MANAGEMENT'S NARRATIVE ANALYSIS
OF RESULTS OF OPERATIONS
Net income for 1994 increased $7.2 million or 40.2% due mainly to
unseasonably severe weather in the first half of 1994 and reduced AEP System
Power Pool (Power Pool) capacity charges, resulting from a reduction in the
relative peak demand allocation ratio. Capacity costs are allocated to Power
Pool members based on their relative peak demands. A decrease in the
Company's prior twelve month peak demand relative to the total peak demand of
all Power Pool members caused capacity charges from the Power Pool to
decrease. The favorable effects on net income of the weather and reduced
capacity charges were partially offset by increased maintenance expense as a
result of severe ice storms in the first quarter and an increase in scheduled
steam plant maintenance.
Operating Revenues Increase
The increase in operating revenues can be analyzed as follows:
Increase From
(dollars in millions) Previous Year
Amount %
Retail:
Price variance . . . . . . . . . $ 0.5
Volume variance. . . . . . . . . 7.2
7.7 3.2
Wholesale:
Price variance . . . . . . . . . 2.4
Volume variance. . . . . . . . . 3.0
5.4 11.1
Other Operating Revenues . . . . . 0.1
Total. . . . . . . . . . . . . . $13.2 4.5
The increase in operating revenues was due to increased energy sales to
retail and wholesale customers reflecting the severe weather, increased
availability of the Company's generating units and a new wholesale power
supply agreement. The increase in energy sales to retail customers reflects
the effects of the weather on residential and commercial customers.
Wholesale energy sales increased due mainly to supplying additional energy to
the Power Pool as a result of the increased availability of Big Sandy Unit 2
during the second quarter and a new agreement with a wholesale customer to
supply its full energy requirements beginning in 1994. Previously the
Company provided only a back-up power supply to this wholesale customer.
Although the 800 megawatt Big Sandy Unit 2 was out of service for scheduled
maintenance in both 1994 and 1993, the 1994 outage occurred during the fall
when energy demand was reduced by mild weather in contrast to the 1993 outage
that took place during spring and early summer when energy needs were
greater.
Operating Expenses Increase
The significant changes in operating expenses that resulted in a $5.8
million increase in total operating expense were:
Increase From
(dollars in millions) Previous Year
Amount %
Maintenance . . . . . . . . . . . . . $3.3 11.4
Federal Income Taxes. . . . . . . . . 1.2 82.1
Maintenance expense increased due to repairs to distribution facilities
damaged by severe ice storms in January and February of 1994 and scheduled
boiler inspections and repairs at the Big Sandy Plant. In 1994 both units at
the Big Sandy Plant underwent planned boiler inspections and repairs whereas
in 1993 maintenance was performed only on Unit 2.
The increase in federal income taxes was primarily due to increased pre-
tax operating income offset in part by adjustments associated with the audit
of prior years' tax returns.
INDEPENDENT AUDITORS' REPORT
To the Shareowner and Board of
Directors of Kentucky Power Company:
We have audited the accompanying balance sheets of Kentucky Power Company as
of December 31, 1994 and 1993, and the related statements of income, retained
earnings, and cash flows for each of the three years in the period ended
December 31, 1994. 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,
1994 and 1993, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 21, 1995
STATEMENTS OF INCOME
Year Ended December 31,
1994 1993 1992
(in thousands)
OPERATING REVENUES $307,443 $294,252 $313,216
OPERATING EXPENSES:
Fuel 62,072 62,106 83,954
Purchased Power 94,565 94,806 91,787
Other Operation 39,237 38,688 35,529
Maintenance 31,967 28,687 22,231
Depreciation and Amortization 23,047 22,275 21,580
Taxes Other Than Federal Income Taxes 7,825 7,504 8,289
Federal Income Taxes 2,641 1,450 1,594
TOTAL OPERATING EXPENSES 261,354 255,516 264,964
OPERATING INCOME 46,089 38,736 48,252
NONOPERATING INCOME (LOSS) (102) 59 221
INCOME BEFORE INTEREST CHARGES 45,987 38,795 48,473
INTEREST CHARGES 20,714 20,764 21,936
NET INCOME $ 25,273 $ 18,031 $ 26,537
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1994 1993 1992
(in thousands)
RETAINED EARNINGS JANUARY 1 $85,296 $89,957 $84,771
NET INCOME 25,273 18,031 26,537
CASH DIVIDENDS DECLARED 21,396 22,692 21,351
RETAINED EARNINGS DECEMBER 31 $89,173 $85,296 $89,957
See Notes to Financial Statements.
BALANCE SHEETS
December 31,
1994 1993
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $224,365 $211,617
Transmission 258,178 249,966
Distribution 297,754 281,834
General 56,613 54,637
Construction Work in Progress 15,002 9,374
Total Electric Utility Plant 851,912 807,428
Accumulated Depreciation and Amortization 259,984 248,673
NET ELECTRIC UTILITY PLANT 591,928 558,755
OTHER PROPERTY AND INVESTMENTS 6,533 6,763
CURRENT ASSETS:
Cash and Cash Equivalents 879 858
Accounts Receivable:
Customers 19,144 18,385
Affiliated Companies 514 4,183
Miscellaneous 2,048 1,778
Allowance for Uncollectible Accounts (260) (208)
Fuel - at average cost 11,735 8,405
Materials and Supplies - at average cost 9,615 8,804
Accrued Utility Revenues 9,128 10,476
Prepayments 1,476 1,367
TOTAL CURRENT ASSETS 54,279 54,048
REGULATORY ASSETS 50,519 40,947
DEFERRED CHARGES 11,049 9,866
TOTAL $714,308 $670,379
See Notes to Financial Statements.
December 31,
1994 1993
(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 68,750 58,750
Retained Earnings 89,173 85,296
Total Common Shareowner's Equity 208,373 194,496
Long-term Debt 253,583 253,495
TOTAL CAPITALIZATION 461,956 447,991
OTHER NONCURRENT LIABILITIES 11,449 7,678
CURRENT LIABILITIES:
Short-term Debt 55,150 38,150
Accounts Payable - General 11,119 10,392
Accounts Payable - Affiliated Companies 8,301 8,064
Customer Deposits 4,297 4,621
Taxes Accrued 6,256 6,767
Interest Accrued 5,794 5,905
Other 14,467 8,186
TOTAL CURRENT LIABILITIES 105,384 82,085
DEFERRED FEDERAL INCOME TAXES 115,003 108,966
DEFERRED INVESTMENT TAX CREDITS 15,288 16,454
DEFERRED CREDITS 5,228 7,205
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $714,308 $670,379
STATEMENTS OF CASH FLOWS
Year Ended December 31,
1994 1993 1992
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 25,273 $ 18,031 $ 26,537
Adjustments for Noncash Items:
Depreciation and Amortization 23,124 22,358 21,667
Deferred Federal Income Taxes (1,239) (224) (3,140)
Deferred Investment Tax Credits (1,453) (1,528) (1,331)
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) 2,692 (1,953) 556
Fuel, Materials and Supplies (4,141) 449 8,857
Accrued Utility Revenues 1,348 2,228 (1,966)
Accounts Payable 964 2,000 (736)
Other (net) (247) (4,408) 3,287
Net Cash Flows From
Operating Activities 46,321 36,953 53,731
INVESTING ACTIVITIES:
Construction Expenditures (53,119) (35,247) (31,683)
Proceeds from Sales of Property 1,215 1,294 1,567
Net Cash Flows Used For
Investing Activities (51,904) (33,953) (30,116)
FINANCING ACTIVITIES:
Capital Contributions from
Parent Company 10,000 - -
Issuance of Long-term Debt - 84,115 34,527
Retirement of Long-term Debt - (85,885) (35,000)
Change in Short-term Debt (net) 17,000 21,250 (1,600)
Dividends Paid (21,396) (22,692) (21,351)
Net Cash Flows From (Used For)
Financing Activities 5,604 (3,212) (23,424)
Net Increase (Decrease) in
Cash and Cash Equivalents 21 (212) 191
Cash and Cash Equivalents January 1 858 1,070 879
Cash and Cash Equivalents December 31 $ 879 $ 858 $ 1,070
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. 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 member of the AEP System KPCo 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 and represent regulator
approved deferred expenses and revenues, respectively, resulting from the
rate-making process. Such deferrals are amortized commensurate with their
inclusion in rates (revenues).
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 average rates used to accrue
AFUDC were 4.5% in 1994, 4% in 1993 and 8% in 1992. The amounts of AFUDC
accrued were $482,000 in 1994, $265,000 in 1993 and $411,000 in 1992.
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%
Amounts to be used for removal of plant are recovered through depreciation
charges included in rates.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with original
maturities of three months or less.
Operating Revenues
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 non-utility 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 to match expenses and revenues in cost-
based rates. The assets are expected to be recovered in future periods
through the rate-making process and the liabilities are expected to reduce
future rate recoveries. The Company's regulatory assets and liabilities are
comprised of the following:
December 31,
1994 1993
Regulatory Assets:
Amounts Due From Customers for
Future Federal Income Taxes $45,186 $37,910
Other 5,333 3,037
Total Regulatory Assets $50,519 $40,947
Regulatory Liabilities:
Deferred Investment Tax Credits $15,288 $16,454
Other Regulatory Liabilities* 352 1,212
Total Regulatory Liabilities $15,640 $17,666
* Included in Deferred Credits on the Balance Sheets.
3. COMMITMENTS AND CONTINGENCIES:
Construction
Construction expenditures for the years 1995-1997 are estimated at $162
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.
Environmental Matters - Clean Air
The Clean Air Act Amendments of 1990 require, among other things,
significant reductions in sulfur dioxide and nitrogen oxide emissions from
various AEP System generating plants. The first phase of reduction 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 emissions requirements; however, a
portion of the costs of Phase I compliance of other AEP affiliates will be
incurred through the AEP System Power Pool (which is described in Note 5).
The compliance plan for the AEP System's generating units affected by Phase I
included installation of flue gas desulfurization systems (scrubbers) at the
two unit 2,600-mw Gavin Plant owned by an affiliate, Ohio Power Company and
switching from high-sulfur coal to an alternate fuel at other affiliated
units. Additional costs will be incurred to comply with Phase II
requirements at the Big Sandy Plant and those of affiliated Power Pool
members. If KPCo is unable to recover its share of the AEP System compliance
costs, it would have an adverse impact on results of operations.
Other Environmental Matters
KPCo is subject to regulation by federal, state and local authorities with
respect to air and water quality and other environmental matters. The
generation of electricity produces non-hazardous and hazardous by-products.
Asbestos, polychlorinated biphenyls (PCBs) and other hazardous materials have
been used in the Big Sandy Plant and transmission/distribution facilities.
Substantial costs to store and dispose of hazardous materials have been
incurred. Significant additional costs could be incurred in the future to
meet the requirements of new laws and regulations and to clean up disposal
sites under existing legislation. Management has no knowledge of any
material clean up costs related to the Company's past disposal of hazardous
and non-hazardous materials.
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 $8.9 million at December 31, 1994.
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
financial condition.
4. COMMON SHAREOWNER'S EQUITY:
The Company received from AEP Co., Inc. a cash capital contribution of $10
million in 1994 which was credited to paid-in capital. There were no other
transactions affecting common stock and paid-in capital accounts in 1994,
1993 and 1992.
Mortgage indentures place various restrictions on the use of retained
earnings for the payment of cash dividends on common stock. At December 31,
1994, $34.2 million of retained earnings were restricted. Regulatory
approval is required to pay dividends out of paid-in capital.
5. RELATED-PARTY TRANSACTIONS:
KPCo has a Unit Power 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 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,
1994 1993 1992
(in thousands)
Demand Charge $40,587 $41,995 $41,017
Energy Charge 28,711 24,626 30,588
Total $69,298 $66,621 $71,605
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 $31.6 million in 1994, $27.3 million in 1993 and
$43.9 million in 1992 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 energy were
included in purchased power expense as follows:
Year Ended December 31,
1994 1993 1992
(in thousands)
Capacity Charge $ 1,921 $ 5,490 $ 6,250
Energy Charge 18,103 20,870 11,630
Total $20,024 $26,360 $17,880
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 $19.9 million in 1994, $19.9 million in 1993 and $16.3 million
in 1992.
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 $5.2
million in 1994, $1.8 million in 1993 and $2.3 million in 1992. Revenues
from these transactions 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 in proportion to
the System companies' respective peak demands. Pursuant to the terms of the
agreement, other operating expense includes equalization credits of $4.3
million, $3.8 million and $4.2 million in 1994, 1993 and 1992, 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 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 contribution required by the Employee
Retirement Income Security Act of 1974.
Net pension plan costs for the years ended December 31, 1994, 1993 and
1992 were $1,046,000, $989,000 and $1,180,000, respectively.
An employee savings plan is offered which allows participants to
contribute up to 17% of their salaries into three 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 $718,000 in 1994, $658,000 in 1993 and $657,000 in 1992.
Certain other benefits are provided for retired employees under an AEP
System other post-retirement benefit 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 at retirement. Prior to 1993, net
costs of these benefits were recognized as an expense when paid and totaled
$373,000 in 1992.
SFAS 106, Employers' Accounting for Post-retirement Benefits Other Than
Pensions, was adopted in January 1993 for the Company's aggregate liability
for postretirement benefits other than pensions (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 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 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 both years.
A Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB
benefits was established and a corporate owned life insurance (COLI) program
was implemented. The insurance policies have a substantial cash surrender
value which is recorded, net of equally substantial policy loans, as other
property and investments. 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
1994 and $1.7 million in 1993 were made to the VEBA trust fund.
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, 1994 and 1993
the fair value of long-term debt was $240 million and $267 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 $253.6 million and
$253.5 million at December 31, 1994 and 1993, respectively.
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1994 1993 1992
(in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 5,097 $ 3,143 $ 5,969
Deferred (1,198) (424) (3,227)
Deferred Investment Tax Credits (1,258) (1,269) (1,148)
Total 2,641 1,450 1,594
Charged (Credited) to Nonoperating
Income (net):
Current (227) 229 (33)
Deferred (41) 200 87
Deferred Investment Tax Credits (195) (259) (183)
Total (463) 170 (129)
Total Federal Income Taxes as Reported $ 2,178 $ 1,620 $ 1,465
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,
1994 1993 1992
(in thousands)
Net Income $25,273 $18,031 $26,537
Federal Income Taxes 2,178 1,620 1,465
Pre-tax Book Income $27,451 $19,651 $28,002
Federal Income Taxes on Pre-tax Book
Income at Statutory Rate
(35% in 1994 and 1993; 34% in 1992) $ 9,608 $ 6,878 $ 9,521
Increase (Decrease) in Federal Income
Taxes Resulting From the Following
Items:
Depreciation (671) (491) (1,084)
Removal Costs (979) (979) (951)
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 (392) (396) (441)
Percentage Repair Allowance (428) (410) (361)
Corporate Owned Life Insurance (615) (236) (72)
Investment Tax Credits (net) (1,453) (1,528) (1,492)
Federal Income Tax Accrual Adjustment (1,100) - -
Other (437) 137 (2,300)
Total Federal Income Taxes as Reported $ 2,178 $ 1,620 $ 1,465
Effective Federal Income Tax Rate 7.9% 8.2% 5.2%
The following tables show the elements of the net deferred tax liability
and the significant temporary differences that gave rise to it:
December 31,
1994 1993
(in thousands)
Deferred Tax Assets $ 21,379 $ 22,900
Deferred Tax Liabilities (136,382) (131,866)
Net Deferred Tax Liabilities $(115,003) $(108,966)
Property Related Temporary
Differences $(101,889) $ (97,751)
Amounts Due From Customers For
Future Federal Income Taxes (15,815) (13,269)
All Other (net) 2,701 2,054
Total Net Deferred
Tax Liabilities $(115,003) $(108,966)
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
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 1988. Returns for 1988 through 1990 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. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt was outstanding as follows:
December 31,
1994 1993
(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) (853) (941)
Total $253,583 $253,495
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, 1994 annual long-term debt payments, excluding premium and
discount, are as follows:
Principal Amount
(in thousands)
1995 $ -
1996 29,436
1997 -
1998 -
1999 35,000
Later Years 190,000
Total $254,436
Short-term debt borrowings are limited by provisions of the 1935 Act to
$100 million. Lines of credit are shared with AEP System companies and at
December 31, 1994 and 1993 were available in the amounts of $523 million and
$511 million, respectively. Commitment fees of approximately 3/16 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:
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1994:
Notes Payable $20,850 6.0%
Commercial Paper 34,300 6.6
Total $55,150 6.3
December 31, 1993:
Notes Payable $26,250 3.5
Commercial Paper 11,900 3.8
Total $38,150 3.6
10. 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 primarily charged to operating expenses in accordance
with rate-making treatment. The components of rental costs are as follows:
Year Ended December 31,
1994 1993 1992
(in thousands)
Operating Leases $ 653 $1,179 $1,224
Amortization of Capital Leases 1,646 1,300 1,140
Interest on Capital Leases 459 376 372
Total Rental Costs $2,758 $2,855 $2,736
Properties under capital leases and related obligations recorded on the
Balance Sheets are as follows:
December 31,
1994 1993
(in thousands)
Electric Utility Plant:
Production $ 990 $ 671
General 11,570 9,494
Total Electric Utility Plant 12,560 10,165
Accumulated Amortization 4,489 3,558
Net Properties under Capital Lease $ 8,071 $ 6,607
Capital Lease Obligations:
Noncurrent Liability $6,207 $5,046
Liability Due Within One Year 1,864 1,561
Total Capital Lease Obligations $8,071 $6,607
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,
1994:
Non-
cancelable
Capital Operating
Leases Leases
(in thousands)
1995 $2,252 $ 624
1996 1,849 533
1997 1,552 483
1998 1,133 276
1999 907 150
Later Years 1,413 90
Total Future Minimum Lease Payments 9,106 $2,156
Less Estimated Interest Element 1,035
Estimated Present Value of
Future Minimum Lease Payments $8,071
11. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1994 1993 1992
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $20,604 $19,065 $21,168
Income Taxes 7,606 3,149 7,616
Noncash Acquistions under
Capital Leases were 3,339 2,560 3,390