Selected Consolidated Financial Data
Year Ended December 31,
1995 1994 1993 1992 1991
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,071,862 $1,031,151 $953,652 $843,996 $858,290
Operating Expenses 886,054 845,283 803,436 721,681 757,416
Operating Income 185,808 185,868 150,216 122,315 100,874
Nonoperating Income 5,202 7,030 27,343 47,170 54,999
Loss from Zimmer Plant Disallowance
(net of tax) - - 144,533 - -
Income Before Interest Charges 191,010 192,898 33,026 169,485 155,873
Interest Charges (net) 80,394 83,053 88,924 93,241 88,894
Net Income (Loss) 110,616 109,845 (55,898) 76,244 66,979
Preferred Stock Dividend Requirements 11,907 12,084 11,062 10,220 7,125
Earnings (Loss) Applicable
to Common Stock $ 98,709 $ 97,761 $ (66,960) $ 66,024 $ 59,854
December 31,
1995 1994 1993 1992 1991
BALANCE SHEETS DATA: (in thousands)
Electric Utility Plant $2,820,208 $2,729,577 $2,645,055 $2,724,506 $2,667,259
Accumulated Depreciation 953,170 884,237 811,817 754,367 693,085
Net Electric Utility Plant $1,867,038 $1,845,340 $1,833,238 $1,970,139 $1,974,174
Total Assets $2,594,126 $2,594,342 $2,582,671 $2,371,370 $2,297,357
Common Stock and Paid-in Capital $ 615,453 $ 606,668 $ 607,072 $ 607,072 $ 587,624
Retained Earnings 74,320 46,976 18,288 127,562 130,765
Total Common Shareholder's Equity $ 689,773 $ 653,644 $ 625,360 $ 734,634 $ 718,389
Cumulative Preferred Stock -
Subject to Mandatory Redemption (a) $ 82,500 $ 150,000 $ 125,000 $ 125,000 $ 75,000
Long-term Debt (a) $ 990,796 $ 997,608 $1,017,713 $ 977,921 $ 991,980
Obligations Under Capital Leases (a) $ 27,816 $ 24,452 $ 15,237 $ 9,951 $ 9,234
Total Capitalization and Liabilities $2,594,126 $2,594,342 $2,582,671 $2,371,370 $2,297,357
(a) Including portion due within one year.
MANAGEMENT'S NARRATIVE ANALYSIS OF
RESULTS OF OPERATIONS
Net Income Increases
Net income increased slightly in 1995 over 1994 due to decreased interest
expense as a result of refinancing of debt at lower interest rates and
postponement in the replacement of retired debt.
A favorable earnings impact from increased energy sales was offset by
corresponding increases in AEP System Power Pool (Power Pool) capacity
charges, property taxes, federal income taxes and severance charges in
connection with a realignment of operations.
Operating Revenues Increase
Operating revenues for 1995 increased $40.7 million or 3.9%. The
components of the change in revenues were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Retail:
Price Variance . . . . . . . . $ 4.2
Volume Variance. . . . . . . . 40.5
Fuel Cost Recoveries . . . . . (5.1)
39.6 4.2
Wholesale:
Price Variance . . . . . . . . (6.9)
Volume Variance. . . . . . . . 3.5
(3.4) (4.3)
Other Operating Revenues. . . . . 4.5
Total . . . . . . . . . . . . . $40.7 3.9
The increase in 1995 operating revenues resulted predominantly from a 5%
increase in energy sales to retail customers primarily due to increased
usage by and continued growth in the number of retail customers reflecting
the addition of 10,755 customers. Energy sales to residential customers,
which is the most weather-sensitive customer class, rose almost 8% in 1995
mainly as a result of increased usage in the last half of the year
reflecting unseasonably warm summer weather in 1995 and colder weather in
the fourth quarter of 1995 as compared to the prior year s fourth quarter.
Sales to commercial customers rose 4% reflecting the effects of weather, an
expanding economy and additional customers.
Although revenues from wholesale customers declined in 1995, wholesale
energy sales increased by more than 4% largely due to increased sales
made on an hourly basis by the AEP System Power Pool (Power Pool) to
unaffiliated utilities. This type of short-term sale is typically made
when the unaffiliated utility can purchase energy at a lower cost than the
cost at which that utility can generate the energy. Such sales usually
take place as a result of increased weather-related demand. The increase
in 1995 wholesale energy sales occurred during the last six months of the
year when the summer weather was unseasonably warm and fall temperatures
were colder as compared with the prior year. Although wholesale energy
sales increased, wholesale revenues declined in 1995 reflecting the impact
of increasing competition on pricing.
Operating Expenses Increase
Operating expenses increased $40.8 million or 4.8% in 1995. Changes in
the components of operating expenses were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Fuel. . . . . . . . . . . . . . . $(34.4) (16.9)
Purchased Power . . . . . . . . . 33.0 24.5
Other Operation . . . . . . . . . 15.4 8.8
Maintenance . . . . . . . . . . . (0.6) (0.9)
Depreciation. . . . . . . . . . . 2.3 2.7
Amortization of Zimmer Plant
Phase-in Costs. . . . . . . . . 6.1 22.6
Taxes Other Than Federal
Income Taxes. . . . . . . . . . 7.0 6.8
Federal Income Taxes. . . . . . . 12.0 25.6
Total Operating Expenses. . . . $40.8 4.8
The decrease in fuel expense was due to an 11% decrease in net generation
and the operation of the fuel clause adjustment mechanism as the
combination of the deferral of underrecovered fuel costs in 1995 and the
accrual of overrecovered fuel costs in 1994 reduced fuel expense. Net
generation decreased as the Company increased power purchases from the
Power Pool in order to substitute less expensive nuclear energy available
from the Power Pool for internally generated energy. The two nuclear units
of an affiliated Power Pool member company were out of service for
refueling and maintenance during portions of 1994 causing the Company to
increase generation in order to sell more power to the Power Pool to
replace the unavailable nuclear energy. This accounts for the decease in
generation even though the Company s energy sales increased.
Increased energy deliveries from the Power Pool and increased capacity
charges from the Power Pool accounted for the increase in purchased power
expense. As a Power Pool member whose internal demand exceeds its
capacity, the Company pays capacity charges allocated to Power Pool members
based on their relative peak demands. An increase in the Company s prior
twelve month peak demand relative to the total peak demand of all Power
Pool members caused the increase in Power Pool capacity charges.
Other operation expenses increased due to a provision for severance pay
recorded related mainly to the AEP System s functional realignment of
operations; the effect of a favorable adjustment in 1994 due to a reduction
in the estimate for injuries and damages claims; and membership dues as a
result of the Company joining the Electric Power Research Institute.
The increase in amortization of Zimmer Plant phase-in costs, which is
based on a rate per kilowatthour sold, reflects the rise in kilowatthour
sales and a full year of amortization in 1995 compared with a partial year
of amortization in 1994, the year deferrals began.
Taxes other than federal income taxes rose as a result of increased
property taxes reflecting higher tax rates and tax bases and increased
gross receipts taxes reflecting increased revenues.
Federal income tax expense attributable to operations increased primarily
due to the increase in pre-tax operating income and the effects of
favorable accrual adjustments recorded in 1994 in connection with the
resolution of the audits of prior years tax returns.
The retirement of long-term debt early in the second quarter and no
issuance of new debt until late in the third quarter caused the decline in
interest charges.
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Columbus Southern
Power Company:
We have audited the accompanying consolidated balance sheets of Columbus
Southern 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 Columbus Southern 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 $1,071,862 $1,031,151 $953,652
OPERATING EXPENSES:
Fuel 169,791 204,210 186,761
Purchased Power 167,517 134,540 159,979
Other Operation 190,542 175,102 170,397
Maintenance 71,022 71,629 71,537
Depreciation 85,448 83,180 84,883
Amortization (Deferral) of Zimmer Plant Phase-in Costs 33,268 27,144 (8,913)
Taxes Other Than Federal Income Taxes 109,680 102,672 99,348
Federal Income Taxes 58,786 46,806 39,444
TOTAL OPERATING EXPENSES 886,054 845,283 803,436
OPERATING INCOME 185,808 185,868 150,216
NONOPERATING INCOME:
Deferred Zimmer Plant Carrying
Charges (net of tax) 3,089 5,604 25,343
Other 2,113 1,426 2,000
TOTAL NONOPERATING INCOME 5,202 7,030 27,343
Loss From Zimmer Plant Disallowance:
Disallowed Cost - - 159,067
Related Income Taxes - - (14,534)
NET ZIMMER LOSS - - 144,533
INCOME BEFORE INTEREST CHARGES 191,010 192,898 33,026
INTEREST CHARGES 80,394 83,053 88,924
NET INCOME (LOSS) 110,616 109,845 (55,898)
PREFERRED STOCK DIVIDEND REQUIREMENTS 11,907 12,084 11,062
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 98,709 $ 97,761 $ (66,960)
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets
December 31,
1995 1994
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,481,309 $1,461,484
Transmission 314,413 306,744
Distribution 843,228 797,570
General 117,185 111,623
Construction Work in Progress 64,073 52,156
Total Electric Utility Plant 2,820,208 2,729,577
Accumulated Depreciation 953,170 884,237
NET ELECTRIC UTILITY PLANT 1,867,038 1,845,340
OTHER PROPERTY AND INVESTMENTS 25,950 26,744
CURRENT ASSETS:
Cash and Cash Equivalents 10,577 14,065
Accounts Receivable:
Customers 52,390 41,056
Affiliated Companies 4,465 4,624
Miscellaneous 10,059 10,025
Allowance for Uncollectible Accounts (1,061) (1,768)
Fuel - at average cost 24,316 28,060
Materials and Supplies - at average cost 23,519 24,923
Accrued Utility Revenues 40,389 31,595
Prepayments 32,116 31,241
TOTAL CURRENT ASSETS 196,770 183,821
REGULATORY ASSETS 438,005 475,019
DEFERRED CHARGES 66,363
63,418
TOTAL $2,594,126 $2,594,342
See Notes to Consolidated Financial Statements.
December 31,
1995 1994
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 574,427 565,642
Retained Earnings 74,320 46,976
Total Common Shareholder's Equity 689,773 653,644
Cumulative Preferred Stock -
Subject to Mandatory Redemption 75,000 150,000
Long-term Debt 990,796 917,608
TOTAL CAPITALIZATION 1,755,569 1,721,252
OTHER NONCURRENT LIABILITIES 34,571 38,913
CURRENT LIABILITIES:
Preferred Stock Due Within One Year 7,500 -
Long-term Debt Due Within One Year - 80,000
Short-term Debt 34,325 -
Accounts Payable - General 31,276 34,934
Accounts Payable - Affiliated Companies 20,753 14,057
Taxes Accrued 120,093 113,362
Interest Accrued 17,016 18,923
Other 30,955 24,469
TOTAL CURRENT LIABILITIES 261,918 285,745
DEFERRED INCOME TAXES 464,413 467,593
DEFERRED INVESTMENT TAX CREDITS 61,010 64,597
DEFERRED CREDITS 16,645 16,242
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $2,594,126 $2,594,342
Consolidated Statements of Cash Flows
Year Ended December 31,
1995 1994 1993
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $ 110,616 $ 109,845 $ (55,898)
Adjustments for Noncash Items:
Depreciation 85,071 82,795 84,462
Deferred Federal Income Taxes 2,914 (2,132) 10,167
Deferred Investment Tax Credits (3,483) (3,929) (5,471)
Deferred Fuel Costs (net) (11,377) 2,247 3,659
Deferred Zimmer Plant Operating Expenses and
Carrying Charges 29,150 19,156 (46,475)
Loss from Zimmer Plant Disallowance - - 159,067
Changes in Certain Currrent Assets and Liabilities:
Accounts Receivable (net) (11,916) (2,840) (8,030)
Fuel, Materials and Supplies 5,148 5,046 1,428
Accrued Utility Revenues (8,794) (2,706) (12,599)
Accounts Payable 3,038 (1,556) 3,336
Other (net) 6,212 (11,382) 886
Net Cash Flows From Operating Activities 206,579 194,544 134,532
INVESTING ACTIVITIES:
Construction Expenditures (98,356) (80,973) (88,605)
Proceeds from Sale and Leaseback
Transactions and Other 2,923 2,606 2,659
Net Cash Flows Used For Investing Activities (95,433) (78,367) (85,946)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company 15,000 - -
Issuance of Cumulative Preferred Stock - 24,596 -
Issuance of Long-term Debt 72,526 198,298 197,722
Retirement of Preferred Stock (71,773) - -
Retirement of Long-term Debt (80,000) (225,834) (166,166)
Change in Short-term Debt (net) 34,325 (25,225) (28,594)
Dividends Paid on Common Stock (71,900) (68,788) (42,175)
Dividends Paid on Cumulative Preferred Stock (12,812) (11,792) (11,062)
Net Cash Flows Used For Financing Activities (114,634) (108,745) (50,275)
Net Increase (Decrease) in Cash and Cash Equivalents (3,488) 7,432 (1,689)
Cash and Cash Equivalents January 1 14,065 6,633 8,322
Cash and Cash Equivalents December 31 $ 10,577 $ 14,065 $ 6,633
See Notes to Consolidated Financial Statements.
Consolidated Statements of Retained Earnings
Year Ended December 31,
1995 1994 1993
(in thousands)
Retained Earnings January 1 $ 46,976 $ 18,288 $127,562
Net Income (Loss) 110,616 109,845 (55,898)
157,592 128,133 71,664
Deductions:
Cash Dividends Declared:
Common Stock 71,900 68,788 42,175
Cumulative Preferred Stock:
7% Series 1,750 1,167 -
7-7/8% Series 3,937 3,938 3,937
9.50% Series 5,522 7,125 7,125
Total Cash Dividends Declared 83,109 81,018 53,237
Capital Stock Expense 163 139 139
Total Deductions 83,272 81,157 53,376
Retained Earnings December 31 $ 74,320 $ 46,976 $ 18,288
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Columbus Southern Power Company (the Company or CSPCo) 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 serving 599,000
retail customers in central and southern Ohio. 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, CSPCo's facilities are
operated in conjunction with the facilities of certain other AEP affiliated
utilities as an integrated utility system.
The Company's three wholly-owned subsidiaries, which are consolidated in
these financial statements, are: Conesville Coal Preparation Company (CCPC)
which provides coal washing services for one of the Company's generating
stations; Simco Inc. which is engaged in leasing a coal conveyor system to
CCPC; and Colomet, Inc. which is engaged in real estate activities for its
parent.
Regulation
As a subsidiary of AEP Co., Inc., CSPCo 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
Public Utilities Commission of Ohio (PUCO). The Federal Energy Regulatory
Commission (FERC) regulates wholesale rates.
Principles of Consolidation
The consolidated financial statements include CSPCo and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consol-
idation.
Basis of Accounting
As a cost-based rate-regulated entity, CSPCo'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. The amounts of AFUDC in 1995, 1994
and 1993 were not significant.
Depreciation
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 3.2%
Transmission 2.3%
Distribution 3.7%
General 3.6%
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.
Sale of Receivables
Under an agreement that expires in 2000, CSPCo can sell up to $50 million
of undivided interests in designated pools of accounts receivable and ac-
crued utility revenues with limited recourse. As collections reduce
previously sold pools, interests in new pools are sold. At December 31,
1995 and 1994, $50 million remained to be collected and remitted to the
buyer.
Operating Revenues
Revenues include the accrual of electricity consumed but unbilled at
month-end as well as billed revenues.
Fuel Costs
Changes in retail jurisdictional fuel cost are deferred until reflected
in revenues in later months through a PUCO fuel cost recovery 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
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
remaining term of the reacquired debt in accordance with rate-making
treatment. If the debt is refinanced the reacquisition costs are deferred
and amortized over the term of the replacement debt commensurate with their
recovery in rates.
Debt discount or premium and debt issuance expenses are 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.
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 AND THE ZIMMER
PHASE-IN PLAN:
The consolidated financial statements include assets and liabilities
recorded in accordance with regulatory actions in order to match expenses
with related revenues included in cost-based regulated rates. The assets
are expected to be recovered in future periods through the rate-making
process and the 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 $279,984 $286,079
Zimmer Plant Phase-in Plan
Deferrals 46,887 75,394
Deferred Zimmer Plant
Carrying Charges 43,003 43,003
Unamortized Loss On
Reacquired Debt 31,025 34,839
Other* 37,106 35,704
Total Regulatory Assets $438,005 $475,019
Regulatory Liabilities:
Deferred Investment Tax Credits $61,010 $64,597
Other* 12,351 13,123
Total Regulatory Liabilities $73,361 $77,720
* Included in Deferred Credits on the Consolidated Balance Sheets.
The Zimmer Plant is a 1,300 mw coal-fired plant which commenced
commercial operation in 1991. CSPCo owns 25.4% of the plant with the
remainder owned by two unaffiliated companies.
In May 1992 the PUCO issued an order providing for a phased-in rate
increase of $123 million for the new Zimmer Plant to be implemented in
three steps over a two-year period and disallowed $165 million of Zimmer
Plant investment. CSPCo appealed the PUCO ordered Zimmer disallowance and
phase-in plan to the Ohio Supreme Court. In November 1993 the Supreme
Court issued a decision on CSPCo's appeal affirming the disallowance and
finding that the PUCO did not have statutory authority to order phased-in
rates. The Court instructed the PUCO to fix rates to provide gross annual
revenues in accordance with the law and to provide a mechanism to recover
the revenues deferred under the phase-in order.
As a result of the ruling, 1993 net income was reduced by $144.5 million
after tax to reflect the disallowance and in January 1994, the PUCO
approved a 7.11% rate increase effective February 1, 1994. The increase is
comprised of a 3.72% base rate increase to complete the rate increase
phase-in and a temporary 3.39% surcharge, which will be in effect until the
deferred revenues are recovered, estimated to be 1998. In 1995 and 1994,
$28.5 and $18.5 million, respectively, of net phase-in deferrals were
collected through the surcharge which reduced the deferrals from $93.9
million at December 31, 1993 to $75.4 million at December 31, 1994 and
$46.9 million at December 31, 1995. In 1993 and 1992, $47.9 million and
$46 million, respectively, were deferred under the phase-in plan. The
recovery of amounts deferred under the phase-in plan and the increase in
rates to the full rate level did not affect net income.
From the in-service date of March 1991 until rates went into effect in
May 1992 deferred carrying charges of $43 million were recorded on the
Zimmer Plant investment. Recovery of the deferred carrying charges will be
sought in the next PUCO base rate proceeding in accordance with the PUCO
accounting order that authorized the deferral.
3. 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 $286
million.
Long-term fuel supply contracts contain clauses that provide for periodic
price adjustments. The PUCO has a fuel clause mechanism that provides for
deferral and subsequent recovery or refund of changes in the cost of fuel
with commission review and approval. The contracts are for various terms,
the longest of which extends to 2011, and contain various clauses that
would release the Company from its obligation under certain force majeure
conditions.
Clean Air
The Clean Air Act Amendments of 1990 (CAAA) 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. Several of the
Company s generating units are affected by Phase I. Also a portion of
Phase I compliance costs of other AEP affiliates is included in AEP System
Power Pool costs (which are described in Note 4) and charged to the
Company. These costs are not expected to have an adverse impact on results
of operations.
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.
4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the System's generating plants are shared by
members of the Power Pool. Under the terms of the System Interconnection
Agreement, capacity charges and credits are designed to allocate the cost
of the System's 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 $14.8 million in 1995, $15.8 million in 1994
and $12.5 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 $ 83,318 $ 74,936 $ 85,450
Energy Charges 74,100 46,164 68,277
Total $157,418 $121,100 $153,727
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 $45.8 million in 1995, $48.7
million in 1994 and $49.3 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 $10
million in 1995, $13.4 million in 1994 and $6.2 million in 1993. Revenues
from these transactions including a transmission fee are included in the
above Power Pool wholesale operating revenues.
AEP System companies participate in a transmission equalization agree-
ment. 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
$31.1 million, $30.1 million and $31.2 million in 1995, 1994 and 1993,
respectively.
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are billed by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the
use of equity capital, which is furnished to AEPSC by AEP Co., Inc.
Billings from AEPSC are 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.
5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employ-
ees 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 $0.8 million, $2.2 million and $2.5 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 and totaled $2.1 million in both 1995 and 1994 and
$1.9 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 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 obliga-
tion 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 employees and retirees OPEBs
required by SFAS 106, which includes the recognition of one-twentieth of
the prior service transition obligation, are being expensed as incurred and
were $11.3 million in 1995, $10.4 million in 1994 and $9.7 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. In 1995 the Company contributed $14.3 million to
the VEBA trust fund, an amount equal to the difference between the pay-as-
you-go OPEB cost and SFAS 106 total OPEB cost for 1995 and 1994. This
contribution was funded by amounts collected from ratepayers plus net
earnings from the COLI program.
6. COMMON OWNERSHIP OF GENERATING AND TRANSMISSION FACILITIES:
The Company jointly owns, as tenants in common, four generating units
and transmission facilities with two unaffiliated companies. Each of the
participating companies is obligated to pay its share of the costs of any
such jointly owned facilities in the same proportion as its ownership
interest. The Company's proportionate share of the operating costs
associated with such facilities is included in the Consolidated Statements
of Income and the amounts reflected in the accompanying Consolidated
Balance Sheets under utility plant include such costs as follows:
Company's Share
December 31,
1995 1994
Percent Utility Construction Utility Construction
of Plant Work Plant Work
Ownership in Service in Progress in Service in Progress
(in thousands)
Production:
W.C. Beckjord Generating Station (Unit No. 6) 12.5 $ 13,876 $ 13 $ 12,625 $1,137
Conesville Generating Station (Unit No. 4) 43.5 78,193 555 78,831 420
J.M. Stuart Generating Station 26.0 181,362 2,127 175,195 3,209
Wm. H. Zimmer Generating Station 25.4 696,661 2,403 695,990 1,797
$970,092 $5,098 $962,641 $6,563
Transmission (a) $ 59,208 $ -0- $ 58,813 $ 161
(a) Varying percentage of ownership.
At December 31, 1995 and 1994, the accumulated depreciation with respect to
the Company's share of jointly owned facilities amounted to $247.6 million
and $218.2 million, respectively.
7. CUMULATIVE PREFERRED STOCK:
At December 31, 1995, authorized shares of cumulative preferred stock
were as follows:
Par Value Shares Authorized
$100 2,500,000
25 7,000,000
The cumulative preferred stock outstanding shown below is subject to
mandatory redemption and has an involuntary liquidation preference of par
value.
Call Price Shares Amount
December 31, Par Outstanding December 31,
Series (a) 1995 Value December 31, 1995 1995 1994
(in thousands)
7% (b) (b) $100 250,000 $25,000 $ 25,000
7-7/8% (c) $107.88 100 500,000 50,000 50,000
9.50% (d) 100 75,000 7,500 75,000
$82,500 $150,000
(a) The sinking fund provisions of the 7% and 7-7/8% series aggregate
$2,500,000, $2,500,000 and $7,500,000 in 1998,1999 and 2000, respectively.
(b) Shares issued June 1994. Commencing in 2000, a sinking fund will
require the redemption of 50,000 shares at $100 a share on or before August
1 of each year. The Company has the right, on each sinking fund date, to
redeem an additional 50,000 shares. Redemption of this series is
prohibited prior to August 1, 2000.
(c) Commencing in 1998, a sinking fund will require the redemption of
25,000 shares at $100 a share on or before May 1 of each year. The Company
has the right, on each sinking fund date, to redeem an additional 25,000
shares. Redemption of this series is restricted prior to March 1, 1997.
(d)On November 1, 1995, 675,000 shares of the 9.50% Cumulative Preferred
Stock were redeemed at $106.33 per share. The remaining 75,000 shares were
redeemed on February 1, 1996 at $100.00 per share.
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $60,091 $56,424 $ 34,235
Deferred 2,028 (5,916) 8,935
Deferred Investment Tax Credits (3,333) (3,702) (3,726)
Total 58,786 46,806 39,444
Charged (Credited) to Nonoperating Income (net):
Current (874) (525) (4,777)
Deferred 886 3,784 14,559
Deferred Investment Tax Credits (150) (227) (538)
Total (138) 3,032 9,244
Credited to Loss from Zimmer Disallowance (net):
Deferred - - (13,327)
Deferred Investment Tax Credits - - (1,207)
Total - - (14,534)
Total Federal Income Taxes as Reported $58,648 $49,838 $ 34,154
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 (Loss) $110,616 $109,845 $(55,898)
Federal Income Taxes 58,648 49,838 34,154
Pre-tax Book Income (Loss) $169,264 $159,683 $(21,744)
Federal Income Taxes on Pre-tax Book Income (Loss) at
Statutory Rate (35%) $59,242 $55,889 $(7,610)
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Deferred Zimmer Plant Carrying Charges 3 3 928
Corporate Owned Life Insurance (2,882) (2,787) (3,351)
Depreciation 7,959 7,335 8,604
Zimmer Plant Disallowance - - 42,346
Prior Year Federal Income Tax Accrual Adjustments - (3,300) -
Amortization/Reversal of Deferred Investment
Tax Credits (net) (3,848) (3,929) (5,468)
Other (1,826) (3,373) (1,295)
Total Federal Income Taxes as Reported $58,648 $49,838 $34,154
Effective Federal Income Tax Rate 34.6% 31.2% N/A
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 $ 69,503 $ 74,752
Deferred Tax Liabilities (533,916) (542,345)
Net Deferred Tax Liabilities $(464,413) $(467,593)
Property Related Temporary
Differences $(337,349) $(330,434)
Amounts Due From Customers For
Future Federal Income Taxes (97,973) (100,128)
All Other (net) (29,091) (37,031)
Total Net Deferred
Tax Liabilities $(464,413) $(467,593)
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their 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 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.
9. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1995 1994 1993
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $78,046 $83,251 $88,141
Income Taxes 57,896 59,218 35,514
Noncash Acquisitions under
Capital Leases were 9,094 14,899 8,672
10. LEASES:
Leases of property, plant and equipment are for periods of up to 31
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 $ 7,684 $ 7,850 $ 8,873
Amortization of Capital
Leases 4,971 4,050 3,032
Interest on Capital Leases 1,547 1,092 763
Total Rental Costs $14,202 $12,992 $12,668
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 $ 1,952 $ 1,952
General 38,632 33,419
Total Electric Utility Plant 40,584 35,371
Other Property 1,838 1,167
Total Properties 42,422 36,538
Accumulated Amortization 14,606 12,086
Net Properties under
Capital Leases $27,816 $24,452
Obligations under Capital Leases:
Noncurrent Liability $22,981 $19,562
Liability Due Within One Year 4,835 4,890
Total Capital Lease
Obligations $27,816 $24,452
Capital lease obligations are included in other noncurrent 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 $ 6,304 $ 5,887
1997 5,419 5,624
1998 4,555 5,392
1999 3,972 5,045
2000 3,341 4,837
Later Years 9,981 11,525
Total Future Minimum Lease
Payments 33,572 $38,310
Less Estimated Interest Element 5,756
Estimated Present Value of
Future Minimum Lease Payments $27,816
11. COMMON SHAREHOLDER'S EQUITY:
The Company received from AEP Co., Inc. a cash capital contribution of
$15 million in 1995 which was credited to paid-in capital. In 1995 and
1994 net charges to paid-in capital of $6,215,000 and $404,000,
respectively, represented expenses of issuing and retiring cumulative
preferred stock. There were no other material transactions affecting the
common stock and paid-in capital accounts in 1995, 1994 and 1993. At
December 31, 1995 retained earnings was $74.3 million with no dividend
restrictions.
12. 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 $827,167 $856,767
Debentures 72,734 -
Installment Purchase Contracts 90,895 90,841
Notes Payable due 1995 - 50,000
990,796 997,608
Less Portion Due Within
One Year - 80,000
Total $990,796 $917,608
First mortgage bonds outstanding were as follows:
December 31,
1995 1994
(in thousands)
% Rate Due
8.95 1995 - December 20 $ - $ 30,000
6-1/4 1997 - October 1 14,640 14,640
9.15 1998 - February 2 57,000 57,000
7 1998 - June 1 24,750 24,750
9.31 2001 - August 1 30,000 30,000
7.95 2002 - July 1 40,000 40,000
7.25 2002 - October 1 75,000 75,000
7.15 2002 - November 1 20,000 20,000
6.80 2003 - May 1 50,000 50,000
6.60 2003 - August 1 40,000 40,000
6.10 2003 - November 1 20,000 20,000
6.55 2004 - March 1 50,000 50,000
6.75 2004 - May 1 50,000 50,000
9.625 2021 - June 1 50,000 50,000
8.70 2022 - July 1 35,000 35,000
8.40 2022 - August 1 15,000 15,000
8.55 2022 - August 1 15,000 15,000
8.40 2022 - August 15 40,000 40,000
8.40 2022 - October 15 15,000 15,000
7.90 2023 - May 1 50,000 50,000
7.75 2023 - August 1 40,000 40,000
7.45 2024 - March 1 50,000 50,000
7.60 2024 - May 1 50,000 50,000
Unamortized Discount (net) (4,223) (4,623)
827,167 856,767
Less Portion Due Within
One year - 30,000
Total $827,167 $826,767
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.
In September 1995 the Company issued $75 million of 8-3/8% Series A
Junior Subordinated Deferrable Interest Debentures due in 2025.
Installment purchase contracts have been entered into in connection with
the issuance of pollution control revenue bonds by the Ohio Air Quality
Development Authority as follows:
December 31,
1995 1994
(in thousands)
% Rate Due
6-3/8 2020 - December 1 $48,550 $48,550
6-1/4 2020 - December 1 43,695 43,695
Unamortized Discount (1,350) (1,404)
Total $90,895 $90,841
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 of related pollution control revenue bonds issued to finance
the Company's share of construction of pollution control facilities at the
Zimmer Plant.
At December 31, 1995 annual long-term debt payments, excluding premium or
discount, are as follows:
Principal Amount
(in thousands)
1996 $ -
1997 14,640
1998 81,750
1999 -
2000 -
Later Years 902,245
Total $998,635
Short-term debt borrowings are limited by provisions of the 1935 Act to
$175 million. Lines of credit are shared with AEP System companies and
at December 31, 1995 and 1994 were available in the amounts of $372
million and $518 million, respectively. Commitment fees of approximately
1/8 of 1% of the unused short-term lines of credit are paid each year to
the banks to maintain the lines of credit. At December 31, 1995
outstanding short-term debt consisted of $13.1 million of notes payable and
$21.2 million of commercial paper with year-end weighted average interest
rates of 6% and 6.1%, respectively.
13. 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 $88.8
million and $153 million, and for long-term debt were $1,032 million and
$921 million, respectively. The carrying amounts for preferred stock
subject to mandatory redemption were $82.5 million and $150 million, and
for long-term debt were $991 million and $998 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.
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
1995
March 31 $257,005 $44,437 $25,525
June 30 246,165 39,179 20,550
September 30 310,141 66,542 47,132
December 31 258,551 35,650 17,409
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
1994
March 31 $255,829 $43,468 $24,652
June 30 256,754 44,523 25,242
September 30 280,470 61,597 42,528
December 31 238,098 36,280 17,423 (a)
(a) Includes favorable federal income tax adjustments of
$3.3 million related to the resolution of various issues
with the IRS.