936 21,989
Net Income $ 25,128 $ 25,273 $ 18,031 $ 26,537 $ 28,465
December 31,
1995 1994 1993 1992 1991
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $879,657 $851,912 $807,428 $780,856 $756,709
Accumulated Depreciation
and Amortization 270,590 259,984 248,673 238,342 226,209
Net Electric Utility Plant $609,067 $591,928 $558,755 $542,514 $530,500
Total Assets $772,198 $739,795 $695,866 $616,700 $611,854
Common Stock and Paid-in Capital $129,200 $119,200 $109,200 $109,200 $109,200
Retained Earnings 91,381 89,173 85,296 89,957 84,771
Total Common Shareholder's Equity $220,581 $208,373 $194,496 $199,157 $193,971
Long-term Debt (a) $292,525 $253,583 $253,495 $254,097 $254,291
Total Capitalization and
Liabilities $772,198 $739,795 $695,866 $616,700 $611,854
(a) Including portion due within one year.
MANAGEMENT'S NARRATIVE ANALYSIS
OF RESULTS OF OPERATIONS
Net Income Declines
Although operating revenues increased 7% in 1995, net income declined
slightly reflecting the recordation of severance pay charges in connection
with a realignment of operations and a rise in interest expense.
Operating Revenues Increase
In 1995 operating revenues increased $21 million. The following table
analyzes the increase:
Increase From
(dollars in millions) Previous Year
Amount %
Retail:
Price variance . . . . . . . . . $(1.0)
Volume variance. . . . . . . . . 14.3
13.3 5.3
Wholesale:
Price variance . . . . . . . . . (5.0)
Volume variance. . . . . . . . . 11.8
6.8 12.6
Other Operating Revenues . . . . . 0.6
Total. . . . . . . . . . . . . . $20.7 6.7
Increased energy sales to retail and wholesale customers of 6% and 22%,
respectively, were the primary cause of the revenue increase. Unseasonably
warm summer weather in 1995, colder weather in the fourth quarter of 1995
compared with the prior year s fourth quarter and growth in the number of
residential and commercial customers produced the increase in retail sales.
All retail customer classes experienced increased energy sales in 1995.
Sales to residential customers, the most weather-sensitive customer class,
rose 8% while sales to commercial and industrial customers increased 6% and
4%, respectively.
The rise in wholesale energy sales was mainly due to an increase in energy
supplied to the AEP System Power Pool (Power Pool) reflecting increased
weather-related energy demand of affiliated Power Pool members and increased
availability of the Company s Big Sandy generating units and increased sales
made on an hourly basis by the Power Pool to unaffiliated utilities. This
type of short-term sale is typically made when the unaffiliated utility can
purchase energy at a lower cost than the cost at which that utility can
generate the energy.
Operating Expenses Increase
The significant changes in operating expenses and interest charges were:
Increase From
(dollars in millions) Previous Year
Amount %
Fuel. . . . . . . . . . . . . . . . . $18.3 29.4
Purchased Power . . . . . . . . . . . (6.1) (6.4)
Other Operation . . . . . . . . . . . 6.0 15.3
Maintenance . . . . . . . . . . . . . (4.1) (12.8)
Federal Income Taxes. . . . . . . . . 1.7 63.5
Interest Charges. . . . . . . . . . . 3.2 15.4
Fuel expense increased significantly as a result of a 25% increase in net
generation mainly reflecting the increase in weather related demand for
energy and the effect of the 800 megawatt Big Sandy Unit 2 being out of
service for scheduled maintenance in the fall of 1994.
The decrease in purchased power expense resulted from decreased energy
purchases from unaffiliated utilities for pass-through sales and reduced
energy purchases from the Power Pool reflecting the availability of the
Company s generating capacity throughout substantially all of 1995. These
decreases were partly offset by an increase in the Company s share of Power
Pool capacity charges. As a Power Pool member whose internal demand exceeds
its capacity, the Company pays capacity charges allocated to Power Pool
members based on their relative peak demands. An increase in the Company s
prior twelve month peak demand relative to the total peak demand of all Power
Pool members caused the increase in Power Pool capacity charges.
Other operation expense increased due to the recordation of a provision for
severance pay related to a planned staffing reduction, increased accruals for
incentive pay and a reduction in transmission equalization credits under the
AEP System transmission equalization agreement. The reduction in
transmission credits reflected the increase in the prior twelve month peak
demand relative to the peak demand of the other affiliated members of the
transmission agreement. The transmission agreement provides for sharing the
cost of investment in the AEP System s transmission facilities in proportion
to the System companies respective peak demands through equalization
payments and receipts. On that basis, the Company receives equalization
payments.
The decline in maintenance expense reflects the effect of significant
distribution line maintenance expenditures in 1994 to repair damage from
severe winter ice storms and a decrease in 1995 in scheduled steam plant
maintenance. In 1994 both units at the Big Sandy Plant underwent scheduled
boiler inspections and repairs while major maintenance was performed in 1995
on Unit 1 only.
The increase in federal income tax expense attributable to operations was
due to the increase in pre-tax operating income and the effects of favorable
accrual adjustments recorded in 1994 in connection with the resolution of the
audit of prior years tax returns.
The issuance of $40 million of Junior Subordinated Debentures in April 1995
was the main reason for the increase in interest expense.
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, 1995 and 1994, and the related statements of income, retained
earnings, and cash flows for each of the three years in the period ended
December 31, 1995. 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,
1995 and 1994, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 1995 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 27, 1996
STATEMENTS OF INCOME
Year Ended December 31,
1995 1994 1993
(in thousands)
OPERATING REVENUES $328,144 $307,443 $294,252
OPERATING EXPENSES:
Fuel 80,337 62,072 62,106
Purchased Power 88,472 94,565 94,806
Other Operation 45,253 39,237 38,688
Maintenance 27,877 31,967 28,687
Depreciation and Amortization 24,434 23,047 22,275
Taxes Other Than Federal Income Taxes 8,431 7,825 7,504
Federal Income Taxes 4,319 2,641 1,450
TOTAL OPERATING EXPENSES 279,123 261,354 255,516
OPERATING INCOME 49,021 46,089 38,736
NONOPERATING INCOME (LOSS) 3 (102) 59
INCOME BEFORE INTEREST CHARGES 49,024 45,987 38,795
INTEREST CHARGES 23,896 20,714 20,764
NET INCOME $ 25,128 $ 25,273 $ 18,031
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1995 1994 1993
(in thousands)
RETAINED EARNINGS JANUARY 1 $89,173 $85,296 $89,957
NET INCOME 25,128 25,273 18,031
CASH DIVIDENDS DECLARED 22,920 21,396 22,692
RETAINED EARNINGS DECEMBER 31 $91,381 $89,173 $85,296
See Notes to Financial Statements.
BALANCE SHEETS
December 31,
1995 1994
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $230,054 $224,365
Transmission 261,619 258,178
Distribution 313,783 297,754
General 59,611 56,613
Construction Work in Progress 14,590 15,002
Total Electric Utility Plant 879,657 851,912
Accumulated Depreciation and Amortization 270,590 259,984
NET ELECTRIC UTILITY PLANT 609,067 591,928
OTHER PROPERTY AND INVESTMENTS 6,438 6,533
CURRENT ASSETS:
Cash and Cash Equivalents 1,031 879
Accounts Receivable:
Customers 23,283 19,144
Affiliated Companies 4,150 514
Miscellaneous 2,739 2,048
Allowance for Uncollectible Accounts (259) (260)
Fuel - at average cost 3,526 11,735
Materials and Supplies - at average cost 12,481 9,615
Accrued Utility Revenues 13,500 9,128
Prepayments 1,701 1,476
TOTAL CURRENT ASSETS 62,152 54,279
REGULATORY ASSETS 82,388 76,006
DEFERRED CHARGES 12,153 11,049
TOTAL $772,198 $739,795
See Notes to Financial Statements.
December 31,
1995 1994
(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 78,750 68,750
Retained Earnings 91,381 89,173
Total Common Shareholder's Equity 220,581 208,373
First Mortgage Bonds 224,235 253,583
Subordinated Debentures 38,854 -
TOTAL CAPITALIZATION 483,670 461,956
OTHER NONCURRENT LIABILITIES 15,031 14,130
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 29,436 -
Short-term Debt 27,050 55,150
Accounts Payable - General 11,608 11,119
Accounts Payable - Affiliated Companies 10,158 8,301
Customer Deposits 3,704 4,297
Taxes Accrued 7,972 6,256
Interest Accrued 5,853 5,794
Other 13,283 11,786
TOTAL CURRENT LIABILITIES 109,064 102,703
DEFERRED INCOME TAXES 145,005 140,490
DEFERRED INVESTMENT TAX CREDITS 18,397 19,875
DEFERRED CREDITS 1,031 641
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $772,198 $739,795
STATEMENTS OF CASH FLOWS
Year Ended December 31,
1995 1994 1993
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 25,128 $ 25,273 $ 18,031
Adjustments for Noncash Items:
Depreciation and Amortization 24,507 23,124 22,358
Deferred Income Taxes (2,380) (1,239) (224)
Deferred Investment Tax Credits (1,478) (1,453) (1,528)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (8,467) 2,692 (1,953)
Fuel, Materials and Supplies 5,343 (4,141) 449
Accrued Utility Revenues (4,372) 1,348 2,228
Accounts Payable 2,346 964 2,000
Other (net) 1,162 (247) (4,408)
Net Cash Flows From Operating Activities 41,789 46,321 36,953
INVESTING ACTIVITIES:
Construction Expenditures (39,264) (53,119) (35,247)
Proceeds from Sales of Property - 1,215 1,294
Net Cash Flows Used For Investing Activities (39,264) (51,904) (33,953)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 10,000 10,000 -
Issuance of Long-term Debt 38,647 - 84,115
Retirement of Long-term Debt - - (85,885)
Change in Short-term Debt (net) (28,100) 17,000 21,250
Dividends Paid (22,920) (21,396) (22,692)
Net Cash Flows From (Used For) Financing Activities (2,373) 5,604 (3,212)
Net Increase (Decrease) in Cash and Cash Equivalents 152 21 (212)
Cash and Cash Equivalents January 1 879 858 1,070
Cash and Cash Equivalents December 31 $ 1,031 $ 879 $ 858
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, transmission
and distribution of electric power in eastern Kentucky. The Company provides
electric power to 165,000 retail customers in its territory. Wholesale
electric power is supplied to neighboring utility systems. As a member of
the American Electric Power (AEP) System Power Pool (Power Pool) and a
signatory company to the AEP 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 and liabilities are recorded to reflect the economic
effects of regulation.
Use of Estimates
The preparation of these financial statements in conformity with generally
accepted accounting principles requires in certain instances the use of
management s 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 from the plant accounts and
associated removal costs, net of salvage, are deducted from accumulated
depreciation.
The costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is recovered with
regulator approval over the service life of utility plant through
depreciation and represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 1995, 1994
and 1993 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 Composite
of Property Annual Rates
Production 3.8%
Transmission 1.7%
Distribution 3.5%
General 2.5%
Expenditures to remove retired 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
Revenues include the accrual of electricity consumed but unbilled at month-
end as well as billed revenues.
Fuel Cost
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 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, regulatory assets and
liabilities are recorded in accordance with SFAS 71.
Investment Tax Credits
Based on directives of regulatory commissions, the Company reflected
investment tax credits in rates 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 was to practice the flow-
through method of accounting.
Debt
Gains and losses on reacquired debt are deferred and amortized over the
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 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.
Reclassifications
Certain prior-period amounts were reclassified to conform with current-
period presentation.
2. EFFECTS OF REGULATION:
The financial statements include assets and liabilities recorded in
accordance with regulatory actions in order to match expenses with the
related revenues from cost-based regulated 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.
The Company 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 no longer met these requirements regulatory
assets and liabilities would have to be written off for that portion of the
business. Regulatory assets and liabilities are comprised of the following:
December 31,
1995 1994
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $77,568 $70,673
Other 4,820 5,333
Total Regulatory Assets $82,388 $76,006
Regulatory Liabilities:
Deferred Investment Tax Credits $18,397 $19,875
Other* 787 352
Total Regulatory Liabilities $19,184 $20,227
* Included in Deferred Credits on the Balance Sheets.
3. COMMITMENTS AND CONTINGENCIES:
Construction
Construction expenditures for the years 1996-1998 are estimated to be $210
million and, in connection therewith, certain commitments have been made.
Fuel Supply
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. The fuel adjustment mechanism generally provides for recovery of
changes in the cost of fuel.
Clean Air
The Clean Air Act Amendments of 1990 require significant reductions in
sulfur dioxide and nitrogen oxide emissions from various AEP System
generating plants. The first phase of reductions in sulfur dioxide emissions
(Phase I) began in 1995 and the second, more restrictive phase (Phase II)
begins in the year 2000. The law also established a permanent nationwide cap
on sulfur dioxide emissions after 1999. The Big Sandy Plant is not affected
by Phase I emission requirements. However, a portion of Phase I compliance
costs of other AEP affiliates is included in AEP System Power Pool costs
(which are described in Note 4) and charged to the Company. These costs are
not expected to have an adverse impact on results of operations.
Loan Guarantees
A constructive marketing program enables residential customers to borrow
from area banks to purchase energy efficient electrical equipment, such as
heat pumps. KPCo guarantees loan principal plus interest. The guaranteed
amounts totaled $10.3 million at December 31, 1995.
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 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 1999. 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 and energy purchases under the Unit Power Agreement were
included in purchased power expense as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Demand Charge $39,608 $40,587 $41,995
Energy Charge 29,027 28,711 24,626
Total $68,635 $69,298 $66,621
Benefits and costs of the System's generating plants are shared by members
of the AEP System 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
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 $38.9 million in 1995, $31.6 million in 1994 and
$27.3 million in 1993 for supplying energy to the Power Pool.
Charges for Power Pool capacity, which is a charge for the right to receive
power and payable 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,
1995 1994 1993
(in thousands)
Capacity Charge $ 6,489 $ 1,921 $ 5,490
Energy Charge 9,493 18,103 20,870
Total $15,982 $20,024 $26,360
Power Pool members share in wholesale sales to unaffiliated utilities made
by the Power Pool. The Company's share was included in operating revenues in
the amount of $19.2 million in 1995 and $19.9 million in both 1994 and 1993.
In addition, the Power Pool purchases power from unaffiliated companies for
immediate resale to other unaffiliated utilities. The Company's share of
these purchases was included in purchased power expense and totaled $3.9
million in 1995, $5.2 million in 1994 and $1.8 million in 1993. Revenues
from these transactions including a transmission fee 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' investment 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, other operating expense includes equalization
credits of $3.5 million, $4.3 million and $3.8 million in 1995, 1994 and
1993, 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.
5. BENEFIT PLANS:
KPCo participates in the AEP System pension plan, a trusteed,
noncontributory defined benefit plan covering all employees meeting eligi-
bility 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, 1995, 1994 and 1993
were $573,000, $1,046,000 and $989,000, respectively.
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 and totaled
$720,000 in 1995, $718,000 in 1994 and $658,000 in 1993.
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 have at least 10
service years and are age 55 or older when employment terminates.
SFAS 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions, was adopted in January 1993 for the Company's aggregate liability
for OPEB. SFAS 106 requires the accrual during the employee's service years
of the present value liability for OPEB costs. Costs for the accumulated
postretirement benefits earned and not recognized at adoption of SFAS 106 are
being recognized in accordance with SFAS 106, as a transition obligation over
20 years. OPEB costs are determined by the application of AEP System
actuarial assumptions to each operating company's employee complement. The
annual accrued costs for 1995, 1994 and 1993 required by SFAS 106 for
employees and retirees, which includes the recognition of one-twentieth of
the prior service transition obligation, was $2.4 million in each year.
As a result of SFAS 106, a Voluntary Employees Beneficiary Association
(VEBA) trust fund for OPEB benefits was established and a corporate owned
life insurance (COLI) program was implemented to lower the net OPEB costs.
The insurance policies have a substantial cash surrender value which is
recorded, net of equally substantial policy loans, in other property and
investments. Legislation was passed by Congress which would have
significantly reduced the tax benefits of our COLI program in the future.
The legislation containing this provision was vetoed by the President. At
this time it is uncertain if legislation repealing certain tax benefits for
COLI programs will be enacted. If enacted this legislation would negatively
impact the effectiveness of the COLI program as a funding and cost reduction
mechanism. The amount contributed to the VEBA trust fund is the difference
between the pay-as-you-go OPEB costs and the SFAS 106 total OPEB cost. This
contribution is funded by amounts collected from ratepayers plus net earnings
from the COLI program. Contributions of $1.6 million in 1995 and 1994 and
$1.7 million in 1993 were made to the VEBA trust fund.
6. COMMON SHAREHOLDER S EQUITY:
The Company received from AEP Co., Inc. cash capital contributions of $10
million in both 1995 and 1994 which were credited to paid-in capital. There
were no other transactions affecting common stock and paid-in capital
accounts in 1995, 1994 and 1993.
Mortgage indentures place various restrictions on the use of retained
earnings for the payment of cah dividends on common stock. At December 31,
1995, $34.2 million of the $91 million of retained earnings were restricted.
Regulatory approval is required to pay dividends out of paid-in capital.
7. 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, 1995 and 1994
the fair value of long-term debt was $307 million and $240 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 $292.5 million and
$253.6 million at December 31, 1995 and 1994, respectively.
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $ 7,935 $ 5,097 $ 3,143
Deferred (2,373) (1,198) (424)
Deferred Investment Tax Credits (1,243) (1,258) (1,269)
Total 4,319 2,641 1,450
Charged (Credited) to Nonoperating Income (net):
Current (163) (227) 229
Deferred (7) (41) 200
Deferred Investment Tax Credits (235) (195) (259)
Total (405) (463) 170
Total Federal Income Taxes as Reported $ 3,914 $ 2,178 $ 1,620
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,
1995 1994 1993
(in thousands)
Net Income $25,128 $25,273 $18,031
Federal Income Taxes 3,914 2,178 1,620
Pre-tax Book Income $29,042 $27,451 $19,651
Federal Income Taxes on Pre-tax Book Income at Statutory Rate (35%) $10,165 $ 9,608 $ 6,878
Increase (Decrease) in Federal Income
Taxes Resulting From the Following Items:
Depreciation (648) (671) (491)
Removal Costs (979) (979) (979)
Amortization of Deferred Federal Income Tax
in Excess of the Statutory Tax Rate (1,355) (1,355) (1,355)
Allowance For Funds Used During Construction (390) (392) (396)
Percentage Repair Allowance (433) (428) (410)
Corporate Owned Life Insurance (826) (615) (236)
Investment Tax Credits (net) (1,478) (1,453) (1,528)
Prior Year Federal Income Tax Accrual Adjustment - (1,100) -
Other (142) (437) 137
Total Federal Income Taxes as Reported $ 3,914 $ 2,178 $ 1,620
Effective Federal Income Tax Rate 13.5% 7.9% 8.2%
The following tables show the elements of the net deferred tax liability
and the significant temporary differences that gave rise to it:
December 31,
1995 1994
(in thousands)
Deferred Tax Assets $ 29,653 $ 21,379
Deferred Tax Liabilities (174,658) (161,869)
Net Deferred Tax Liabilities $(145,005) $(140,490)
Property Related Temporary
Differences $(105,234) $(101,889)
Amounts Due From Customers For
Future Federal Income Taxes (18,228) (15,815)
Deferred State Income Taxes (25,487) (25,487)
All Other (net) 3,944 2,701
Total Net Deferred
Tax Liabilities $(145,005) $(140,490)
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
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 alloca-
tion approximates a separate return result for each company in the consoli-
dated 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 1991 through 1993 are presently being
audited by the IRS. In the opinion of management, the final settlement of
open years will not have a material effect on results of operations.
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 are generally charged to operating expenses in accordance
with rate-making treatment. The components of rental costs are as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Operating Leases $ 564 $ 653 $1,179
Amortization of Capital
Leases 2,111 1,646 1,300
Interest on Capital Leases 513 459 376
Total Rental Costs $3,188 $2,758 $2,855
Properties under capital leases and related obligations recorded on the
Balance Sheets are as follows:
December 31,
1995 1994
(in thousands)
Electric Utility Plant:
Production $ 1,352 $ 990
General 13,731 11,570
Total Electric Utility Plant 15,083 12,560
Accumulated Amortization 5,664 4,489
Net Properties under
Capital Lease $ 9,419 $ 8,071
Capital Lease Obligations:
Noncurrent Liability $7,064 $6,207
Liability Due Within One Year 2,355 1,864
Total Capital Lease Obligations $9,419 $8,071
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, 1995:
Non-
cancelable
Capital Operating
Leases Leases
(in thousands)
1996 $ 2,789 $ 522
1997 2,431 483
1998 1,797 276
1999 1,400 150
2000 910 88
Later Years 1,194 3
Total Future Minimum Lease Payments 10,521 $1,522
Less Estimated Interest Element 1,102
Estimated Present Value of
Future Minimum Lease Payments $ 9,419
10. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt was outstanding as follows:
December 31,
1995 1994
(in thousands)
First Mortgage Bonds:
5 1/8% due January 1, 1996 $ 29,436 $ 29,436
7.20% due December 1, 1999 35,000 35,000
8.95% due May 10, 2001 20,000 20,000
8.90% due May 21, 2001 40,000 40,000
7 7/8% due September 1, 2002 45,000 45,000
6.65% due May 1, 2003 15,000 15,000
6.70% due June 1, 2003 15,000 15,000
6.70% due July 1, 2003 15,000 15,000
7.90% due June 1, 2023 15,000 15,000
7.90% due June 1, 2023 25,000 25,000
Unamortized Discount (net) (765) (853)
Total 253,671 253,583
Junior Subordinated Deferrable
Interest Debentures
8.72% Series A
due June 30, 2025 40,000 -
Unamortized Discount (1,146) -
Total 38,854 -
Less Portion Due Within One Year 29,436 -
Total $263,089 $253,583
Certain first mortgage bond indentures contain improvement, maintenance and
replacement provisions requiring the deposit of cash or bonds with a trustee
or, in lieu thereof, certification of unfunded property additions.
At December 31, 1995 annual long-term debt payments, excluding premium and
discount, are as follows:
Principal Amount
(in thousands)
1996 $ 29,436
1997 -
1998 -
1999 35,000
2000 -
Later Years 230,000
Total $294,436
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, 1995 and 1994 were available in the amounts of $372 million and
$523 million, respectively. Commitment fees of approximately 1/8 of 1% of
the unused short-term lines of credit are paid each year to the banks to
maintain the lines of credit. Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1995:
Notes Payable $15,950 6.1%
Commercial Paper 11,100 6.1%
Total $27,050 6.1%
December 31, 1994:
Notes Payable $20,850 6.0%
Commercial Paper 34,300 6.6%
Total $55,150 6.3%
11. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1995 1994 1993
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $23,581 $20,604 $19,065
Income Taxes 6,453 7,606 3,149
Noncash Acquisitions under
Capital Leases were 3,651 3,339 2,560
12. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
1995
March 31 $85,302 $13,643 $7,815
June 30 72,699 8,562 2,547
September 30 79,532 12,171 6,000
December 31 90,611 14,645 8,766
1994
March 31 86,457 12,980 7,803
June 30 76,656 10,007 4,785
September 30 75,346 10,632 5,391
December 31 68,984 12,470 7,294