Selected Consolidated Financial Data
Year Ended December 31,
1995 1994 1993 1992 1991
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,545,039 $1,535,500 $1,519,104 $1,410,778 $1,378,706
Operating Expenses 1,317,937 1,330,282 1,289,764 1,176,882 1,143,626
Operating Income 227,102 205,218 229,340 233,896 235,080
Nonoperating Income (Loss) (4,699) (4,716) (3,353) 3,036 1,132
Income Before Interest Charges 222,403 200,502 225,987 236,932 236,212
Interest Charges 106,503 98,157 100,855 105,513 95,793
Net Income 115,900 102,345 125,132 131,419 140,419
Preferred Stock Dividend Requirements 16,405 15,660 16,540 16,596 13,861
Earnings Applicable to Common Stock $ 99,495 $ 86,685 $ 108,592 $ 114,823 $ 126,558
December 31,
1995 1994 1993 1992 1991
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,558,436 $4,398,727 $4,193,700 $4,038,735 $3,884,833
Accumulated Depreciation and
Amortization 1,694,746 1,627,852 1,550,855 1,477,078 1,405,074
Net Electric Utility Plant $2,863,690 $2,770,875 $2,642,845 $2,561,657 $2,479,759
Total Assets $3,735,378 $3,647,795 $3,491,674 $3,094,091 $2,972,581
Common Stock and
Paid-in Capital $ 785,509 $ 764,866 $ 755,292 $ 741,509 $ 742,107
Retained Earnings 199,021 206,361 227,816 229,920 220,933
Total Common
Shareholder's Equity $ 984,530 $ 971,227 $ 983,108 $ 971,429 $ 963,040
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 55,000 $ 55,000 $ 55,000 $ 105,000 $ 105,000
Subject to Mandatory
Redemption (a) 190,235 190,385 160,537 108,509 65,662
Total Cumulative
Preferred Stock $ 245,235 $ 245,385 $ 215,537 $ 213,509 $ 170,662
Long-term Debt (a) $1,285,684 $1,228,911 $1,215,168 $1,200,272 $1,100,626
Obligations Under
Capital Leases (a) $ 48,937 $ 43,138 $ 29,973 $ 24,269 $ 19,801
Total Capitalization
and Liabilities $3,735,378 $3,647,795 $3,491,674 $3,094,091 $2,972,581
(a) Including portion due within one year.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Business Outlook
Since its enactment in 1992, the Energy Policy Act has fostered competition
in the generation and sale of electricity in the wholesale market. The
prospect for market driven rates is powering a movement, mainly among large
industrial energy users, to introduce competition to the retail market as
well. As a result management expects that competition will be a significant
factor influencing the Company s future results of operations.
A significant expansion of competition in the generation and sale of
electricity could result in an adverse effect on future results of operations
from stranded costs and the write-off of regulatory assets. Stranded costs
occur when a customer switches to a new supplier creating the issue of who
pays for investments and commitments that are no longer needed, economical or
recoverable in a competitive market. The amount of any losses the Company
may experience from stranded costs depends on the extent to which direct
competition is introduced to the Company s business and the market price of
energy. Cost-based regulation traditionally results in the recognition of
revenues and expenses in accordance with rate commission orders which can
result in revenue and expense recognition in different time periods than for
enterprises that are not regulated. As a result, regulatory assets have been
recorded by regulated utility companies representing the deferral of costs
for recovery in future periods. At December 31, 1995, the Company had $435
million of regulatory assets. In order to maintain regulatory assets, the
Company s rates must be cost-based regulated. Management has reviewed the
evidence currently available and concluded that the Company continues to meet
the requirements to apply rate-regulated accounting standards. In the event
a portion of the Company s business no longer met these requirements,
regulatory assets would have to be written off for that portion of the
business.
Whether future results of operations are adversely affected by losses or
write-offs will also depend on whether and how equitable recovery is provided
for by the applicable regulators. We intend to seek appropriate recovery of
any stranded costs and regulatory assets that may result from a transition to
competition.
The Company, as a member of the AEP System, has the financial strength,
geographic reach, location and cost structure to be an able competitor.
Although no assurance can be given that the Company can maintain this
position in the future, management is taking steps to prepare for the
challenges that increased competition will present. In 1995 management took
steps to prepare for competition by realigning the Company s operations,
along with the operations of the AEP System s other operating companies, into
functional operating units, expanding marketing and customer service efforts
and proposing a plan for an orderly transition to retail competition.
Management also proposed and filed open access transmission rates.
The realignment from separate operating company organizations to distinct
AEP System wide power generation and energy delivery operating units will
facilitate the unbundling of electric services to separate competitive
generation services from regulated transmission and distribution services.
It also should facilitate our ability to more efficiently and effectively
meet customer needs. Process improvement and cost control will be key
performance objectives for our new operating units.
In October of 1995 management proposed the creation of an Independent
System Operator to operate a multi-state transmission grid to facilitate
equal, safe and efficient transmission. Management also proposed the
eventual creation of a Regional Power Exchange that would accept offers to
buy and sell power and would settle transactions based on the price at which
supply and demand are balanced. Under the proposal regulators would continue
to regulate delivery services and provide for the recovery of any stranded
costs and regulatory assets through a wires charge.
Management has also offered access to AEP s extensive transmission grid at
142 interconnections to all parties under the same terms and conditions
available to the AEP System. This should provide the Company with greater
opportunities for transmission service revenues. Management has also
responded to our retail customers needs by introducing new cost-based
regulated rate designs (interruptible buy-through and real time pricing).
These proposals were issued to enable the Company to participate in a
meaningful way in the process of shaping the form of the future competitive
playing field. Should competition expand significantly, our success will
depend on our ability to obtain a level playing field, improve and expand on
our energy sales and services and maintain and improve on our relatively low
cost structure.
Environmental Concerns
Hazardous Material
By-products from the generation of electricity include materials such as
ash, slag and sludge. Coal combustion by-products, which constitute the
overwhelming percentage of these materials, are typically disposed of or
treated in captive disposal facilities or are beneficially utilized. In
addition, the generating plants and transmission and distribution facilities
have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and
non-hazardous materials. The Company is currently incurring costs to safely
dispose of such substances, and additional costs could be incurred to comply
with new laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund legislation) addresses clean-up of hazardous substances
at disposal sites and authorizes the United States Environmental Protection
Agency (Federal EPA) to administer the clean-up programs. As of year-end
1995, there are two sites for which the Company has received information
requests which could lead to Potentially Responsible Parties (PRP)
designation. Also, the Company has received an information request with
respect to one site administered by state authorities. APCO s liability has
been resolved for one other site with no significant effect on results of
operations. The Company's present estimates do not anticipate material
cleanup costs for identified sites for which APCo has been declared a PRP.
However, if for reasons not currently identified significant costs are
incurred for cleanup, future results of operations and possibly financial
condition would be adversely affected unless the costs can be recovered.
Results of Operations
Net Income Increases in 1995 After Declining in 1994
Net income increased by $13.6 million or 13% in 1995 while 1994 net
income decreased by $22.8 million or 18% due primarily to fluctuations in
AEP System Power Pool (Power Pool) capacity charges. The changes in Power
Pool capacity charges resulted from a reduction in 1995 and an increase in
1994 of the Company s prior twelve-month peak demand relative to the total
peak demand of all Power Pool members. Power Pool members like the Company
whose internal demand exceeds their capacity are allocated capacity costs
based on the relative peak demands and generating reserves of all Power Pool
members. Also contributing to the decrease in 1994 net income were severe
winter storm damage expenses, an increase in West Virginia business and
occupation taxes resulting from increased generation at West Virginia plants,
and increased charges under the AEP System transmission equalization
agreement.
Operating Revenues Increase and Energy Sales Increase
Operating revenues increased 1% in both 1995 and 1994 reflecting
increased energy usage by retail customers and growth in the numbers of
retail customers, and are analyzed as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1995 1994
Amount % Amount %
Retail:
Price variance . . . . $ 20.2 $ 7.9
Volume variance. . . . 39.3 2.6
Power Supply Costs . . (23.5) (5.4)
36.0 3.0 5.1 0.4
Wholesale:
Price variance . . . . (17.4) 23.9
Volume variance. . . . (1.8) (20.9)
Power Supply Costs . . (2.7) (.8)
(21.9) (7.5) 2.2 0.8
Other Operating Revenues (4.6) 9.1
Total . . . . . $ 9.5 0.6 $ 16.4 1.1
The moderate increase in 1995 operating revenues resulted from a 5%
increase in sales to retail customers partly offset by a reduction in
revenues from wholesale customers. Energy sales to residential customers,
which is the most weather-sensitive customer class, rose over 6% in 1995
mainly as a result of increased weather related usage in the last half of the
year reflecting unseasonably warm summer weather in 1995 and colder weather
in the fourth quarter of 1995 compared with the weather in the prior year.
Sales to commercial and industrial customers rose 6% and 2%, respectively,
reflecting the addition of 2,531 new customers, the effects of weather and
economic growth in the Company s service area.
Although revenues from wholesale customers declined 7.5%, energy sales were
only slightly down. Energy sales were relatively flat as an increase in
Power Pool sales made on an hourly basis to unaffiliated utilities were
offset by a decline in energy supplied to affiliated utilities through the
Power Pool due to the increased availability of lower cost nuclear generation
of an affiliate. Hourly sales are a type of short-term sale typically made
when the unaffiliated utility can purchase energy at a lower cost than the
cost at which that utility can generate the energy. Although wholesale
energy sales were relatively flat, wholesale revenues declined in 1995
reflecting increasing competition.
The slight increase in retail revenues in 1994 can be attributed to the
effect of a May 1993 rate increase in the Virginia retail jurisdiction.
Although wholesale energy sales decreased 7% in 1994, wholesale revenues
increased primarily due to an increase in take-or-pay capacity charges to
unaffiliated utilities. Take-or-pay capacity charges are to reserve a
specified quantity of generating capacity and must be paid even when the
energy is not taken.
Operating Expenses
Operating expenses decreased 1% in 1995 largely due to a decline in fuel
and purchased power expenses and increased 3% in 1994 reflecting
increases in most expense categories. Changes in the components of operating
expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1995 1994
Amount % Amount %
Fuel . . . . . . . . . $(42.1) (10.8) $ 8.2 2.2
Purchased Power. . . . (15.7) (5.0) 5.5 1.8
Other Operation. . . . 25.7 13.1 9.6 5.2
Maintenance. . . . . . 5.5 4.1 14.3 12.0
Depreciation and
Amortization . . . . 4.8 3.7 4.9 4.0
Taxes Other Than
Federal Icome Taxes. (2.4) (2.0) 6.7 6.0
Federal Income Taxes . 11.9 25.9 (8.7) (16.1)
Total. . . . . . . . $(12.3) (0.9) $40.5 3.1
The substantial decrease in 1995 fuel expense was due to a decrease in
coal-fired net generation while the increase in 1994 was caused by an
increase in generation. The changes in generation resulted from the
availability of an affiliate s low cost nuclear power units. When the
availability of the affiliate s nuclear units is reduced as it was in 1994,
the Company increases its generation for delivery to the Power Pool. Both
affiliated nuclear generating units were out of service in portions of 1994
for refueling while only one unit was out of service in 1995. Also
contributing to the decrease in 1995 fuel expense was a lower average cost of
fuel which resulted mainly from a reduction in coal prices due to the
renegotiation of certain long-term coal contracts.
Purchased power expense decreased in 1995 due to the reduction in Power
Pool capacity charges and reduced purchases from unaffiliated utilities for
pass-through sales to other unaffiliated utilities, reflecting the effects of
the milder winter weather in the first quarter of 1995 and cooler spring
weather, partially offset by increased purchases of Power Pool energy used to
meet increased retail demand rather than generating the energy. In 1994
purchased power expense increased as a result of the increased Power Pool
capacity charges.
The increase in other operation expense in 1995 was due to provisions for
severance pay related to an organizational review study and the AEP
realignment of operations; costs associated with the development of a new
activity based budgeting system; increased employee benefits costs; and the
effect of a $4.6 million favorable adjustment in 1994 which capitalized
previously expensed software costs in accordance with an order of the
Virginia regulatory commission. Other operation expense increased in 1994
primarily due to increased charges under the AEP System transmission
equalization agreement. Transmission charges are allocated based on the
relative peak demands in the prior twelve months. The increase in such
charges reflected the Company's January 1994 record peak demand.
Maintenance expense increased in 1995 as a result of the amortization of
deferred Virginia retail incremental storm damage expenses incurred to repair
distribution facilities damaged by two major ice storms in the first quarter
of 1994. Concurrent with rate recovery, being collected subject to refund,
the Company is amortizing over a three-year period the Virginia portion of
deferred storm damage expenses. A January 1994 snow storm, and two major ice
storms in February and March of 1994 significantly increased 1994 maintenance
expense. Storm damage expenditures in 1994 were $43.2 million of which $23.9
million was deferred.
Taxes other than federal income taxes increased in 1994 due to the effect
on the generation-based West Virginia business and occupation tax of the
increased generation at West Virginia plants. Effective June 1995, the tax
is based on generating capacity in West Virginia rather than on generation in
West Virginia which is expected to result in a less volatile level of West
Virginia taxes.
Federal income taxes attributable to operations increased in 1995 primarily
due to an increase in pre-tax operating income. Federal income taxes
attributable to operations decreased in 1994 mainly due to a decrease in pre-
tax operating income.
Nonoperating Loss
Nonoperating loss increased in 1994 due to the adoption of SFAS 112
"Employers' Accounting for Postemployment Benefits" by the Company's
subsidiaries, which were formerly engaged in coal-mining, and the effect of a
refund in 1993 of medical costs received by the inactive coal subsidiaries
from surplus funds in the Black Lung Trust Fund.
Interest Charges
Interest charges increased in 1995 primarily as a result of an increase in
the balance of long-term debt outstanding. Refinancing of long-term debt
during the early part of 1994 reduced the average interest rate on
outstanding long-term debt as well as the average levels of long-term debt
outstanding caused the decline in interest expense in 1994.
Financial Condition
Construction Spending
Total plant and property additions were $232 million in 1995 and $253
million in 1994. Management estimates construction expenditures for the next
three years to be $652 million with no major new generating plant
construction planned. Funds for construction of new facilities and
improvement of existing facilities come from a combination of internally
generated funds, short-term and long-term borrowings and equity investments
by the Company's parent, American Electric Power Company, Inc. (AEP Co.,
Inc.). Approximately 75% of the construction expenditures for the next three
years are expected to be financed internally.
Capital Resources
When necessary the Company generally issues short-term debt to provide for
interim financing of capital expenditures that exceed internally generated
funds. At December 31, 1995, $372 million of unused short-term lines of
credit shared with other AEP System companies were available. A charter
provision limits short-term borrowings to $228 million. Short-term
borrowings of $126 million at December 31, 1995 reflect a $3 million
increase. Periodic reductions of outstanding short-term debt are made
through issuances of long-term debt, preferred stock and equity capital
contributions by the parent company.
The Company has regulatory approval to issue up to $360 million of
long-term debt. Management expects to use the proceeds of future long-term
financings to retire short-term debt, refinance maturing and other long-term
debt, refund cumulative preferred stock and fund construction expenditures.
The Company presently exceeds all minimum coverage requirements for
issuance of mortgage bonds and preferred stock. The minimum coverage ratios
are 2.0 for mortgage bonds and 1.5 for preferred stock. At December 31,
1995, the mortgage bonds and preferred stock coverage ratios were 3.47 and
1.78, respectively.
Litigation
The Company is involved in a number of legal proceedings and claims. While
management is unable to predict the outcome of such litigation, it is not
expected that the resolution of these matters will have a material adverse
effect on the results of operations and/or financial condition.
Effects of Inflation
Inflation affects the Company s cost of replacing utility plant and the
cost of operating and maintaining its plant. The rate-making process limits
recovery to the historical cost of assets resulting in economic losses when
the effects of inflation are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
New Accounting Rules
The Financial Accounting Standards Board (FASB) issued a new accounting
standard, SFAS 121 Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of. The new standard is effective
beginning with 1996 accounting periods. The initial implementation of this
new standard is not expected to have a significant impact on the Company.
In 1996 the FASB issued an exposure draft Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets.
This document proposes that the present value of any decommissioning or
other closure or removal obligation be recorded as a liability when the
obligation is incurred. A corresponding asset would be recorded in the plant
investment account and recovered through depreciation charges over the
asset s life. A proposed transition rule would require that an entity report
in income the cumulative effect of initially applying the new standard. The
Company is currently studying the impact of the proposed rules and evaluating
its potential impact.
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Appalachian Power Company:
We have audited the accompanying consolidated balance sheets of Appalachian
Power Company and its subsidiaries as of December 31, 1995 and 1994, and the
related consolidated 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 consolidated financial statements present fairly, in all
material respects, the financial position of Appalachian Power Company and
its subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their 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
Consolidated Statements of Income
Year Ended December 31,
1995 1994 1993
(in thousands)
OPERATING REVENUES $1,545,039 $1,535,500 $1,519,104
OPERATING EXPENSES:
Fuel 348,776 390,864 382,633
Purchased Power 300,086 315,818 310,307
Other Operation 221,783 196,097 186,471
Maintenance 139,566 134,092 119,754
Depreciation and Amortization 132,999 128,192 123,306
Taxes Other Than Federal Income Taxes 117,093 119,458 112,739
Federal Income Taxes 57,634 45,761 54,554
Total Operating Expenses 1,317,937 1,330,282 1,289,764
OPERATING INCOME 227,102 205,218 229,340
NONOPERATING LOSS (4,699) (4,716) (3,353)
INCOME BEFORE INTEREST CHARGES 222,403 200,502 225,987
INTEREST CHARGES 106,503 98,157 100,855
NET INCOME 115,900 102,345 125,132
PREFERRED STOCK DIVIDEND REQUIREMENTS 16,405 15,660 16,540
EARNINGS APPLICABLE TO COMMON STOCK $ 99,495 $ 86,685 $ 108,592
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets
December 31,
1995 1994
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,857,621 $1,848,263
Transmission 1,041,415 1,010,344
Distribution 1,409,407 1,315,915
General 169,602 160,752
Construction Work in Progress 80,391 63,453
Total Electric Utility Plant 4,558,436 4,398,727
Accumulated Depreciation and Amortization 1,694,746 1,627,852
NET ELECTRIC UTILITY PLANT 2,863,690 2,770,875
OTHER PROPERTY AND INVESTMENTS 31,523 48,928
CURRENT ASSETS:
Cash and Cash Equivalents 8,664 5,297
Accounts Receivable:
Customers 126,613 108,785
Affiliated Companies 7,721 10,980
Miscellaneous 8,077 4,327
Allowance for Uncollectible Accounts (2,253) (830)
Fuel - at average cost 69,037 65,581
Materials and Supplies - at average cost 55,756 49,451
Accrued Utility Revenues 65,078 51,686
Prepayments 8,579 6,487
TOTAL CURRENT ASSETS 347,272 301,764
REGULATORY ASSETS 435,352 467,213
DEFERRED CHARGES 57,541 59,015
TOTAL $3,735,378 $3,647,795
See Notes to Consolidated Financial Statements.
December 31,
1995 1994
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Share $ 260,458 $ 260,458
Paid-in Capital 525,051 504,408
Retained Earnings 199,021 206,361
Total Common Shareholder's Equity 984,530 971,227
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 55,000 55,000
Subject to Mandatory Redemption 190,085 190,300
Long-term Debt 1,278,433 1,228,911
TOTAL CAPITALIZATION 2,508,048 2,445,438
OTHER NONCURRENT LIABILITIES 102,178 79,729
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 7,251 -
Short-term Debt 125,525 122,825
Accounts Payable - General 36,424 46,729
Accounts Payable - Affiliated Companies 45,800 46,983
Taxes Accrued 48,666 34,623
Customer Deposits 14,411 14,362
Interest Accrued 19,057 17,347
Other 75,303 63,663
TOTAL CURRENT LIABILITIES 372,437 346,532
DEFERRED INCOME TAXES 656,006 658,660
DEFERRED INVESTMENT TAX CREDITS 89,682 95,907
DEFERRED CREDITS 7,027 21,529
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $3,735,378 $3,647,795
Consolidated Statements of Cash Flows
Year Ended December 31,
1995 1994 1993
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 115,900 $ 102,345 $ 125,132
Adjustments for Noncash Items:
Depreciation and Amortization 134,485 130,694 125,847
Deferred Federal Income Taxes 647 17,355 (5,834)
Deferred Investment Tax Credits (5,465) (5,492) (5,468)
Deferred Power Supply Costs (net) (3,721) 9,356 22,100
Provision for Rate Refunds 15,224 (8,780) 18,654
Storm Damage Expense Amortization (Deferrals) 14,804 (21,741) (3,371)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (16,896) 7,600 (2,758)
Fuel, Materials and Supplies (9,761) (24,800) 62,608
Accrued Utility Revenues (13,392) 6,608 (11,598)
Accounts Payable (11,488) 25,554 (20,018)
Taxes Accrued 14,043 (17,505) 12,104
Other (net) 13,520 (3,192) 13,247
Net Cash Flows From Operating Activities 247,900 218,002 330,645
INVESTING ACTIVITIES:
Construction Expenditures (216,200) (230,531) (189,767)
Proceeds from Sales of Property 7,793 948 1,806
Net Cash Flows Used For Investing Activities (208,407) (229,583) (187,961)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 30,000 10,000 15,000
Issuance of Cumulative Preferred Stock - 29,574 108,783
Issuance of Long-term Debt 128,785 70,443 286,486
Retirement of Cumulative Preferred Stock (150) (152) (112,505)
Retirement of Long-term Debt (74,950) (58,236) (277,704)
Change in Short-term Debt (net) 2,700 83,325 (40,350)
Dividends Paid on Common Stock (106,836) (108,140) (110,696)
Dividends Paid on Cumulative Preferred Stock (15,675) (14,562) (16,573)
Net Cash Flows From (Used For)
Financing Activities (36,126) 12,252 (147,559)
Net Increase (Decrease) in Cash and Cash Equivalents 3,367 671 (4,875)
Cash and Cash Equivalents January 1 5,297 4,626 9,501
Cash and Cash Equivalents December 31 $ 8,664 $ 5,297 $ 4,626
See Notes to Consolidated Financial Statements.
Consolidated Statements of Retained Earnings
Year Ended December 31,
1995 1994 1993
(in thousands)
Retained Earnings January 1 $206,361 $227,816 $229,920
Net Income 115,900 102,345 125,132
322,261 330,161 355,052
Deductions:
Cash Dividends Declared:
Common Stock 106,836 108,140 110,696
Cumulative Preferred Stock:
4-1/2% Series 1,350 1350 1350
4.50% Series 16 22 30
5.90% Series 2,950 2,950 713
5.92% Series 3,552 3,552 1,066
6.85% Series 2,055 1,296 -
7.40% Series 1,850 1,850 1850
7.80% Series 3,900 3,900 3,900
8.12% Series - - 1,962
8.52% Series - - 1,372
9% Series - - 3,746
$2.65 Series - - 22
Total Cash Dividends
Declared 122,509 123,060 126,707
Capital Stock Expense 731 740 529
Total Deductions 123,240 123,800 127,236
Retained Earnings December 31 $199,021 $206,361 $227,816
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Appalachian Power Company (the Company or APCo) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public
utility holding company. The Company is engaged in the generation, purchase,
transmission and distribution of electric power to 859,000 retail customers
in southwestern Virginia and southern West Virginia. 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, APCo's facilities are
operated in conjunction with the facilities of certain other AEP affiliated
utilities as an integrated utility system.
The Company has four wholly-owned subsidiaries which are consolidated in
these financial statements: Cedar Coal Co., Central Appalachian Coal Company
and Southern Appalachian Coal Company (which were formerly engaged in coal
mining and now lease their coal reserves to unaffiliated companies) and West
Virginia Power Company (which is inactive). Kanawha Valley Power Company,
previously a wholly-owned subsidiary, which owned and operated hydroelectric
generating units and sold electricity to APCo, merged into the Company on
June 30, 1995.
Regulation
As a subsidiary of AEP Co., Inc., APCo is subject to the regulation of the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (1935 Act). Retail rates are regulated by the Virginia
State Corporation Commission (Virginia SCC) and the Public Service Commission
of West Virginia (WVPSC). The Federal Energy Regulatory Commission (FERC)
regulates wholesale rates.
Principles of Consolidation
The consolidated financial statements include APCo and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consol-
idation.
Basis of Accounting
As a cost-based rate-regulated entity, APCo's financial statements reflect
the actions of regulators that result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate
regulated. In accordance with Statement of Financial Accounting Standards
(SFAS) 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. In the Virginia jurisdiction, con-
struction work in progress is included in rate base in lieu of recording
AFUDC. The amounts of AFUDC in 1995, 1994 and 1993 were not significant.
Depreciation and Amortization
Depreciation is provided on a straight-line basis over the estimated
useful lives of utility plant and is calculated largely through the use of
composite rates by functional class as follows:
Functional Class Composite
of Property Annual Rates
Production:
Steam 3.6%
Hydro 2.5%
Transmission 2.2%
Distribution 3.5%
General 3.3%
Amounts to be used for demolition 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.
Power Supply Costs and Fuel Costs
The Company practices deferred accounting with respect to the over and
under collection of certain fuel and power supply costs pursuant to the
Virginia regulatory commission's fuel cost recovery mechanism. In the
Virginia jurisdiction, changes in fuel costs and the fuel portion of
purchased power costs are reviewed annually by the Virginia SCC. In the West
Virginia jurisdiction, deferral accounting for the over and under collection
of fuel and certain power supply costs incurred from November 1993 through
October 1996 has been suspended as a result of a three-year freeze on fuel
rates which is described in Note 3. Prior to November 1, 1993 deferred fuel
accounting was practiced in the West Virginia jurisdiction.
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 be-
tween 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
The Company's policy was to account for investment tax credits under the
flow-through method except where regulatory commissions reflected investment
tax credits in the rate-making process on a deferral basis. Commensurate
with rate treatment deferred investment tax credits are being amortized over
the life of the related plant investment.
Debt and Preferred Stock
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.
Commensurate with ratemaking, debt discount or premium and debt issuance
expenses are deferred and amortized over the term of the related debt, with
the amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are deferred,
debited to paid-in capital and amortized to retained earnings in accordance
with rate-making treatment. The excess of par value over costs of preferred
stock reacquired to meet sinking fund requirements is credited to paid-in
capital.
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 consolidated financial statements include assets and liabilities
recorded in accordance with regulatory actions in order to match expenses
with 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
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $379,104 $382,467
Unamortized Loss On
Reacquired Debt 26,075 25,621
Deferred Storm Damage 10,308 25,112
Other 19,865 34,013
Total Regulatory Assets $435,352 $467,213
Regulatory Liabilities:
Deferred Investment Tax
Credits $89,682 $ 95,907
Other* 2,645 7,075
Total Regulatory Liabilities $92,327 $102,982
* Included in Deferred Credits on Consolidated Balance Sheets.
3. RATE MATTERS:
As a result of certain significant fuel cost reductions, on November 15,
1994 the Company implemented, subject to refund, a net decrease in rates
charged to its Virginia retail customers of $13.2 million, subject to final
approval by the Virginia SCC. The net decrease consisted of a $28.9 million
decrease in the fuel component of its rates offset, in part, by an increase
of $15.7 million in base rates. On December 19, 1994, the Virginia SCC
issued an order approving the decrease in the fuel factor component of rates.
The increase in base rates would, in part, recover over three years the costs
of extensive repairs to facilities damaged by the severe winter storms in
1994. The Company deferred $23.9 million of Virginia retail incremental
storm damage expenses related to two major ice storms in February and March
of 1994. The Company proposed in this rate proceeding to amortize the
deferred storm damage expenses over a three-year period, consistent with the
amortization of previous storm damage expense deferrals approved in a 1992
rate case. The ultimate recovery of the entire deferred storm damage costs
is subject to Virginia SCC approval. If not approved, results of operations
would be adversely affected. A hearing was held in July 1995. The Company
is awaiting a final order from the Virginia SCC in this matter.
Under the terms of a 1993 settlement agreement, the Company agreed to a
base rate freeze in the West Virginia jurisdiction and suspension of the
WVPSC's Expanded Net Energy Cost (ENEC) recovery mechanism until October 31,
1996. Deferral accounting will not be used for new ENEC cost variances
incurred from November 1993 through October 1996. The ENEC actual under-
recovery balance on October 31, 1993 of $13.3 million is being collected
through a component of the revised ENEC rates over the three-year period
ending October 31, 1996. At December 31, 1995 the unrecovered ENEC balance
was $2.5 million.
Effective September 15, 1992 the FERC authorized the Company to implement,
subject to refund, an $8.7 million annual rate increase. The Company is
awaiting a final order from the FERC in this matter.
4. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made. Such commitments do
not include any expenditures for new generating capacity. The aggregate
construction program expenditures for 1996-1998 are estimated to be $652
million.
Long-term fuel supply contracts contain clauses that provide for periodic
price adjustments. The contracts are for various terms, the longest of which
extends to 2006, and contain various clauses that would release the Company
from its obligation under certain force majeure conditions. The Virginia
jurisdiction has a fuel cost recovery mechanism that provides, with the
regulators' review and approval, for deferral and subsequent recovery or
refund of changes in the cost of fuel. The Company agreed to freeze the fuel
cost recovery factor in the West Virginia jurisdiction for three years ending
October 31, 1996. (See Note 3).
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 Company s plants are not
affected by Phase I emission requirements. However, a portion of Phase I
compliance costs of other AEP affiliates is included in Power Pool costs
(which are described in Note 5) and charged to the Company. These costs are
not expected to have an adverse impact on results of operations.
Litigation
The Company 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.
5. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are shared by
members of the Power Pool. The Company is a member of the Power Pool. Under
terms of the System Interconnection Agreement, capacity charges and credits
are designed to allocate the cost of the System's capacity 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 $26.3 million in 1995, $32.3 million in 1994
and $33.4 million in 1993 for energy supplied to the Power Pool.
Charges for Power Pool capacity reservation and energy received were
included in purchased power expense as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Capacity Charges $116,821 $138,517 $111,335
Energy Charges 161,531 147,655 182,205
Total $278,352 $286,172 $293,540
Power Pool members share in wholesale sales to unaffiliated utilities made
by the Power Pool. The Company's share of the Power Pool's wholesale sales
included in operating revenues were $92 million in 1995, $103.8 million in
1994 and $96.7 million in 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 $18.8
million in 1995, $27.5 million in 1994 and $9 million in 1993. Revenues
from these transactions including a transmission fee are included in the
above Power Pool wholesale operating revenues.
Energy sold directly to Kingsport Power Company, an affiliated distribution
utility that is not a member of the Power Pool, was included in operating
revenues in the amounts of $58.7 million in 1995, $61.1 million in 1994 and
$61.8 million in 1993.
Purchased power expense includes $2.9 million in 1995, $2.1 million in 1994
and $7.8 million in 1993 of energy bought from the Ohio Valley Electric
Corporation, an affiliated company that is not a member of the Power Pool.
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 in proportion to
the System companies' respective peak demands. Pursuant to the terms of the
agreement, other operation expense includes equalization charges of $5.4
million, $10.2 million and $3.2 million in 1995, 1994 and 1993, respectively.
The Company and an affiliate, Ohio Power Company, jointly own two power
plants. The costs of operating these facilities are apportioned between the
owners based on ownership interests. The Company's share of these costs is
included in the appropriate expense accounts on the Consolidated Statements
of Income. The Company s investment in these plants is included in electric
utility plant on the Consolidated Balance Sheets.
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 capitalized or expensed 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:
The Company and its subsidiaries participate 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 costs for the years ended December 31, 1995, 1994 and 1993 were
$2.7 million, $5.3 million and $5.1 million, 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. The
Company's annual contributions totaled $4.3 million in 1995, $4.2 million in
1994 and $3.9 million 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 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 Company's
annual accrued costs for employees and retirees OPEBs required by SFAS 106,
which includes the recognition of one-twentieth of the prior service
transition obligation, were $19.5 million in 1995, $19.4 million in 1994 and
$18.6 million in 1993.
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 a 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 cost and SFAS 106 total OPEB cost. This
contribution is funded by amounts collected from ratepayers plus net earnings
from the COLI program. Contributions to the VEBA trust fund were $9.5
million in 1995, $11.6 million in 1994 and $5.6 million in 1993.
7. 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 $58,676 $28,779 $61,988
Deferred 1,715 19,763 (4,664)
Deferred Investment Tax Credits (2,757) (2,781) (2,770)
Total 57,634 45,761 54,554
Charged (Credited) to Nonoperating Income (net):
Current (503) (1,043) 995
Deferred (1,068) (2,408) (1,170)
Deferred Investment Tax Credits (2,708) (2,711) (2,698)
Total (4,279) (6,162) (2,873)
Total Federal Income Taxes as Reported $53,355 $39,599 $51,681
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 $115,900 $102,345 $125,132
Federal Income Taxes 53,355 39,599 51,681
Pre-tax Book Income $169,255 $141,944 $176,813
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35%) $ 59,239 $ 49,680 $ 61,885
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 14,184 11,103 8,912
Corporate Owned Life Insurance (5,304) (5,050) (6,170)
Removal Costs (5,040) (4,200) (4,742)
Percentage Repair Allowance (2,945) (2,813) (3,444)
Prior Year Federal Income Tax Accrual Adjustments - (3,100) (2,000)
Amortization of Deferred Investment Tax Credits (net) (5,465) (5,492) (5,468)
Other (1,314) (529) 2,708
Total Federal Income Taxes as Reported $ 53,355 $ 39,599 $ 51,681
Effective Federal Income Tax Rate 31.5% 27.9% 29.2%
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 $ 127,710 $ 99,000
Deferred Tax Liabilities (783,716) (757,660)
Net Deferred Tax Liabilities $(656,006) $(658,660)
Temporary Difference in Tax Dollars:
Property Related Temporary
Differences $(482,003) $(472,597)
Amounts Due From Customers For
Future Federal Income Taxes (110,529) (111,706)
Deferred State Income Taxes (63,307) (63,307)
All Other (net) (167) (11,050)
Total Net Deferred
Tax Liabilities $(656,006) $(658,660)
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliated companies in the AEP System.
The allocation of the AEP System's current consolidated federal income tax to
the System companies is in accordance with SEC rules under the 1935 Act.
These rules permit the allocation of the benefit of current tax losses to the
System companies giving rise to them in determining their current tax ex-
pense. 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 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.
8. LEASES:
Leases of property, plant and equipment are for periods of up to 30 years
and require payments of related property taxes, maintenance and operating
costs. The majority of the leases have purchase or renewal options and will
be renewed or replaced by other leases.
Lease rentals 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 $ 8,600 $ 9,490 $11,068
Amortization of
Capital Leases 11,003 8,878 5,186
Interest on Capital Leases 4,120 4,585 4,165
Total Rental Costs $23,723 $22,953 $20,419
Properties under capital leases and related obligations recorded on the
Consolidated Balance Sheets are as follows:
December 31,
1995 1994
(in thousands)
Electric Utility Plant:
Production $ 8,455 $ 9,180
Transmission 2 34
General 66,279 59,748
Total Electric Utility
Plant 74,736 68,962
Accumulated Amortization 25,799 25,824
Net Properties under
Capital Leases $48,937 $43,138
Capital Lease Obligations:
Noncurrent Liability $36,739 $32,984
Liability Due Within One Year 12,198 10,154
Total Capital Lease
Obligations $48,937 $43,138
Capital lease obligations are included in other non-current and other
current liabilities.
Properties under operating leases and related obligations are not included
in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at
December 31, 1995:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1996 $15,128 $ 5,335
1997 15,460 4,758
1998 11,168 3,344
1999 10,561 2,827
2000 8,919 2,063
Later Years 26,738 10,234
Total Future Minimum Lease Rentals 87,974 $28,561
Less Estimated Interest Element 39,037
Estimated Present Value of Future
Minimum Lease Payments $48,937
9. CUMULATIVE PREFERRED STOCK:
The authorized shares of no par value cumulative preferred stock is
8,000,000 shares. The aggregate involuntary liquidation price for all shares
of cumulative preferred stock may not exceed $300 million. The unissued
shares of the cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance.
The cumulative preferred stock is callable at the price indicated plus
accrued dividends. The involuntary liquidation preference is $100 per share.
During 1993 the Company redeemed and cancelled the following entire series:
300,000 shares of 8.12% series; 200,000 shares of 8.52% series; 570,000
shares of 9% series; and 32,900 shares of $2.65 series.
Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Outstanding December 31,
Series 1995 December 31, 1995 1995 1994
(in thousands)
4-1/2% $110.00 300,000 $30,000 $30,000
7.40% 102.11 250,000 25,000 25,000
$55,000 $55,000
Cumulative Preferred Stock Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Number of Shares Redeemed Outstanding December 31,
Series(a) 1995 Year Ended December 31, December 31, 1995 1995 1994
1995 1994 1993 (in thousands)
4.50% (b) $102.00 1,500 1,517 1,507 2,348 $ 235 $ 385
7.80% (c) 107.80 - - - 500,000 50,000 50,000
5.90% (d) (g) - - - 500,000 50,000 50,000
5.92% (e) (g) - - - 600,000 60,000 60,000
6.85% (f) (h) - - N/A 300,000 30,000 30,000
$190,235 $190,385
N/A - Not applicable, shares were issued in a subsequent year.
(a) The sinking fund provisions of series subject to mandatory redemption
aggregate $150,000 in 1996, $85,000 in 1997, $2,500,000 in 1998, $2,500,000
in 1999 and $8,500,000 in 2000.
(b) A sinking fund for the 4.50% cumulative preferred stock requires the
purchase or redemption of 1,500 shares at $100 a share on or before November 30
in each year. Unless all sinking fund provisions for this series have been
made, no distribution may be made on the common stock.
(c) Commencing in 1998, a sinking fund for the 7.80% cumulative preferred stock
will require the redemption of 25,000 shares at $100 a share on or before May 1
in each year. The Company has the non-cumulative option to redeem up to 25,000
additional shares on any sinking fund date at a redemption price of $100 per
share.
(d) Shares issued November 1993. Commencing in 2003 and continuing through the
year 2007, a sinking fund for the 5.90% cumulative preferred stock will require
the redemption of 25,000 shares each year and the redemption of the remaining
outstanding shares on November 1, 2008, in each case at $100 per share.
(e) Shares issued October 1993. Commencing in 2003 and continuing through the
year 2007, a sinking fund for the 5.92% cumulative preferred stock will require
the redemption of 30,000 shares each year and the redemption of the remaining
shares outstanding on November 1, 2008, in each case at $100 per share.
(f) Shares issued June 1994. Commencing in 2000 and continuing through date of
redemption, a sinking fund for the 6.85% cumulative perferred stock will
require the redemption of 60,000 shares each year, in each case at $100 per
share. The Company has the non-cumulative option to redeem up to 60,000
additional shares on any sinking fund date at a redemption price of $100
per share.
(g) Not callable until after 2002.
(h) Not callable until after 1999.
10. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1995 1994
(in thousands)
First Mortgage Bonds $1,044,555 $ 987,949
Installment Purchase
Contracts 233,877 233,706
Sinking Fund Debentures 7,252 7,256
1,285,684 1,228,911
Less Portion Due Within
One Year 7,251 -
Total $1,278,433 $1,228,911
First mortgage bonds outstanding were as follows:
December 31,
1995 1994
(in thousands)
% Rate Due
7-1/2 1998 - December 1 $ 45,000 $ 45,000
7.00 1999 - December 1 30,000 30,000
7-5/8 2002 - February 1 43,350 43,350
7.95 2002 - March 1 60,000 60,000
7.38 2002 - August 15 50,000 50,000
7-1/2 2002 - December 1 59,760 59,760
7.40 2002 - December 1 30,000 30,000
6.65 2003 - May 1 40,000 40,000
6.85 2003 - June 1 30,000 30,000
6.00 2003 - November 1 30,000 30,000
7.70 2004 - September 1 21,000 21,000
7.85 2004 - November 1 50,000 50,000
8.00 2005 - May 1 50,000 -
6.89 2005 - June 22 30,000 -
9-1/8 2019 - November 1 - 47,000
9-7/8 2020 - December 1 20,584 47,500
9.35 2021 - August 1 50,000 50,000
8.75 2022 - February 1 50,000 50,000
8.70 2022 - May 22 40,000 40,000
8.43 2022 - June 1 50,000 50,000
8.50 2022 - December 1 70,000 70,000
7.80 2023 - May 1 40,000 40,000
7.90 2023 - June 1 30,000 30,000
7.15 2023 - November 1 30,000 30,000
7.125 2024 - May 1 50,000 50,000
8.00 2025 - June 1 50,000 -
Unamortized Discount (net) (5,139) (5,661)
Total $1,044,555 $987,949
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into, in connection with
the issuance of pollution control revenue bonds by governmental authorities
as follows:
% Rate Due December 31,
1995 1994
(in thousands)
Industrial Development Authority of
Russell County, Virginia:
7-1/4% 1998 - November 1 $ 19,500 $ 19,500
7.70% 2007 - November 1 17,500 17,500
Putnam County, West Virginia:
5.45% 2019 - June 1 40,000 40,000
6.60% 2019 - July 1 30,000 30,000
Mason County, West Virginia:
7-7/8% 2013 - November 1 10,000 10,000
7.40% 2014 - January 1 30,000 30,000
6.85% 2022 - June 1 40,000 40,000
6.60% 2022 - October 1 50,000 50,000
Unamortized Discount (3,123) (3,294)
Total $233,877 $233,706
Under the terms of the installment purchase contracts, the Company is
required to pay amounts sufficient to enable the payment of interest on and
the principal (at stated maturities and upon mandatory redemptions) of
related pollution control revenue bonds issued to finance the construction of
pollution control facilities at certain plants.
Sinking fund debentures outstanding were as follows:
December 31,
1995 1994
(in thousands)
6% due 1996 - March 1 $7,251 $7,251
Unamortized Premium 1 5
Total $7,252 $7,256
At December 31, 1995, annual long-term debt payments, excluding premium or
discount, are as follows:
Principal Amount
(in thousands)
1996 $ 7,251
1997 -
1998 64,500
1999 80,000
2000 -
Later Years 1,142,194
Total $1,293,945
Short-term debt borrowings are limited by provisions of the 1935 Act to
$250 million and further limited by charter provisions to $228 million.
Lines of credit are shared with other AEP System companies and at December
31, 1995 and 1994 were available in the amounts of $372 million and $558
million, respectively. Commitment fees of approximately 1/8 of 1% of the
unused short-term line 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:
Commercial Paper $125,525 6.1%
December 31, 1994:
Notes Payable $ 2,425 6.3%
Commercial Paper 120,400 6.2
Total $122,825 6.2
11. COMMON SHAREHOLDER'S EQUITY:
The Company received from AEP Co., Inc. cash capital contributions of $30
million, $10 million and $15 million in 1995, 1994 and 1993, respectively,
which were credited to paid-in capital. In 1995, 1994 and 1993 net charges
to paid-in capital of $9,357,000, $426,000 and $1,217,000, respectively,
represented expenses of issuing and retiring cumulative preferred stock.
There were no other material transactions affecting common stock and paid-in
capital accounts in 1995, 1994 and 1993.
Mortgage indentures, debentures, charter provisions and orders of
regulatory authorities place various restrictions on the use of retained
earnings for the payment of cash dividends on common stock. At December 31,
1995, $33.2 million of the $199 million of retained earnings were restricted.
To pay dividends out of paid-in capital, the Company needs regulatory
approval.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash and cash equivalents, accounts receivable,
short-term debt and accounts payable approximate fair value because of the
short-term maturity of these instruments. At December 31, 1995 and 1994
fair values for preferred stock subject to mandatory redemption were $198
million and $169 million and for long-term debt were $1,350 million and
$1,157 million, respectively. The carrying amounts for preferred stock
subject to mandatory redemption were $190 million at December 31, 1995
and 1994 and for long-term debt were $1,286 million and $1,229 million at
December 31, 1995 and 1994, respectively. Fair values are based on quoted
market prices for the same or similar issues and the current dividend or
interest rates offered for instruments of the same remaining maturities.
13. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1995 1994 1993
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $102,145 $96,667 $103,387
Income Taxes 59,412 48,872 62,305
Noncash Acquisitions Under
Capital Leases were 16,209 22,883 11,403
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
1995
March 31 $407,516 $69,144 $41,937
June 30 339,957 38,839 8,486
September 30 403,786 55,361 28,378
December 31 393,780 63,758 37,099
1994
March 31 438,095 59,942 32,532
June 30 369,862 48,662 24,008
September 30 371,842 50,846 25,731
December 31 355,701 45,768 20,074
Net income for fourth quarter 1994 includes favorable federal income tax
accrual adjustments of $3.1 million related to the resolution of various
issues with the IRS.