Selected Consolidated Financial Data
Year Ended December 31,
1996 1995 1994 1993 1992
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,911,708 $1,822,997 $1,738,726 $1,708,577 $1,691,597
Operating Expenses 1,614,547 1,550,837 1,493,853 1,440,390 1,439,826
Operating Income 297,161 272,160 244,873 268,187 251,771
Nonoperating Income 6,374 11,240 7,722 18,075 22,391
Income Before Interest Charges 303,535 283,400 252,595 286,262 274,162
Interest Charges 85,880 93,953 89,969 100,492 113,609
Net Income 217,655 189,447 162,626 185,770 160,553
Preferred Stock Dividend Requirements 8,778 14,668 15,301 16,990 17,115
Earnings Applicable to Common Stock $ 208,877 $ 174,779 $ 147,325 $ 168,780 $ 143,438
December 31,
1996 1995 1994 1993 1992
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,996,621 $4,915,222 $4,938,121 $4,802,327 $4,733,782
Accumulated Depreciation and
Amortization 2,216,534 2,091,148 2,077,626 1,992,082 1,916,011
Net Electric Utility Plant $2,780,087 $2,824,074 $2,860,495 $2,810,245 $2,817,771
Total Assets $4,092,166 $4,156,564 $4,151,140 $4,133,791 $3,722,354
Common Stock and Paid-in Capital $ 781,863 $ 780,675 $ 784,301 $ 784,301 $ 786,108
Retained Earnings 584,015 518,029 483,222 474,500 445,955
Total Common Shareholder's Equity $1,365,878 $1,298,704 $1,267,523 $1,258,801 $1,232,063
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 38,532 $ 41,240 $ 126,240 $ 126,240 $ 232,978
Subject to Mandatory Redemption (a) 109,900 115,000 115,000 115,000 -
Total Cumulative
Preferred Stock $ 148,432 $ 156,240 $ 241,240 $ 241,240 $ 232,978
Long-term Debt (a) $1,069,729 $1,227,632 $1,188,989 $1,194,483 $1,366,221
Obligations Under Capital
Leases (a) $ 131,285 $ 131,926 $ 127,735 $ 97,329 $ 96,168
Total Capitalization and Laibilities $4,092,166 $4,156,564 $4,151,140 $4,133,791 $3,722,354
(a) Including portion due within one year.
/TABLE
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Business Outlook
With the issuance of two Federal Energy Regulatory Commission
(FERC) orders and the commencement of planning for retail competition
at the state level, we are in a better position to identify and
develop strategies for addressing the issues that face the American
Electric Power (AEP) System, Ohio Power Company and our changing
industry. The industry's adjustment to greater competition in the
generation and sale of electricity, customer choice and the ability to
fully recover costs will probably be the most significant factors
affecting the Company's future profitability.
Although the Company, as a member of the AEP System, has the
financial strength, geographic reach, location and cost structure to
be an able competitor, no assurance can be given that this position
can be maintained. However, we intend to make every effort to
maintain and strengthen our competitive position. We see a link
between a smooth transition to a competitive marketplace and
maintaining a strong financial position.
The new FERC orders facilitate increased competition in both the
generation and sale of bulk power to wholesale customers. They
provide, among other things, for open access to transmission
facilities. AEP's support of the FERC's open access transmission rule
is evidenced by our being among the first to file a comparability
tariff, offering access to the AEP transmission grid at 143
interconnections to all parties under the same terms and conditions
available to AEP affiliates. This has provided greater opportunities
for transmission service sales.
Although customer choice proposals and discussions are under way
in Ohio, it is difficult to predict their result and the timing of
changes, if any. We are actively involved in discussions on the state
and federal level regarding whether to and how best to transition to
competition in order to represent the best interests of our customers,
shareholders and employees. We favor an orderly and smooth transition
to a more competitive energy market because we believe that AEP will
do better in the long term if it is free to compete.
If the electric energy market evolves from cost-of-service
ratemaking to market-based pricing, many complex issues must be
resolved, including the recovery of stranded costs. While the new
FERC orders provide, under certain conditions, for recovery of
stranded costs at the wholesale level, the issue of stranded cost
remains open at the much larger state retail level.
Stranded Costs
Stranded costs occur when a customer switches to a new supplier
for its electric energy needs or when a component of the business, for
example generation, is no longer subject to cost-based regulation,
creating the issue of who pays for plant investment, purchased power
or fuel contracts both non-affiliated and affiliated, inventories,
construction work in progress, plant removal and shutdown costs,
previously deferred costs (regulatory assets) and other investments
and commitments that are no longer needed, economic or recoverable in
a competitive market. The amount of any stranded costs the Company
may experience depends on the timing of and the extent to which direct
competition is introduced to our business and the then-existing market
price of energy.
Under the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (deferred revenues) are included in the consolidated
financial statements in accordance with regulatory actions to match
expenses and revenues in cost-based rates. In the event a portion of
the business no longer met the requirements of SFAS 71, net regulatory
assets would have to be written off for that portion of the business
and assets tested for possible impairment. Whether an impairment
exists would depend on how low the market price of energy is in
competition relative to the cost of energy.
Among other requirements the application of SFAS 71 requires that
the rates charged to customers be cost based. Our generation business
is still cost-based regulated and should remain so for the foreseeable
future. Should enabling state legislation be enacted we believe there
should be at least a three to five year transition to full
competition. Although the recent FERC orders provide for competition
in the firm wholesale market, that market is a relatively small part
of our business and our firm wholesale sales are still under
cost-of-service contracts. We believe that enabling state legislation if
enacted should provide for a sufficient transition period to allow for
the recovery of any generation-related stranded costs and we are
dedicating ourselves to working with regulators, customers and
legislators to accomplish both an orderly transition and a reasonable
and fair disposition of the stranded cost issue. However, if the
Company were to no longer be cost-based regulated and recovery of
stranded costs were not possible, results of operations and financial
condition would be adversely affected.
Since state commissions have jurisdiction over the sale and
distribution of electricity to retail customers, we believe that state
legislation and regulation should shape the future competitive market
for electricity while federal legislation should seek to ensure
reciprocity among the states and a level playing field for all power
suppliers. Presently states with higher cost power, like California,
are aggressively pursuing deregulation. However, Ohio is addressing
the call for customer choice more cautiously.
Restructuring/Functional Unbundling
In 1996 we took some major steps to maintain and enhance the
Company's competitive strength. We restructured our management and
operations to allow us to comply with the new FERC orders which
required separation of generation and energy sales operations from our
energy transmission and delivery operations. This has achieved and
should continue to achieve staffing, managerial and operating
efficiencies. The generation and marketing business units are
preparing for the possibility of competition in an open market for
customers. Our energy delivery business expects to remain regulated
and ultimately be subject to some form of incentive or performance-
based ratemaking. If competition never replaces regulation we will be
a more efficient and productive business as a result of our
preparations which should benefit all concerned.
Marketing and customer service efforts have been enhanced with
programs like the Key Accounts Program which strives to build strong
partnerships with key customers in order to build customer loyalty.
In 1996 we also launched a series of new television commercials to
inform our customers that we will be operating under the name,
American Electric Power. The commercials are intended to position AEP
as more than just a supplier of electricity. We want to be the energy
and energy services provider of choice; AEP: America's Energy Partner.
Cost Containment
In 1996 we continued our efforts to reduce costs in order to
maintain our competitiveness. Reviews of our major processes led to
decisions to consolidate the management and operations of internal
service functions performed at multiple locations. Among the
functions being consolidated are fossil generation plant maintenance,
system operations, accounting and load research. A study of the
Company's procurement and supply chain operations led to cost
reductions through better inventory management, just-in-time delivery
and the increased use of electronic purchasing. Also in 1996 we
completed the installation of an activity based management budgeting
system. This tool will enable managers to better analyze work and
control costs. While staff reductions and cost savings are being
achieved in these and other areas, expenses for new marketing
programs, customer services and modern efficient management
information systems are being increased to prepare for competition.
These expenditures for the future should produce further improvements
and efficiencies, enabling the Company to maintain its position as a
low-cost producer.
Fuel Costs
Coal is 80% of the production cost of electricity. Although our
coal costs per unit of electricity (per kwh) have declined we
recognize that we must continue to manage our coal costs to continue
to maintain our competitive position. Approximately 40% of the coal
we burn is supplied by affiliated mines; the remainder is acquired
under long-term contracts and in the spot market. As long-term
contracts expire we are negotiating with non-affiliated suppliers to
lower purchased coal costs. Efforts also continued in 1996 to reduce
the cost of affiliated coal. We intend to continue to prudently
supplement our long-term coal supplies with spot market purchases as
long as favorable spot market prices exist.
Affiliated Coal
In recent years the Company has been limited in its recovery of
the cost of coal produced by its affiliated mines in its Ohio
jurisdiction. Under the terms of a 1992 stipulation agreement the
cost of coal burned at the Gavin Plant is subject to a 15-year
predetermined price of $1.575 per million Btu's with quarterly
escalation adjustments through 2009. A 1995 Settlement Agreement set
the fuel component of the electric fuel component (EFC) factor at
1.465 cents per kwh for the period June 1, 1995 through November 30,
1998 and reserved certain issues including emission allowances for
later consideration in determining total fuel recovery. After
November 2009 the price that OPCo can recover for coal from its
affiliated Meigs mine, which supplies the Gavin Plant, will be limited
to the lower of cost or the then-current market price. The agreements
provide OPCo with an opportunity to accelerate recovery of its Ohio
jurisdictional investment in and liabilities and closing costs of the
Company s Meigs, Muskingum and Windsor mining operations to the extent
the actual cost of coal burned at the Gavin Plant is less than the
predetermined prices. Based on the estimated future cost of coal at
Gavin Plant, management believes that the Ohio jurisdictional portion
of the investment in and liabilities and closing cost of the
affiliated mining operations including deferred amounts will be
recovered under the terms of the predetermined price agreement.
Management intends to seek from ratepayers recovery of the non-Ohio
jurisdictional portion of the investment in and the liabilities and
closing costs of the Meigs, Muskingum and Windsor mines. The non-Ohio
jurisdictional portion of shutdown costs for these mines which
includes the investment in the mines, leased asset buyouts,
reclamation costs and employee benefits is estimated to be
approximately $180 million after tax at December 31, 1996. The
affiliated Muskingum and Windsor mines may have to close by January
2000 as part of the Company's efforts to comply with Phase II
requirements of the Clean Air Act Amendments of 1990 (CAAA). Should
it become apparent that the costs of the affiliated mines including
future mine closure costs will not be recoverable, the mines could be
closed and results of operations and possibly financial condition
adversely affected.
Environmental Matters
We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
Ohio Power has spent hundreds of millions of dollars to equip its
facilities with the latest economical clean air and water technologies
and to research possible new technologies. We are also proud of our
award winning efforts to reclaim our mining properties. We intend to
continue to take a leadership role to foster economically prudent
efforts to protect and preserve the environment.
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) 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 1996, OPCo is currently involved in
litigation with respect to three sites being overseen by the Federal
EPA and has been named by the Federal EPA as a "Potentially
Responsible Party" (PRP) for two other sites. There are three
additional sites for which the Company has received information
requests which could lead to PRP designation. OPCO s liability has
been resolved for a number of sites with no significant effect on
results of operations. The Company's present estimates do not
anticipate material cleanup costs for identified sites for which OPCo
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.
Federal EPA Actions
Federal EPA is required by the CAAA to issue rules to implement
the law. In December 1996 Federal EPA issued final rules governing
nitrogen oxide emissions that must be met after January 1, 2000 (Phase
II of the CAAA). The final rules will require substantial reductions
in nitrogen oxide emissions from certain types of power plant boilers
including those in the Company's power plants. In December 1996 a
group of utilities including the Company filed a petition for review
of the rules in a U.S. Court of Appeals and requested expedited
consideration of the appeal. The cost to comply with the emission
reductions required by the final rules is expected to be substantial
and could have a material adverse impact on results of operations and
possibly financial condition if not recovered from customers.
Federal EPA is considering proposals to revise the existing
ambient air quality standard for ozone and to establish a new ambient
air quality standard for fine particulate matter. The rules being
considered could result in further requirements for reductions of
nitrogen oxides and sulfur dioxide emitted from coal fired power
plants and could have a significant impact on operations. The
proposals being considered are of particular concern because they do
not have a sound scientific basis. The cost of complying with any new
emission reduction requirements imposed as a result of the adoption of
revised ambient air quality standards can not be precisely determined
but could be substantial. If Federal EPA ultimately promulgates
stricter ambient air quality standards, they could have a material
adverse impact on results of operations and possibly financial
condition if these costs are not recovered from customers.
Results of Operations
Net Income Increases
Net income increased 15% in 1996 primarily due to increased sales
of energy and services and reduced financing charges. Sales increased
due to increased wholesale energy sales to the AEP System Power Pool
(Power Pool) and unaffiliated utilities and increased services
provided to power marketers and other utilities. Also contributing to
the improvement in net income were severance pay charges recorded in
1995 in connection with realigning operations and management and gains
recorded in 1996 from emission allowance transactions. In 1995 net
income increased 16% primarily due to increased energy sales, the
favorable effect of an $8.3 million after tax adjustment to revenues
recorded in June 1995 under a major industrial contract and a retail
base rate increase in March of 1995. The increase in 1995's energy
sales was attributable to increased usage and new customers.
Operating Revenues and Energy Sales Increase
Operating revenues increased 5% in 1996 and 1995 reflecting
increased sales to retail and wholesale customers in both years. The
change in operating revenues is analyzed as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1996 1995
Amount % Amount %
Retail:
Price Variance. . . . .$ 7.9 $ 56.8
Volume Variance . . . . 3.4 32.2
Fuel Cost Recoveries. . 5.8 (13.8)
17.1 1.3 75.2 6.0
Wholesale:
Price Variance. . . . .(153.2) (17.2)
Volume Variance . . . . 220.4 26.3
Fuel Cost Recoveries. . 1.7 (3.5)
68.9 15.1 5.6 1.2
Other Operating Revenues. 2.7 7.3 3.5 10.5
Total . . . . . . . .$ 88.7 4.9 $ 84.3 4.8
Retail revenues increased in 1996 primarily due to a March 1995
increase in retail rates approved by the PUCO as part of the
Settlement Agreement which allowed recovery of CAAA compliance costs.
Revenues from residential and commercial customers each increased 3%
reflecting the rate increase. Industrial customer revenues were flat
as the positive effect of the rate increase on revenues was offset by
the effect of a favorable adjustment recorded in June 1995 under a
major industrial contract. Growth in the number of residential and
commercial customers also contributed to the increase in retail
operating revenues.
In 1996 wholesale revenues increased 15% while sales increased
48%. The Company's share of Power Pool allocated sales increased 100%
reflecting increased transactions with other utilities and power
marketers. During 1996 the Company through the Power Pool shared in
sales of a new product, coal conversion services which resulted in 1.8
billion kilowatthours of electricity being provided to power marketers
and certain other utilities under a new FERC-approved interruptible
tariff. Since these new sales are for the service of converting the
customers' coal to electricity and do not include recovery of a fuel
cost, the average wholesale price per kilowatt was significantly less
in 1996 than in 1995. Energy sales to the Power Pool increased 46%
reflecting increased weather-related demand of affiliated Power Pool
members in the first half of 1996 and the increased availability of
the Gavin Plant in 1996. Energy sales to the Power Pool are priced
to compensate the supplying Power Pool member for its out-of-pocket
costs. The Gavin units had been out-of-service for extended periods
during the first three months of 1995 while the flue gas
desulfurization systems (scrubbers) were being installed and
maintained.
The increase in 1995 operating revenues resulted primarily from
the retail rate increase in March of 1995, a revenue adjustment in
June 1995 on a major industrial contract, and a 3% increase in energy
sales to retail customers due to increased usage and growth in the
number of residential and commercial customers. Energy sales to
residential customers, which is the most weather-sensitive customer
class, rose 6% in 1995 mainly as a result of increased weather related
usage in the last half of the year. Sales to commercial and
industrial customers in 1995 rose 5% and 2%, respectively, reflecting
more than 1,600 new commercial customers, the effects of weather and
economic growth in the Company's service area.
Wholesale revenues increased in 1995 due to an increase in energy
supplied to the Power Pool reflecting increased weather-related energy
demand of affiliated members of the Power Pool during the last six
months of the year. The increase in revenues from Power Pool sales was
partially offset by decreased revenues from unaffiliated utilities in
1995. The decline in unaffiliated wholesale revenues resulted from a
decrease in direct sales to an unaffiliated utility reflecting the
return to service of that utility s generating unit which had been out
of service for a portion of 1994 for scheduled maintenance, and a
reduction in revenues from OPCo s share of Power Pool revenues. While
Power Pool revenues decreased, energy sales by the Power Pool
increased. The price related decrease in Power Pool revenues reflects
the increasing competition in the wholesale market.
Operating Expenses Increase
Operating expenses increased by approximately 4% in both 1996 and
1995. Changes in the components of operating expenses were as
follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1996 1995
Amount % Amount %
Fuel. . . . . . . . . . $31.2 5.1 $(66.4) (9.7)
Purchased Power . . . . 1.9 3.1 2.0 3.3
Other Operation . . . . (4.5) (1.4) 119.7 57.8
Maintenance . . . . . . 8.3 5.8 (6.3) (4.2)
Depreciation and
Amortization. . . . . 2.0 1.4 3.3 2.5
Taxes Other Than
Federal Income Taxes. (2.0) (1.2) (11.4) (6.3)
Federal Income Taxes. . 26.8 28.0 16.1 20.2
Total Operating
Expenses. . . . . . $63.7 4.1 $ 57.0 3.8
The increase in fuel expense in 1996 was due to a 7% increase in
generation to meet the increased demand for energy. The increased
availability of the Gavin units in 1996 enabled the Company to
increase generation.
Although generation increased 2% in 1995, fuel expense declined
mainly as a result of a decrease in the average cost of fuel consumed.
Coal prices declined in 1995 primarily due to renegotiation of certain
long-term coal contracts, lower priced purchases under existing and
new contracts and a reduction in affiliated coal prices from increased
productivity at the affiliated mines and the positive effect on
affiliated mining costs of the write-off of a dragline idled at a
subsidiary s strip mine in June 1994. Also contributing to the
decrease in 1995 fuel expense was the effect of a fuel cost
disallowance in 1994 connected with another drag line idled in 1993.
The significant increase in other operation expense in 1995 was
primarily due to rent and other operating costs of the newly installed
Gavin Plant scrubbers which went into service in December 1994 and
March 1995; a provision for severance pay recorded in 1995 related
mainly to a functional realignment of AEP System operations; and an
increase in employee benefit expenses due to the inclusion in cost of
service of previously deferred benefit costs.
Maintenance expense rose in 1996 as the level of maintenance
activity went up reflecting a full year's operation of the Gavin Plant
scrubbers and increased generation. Scheduled outages in 1994 for
boiler inspections and repairs at the generating units accounted for
the decrease in 1995 maintenance expense.
The decline in taxes other than federal income taxes in 1995 was
mainly due to the West Virginia business and occupation (B&O) tax
which was generation based through May 1995. Effective June 1995, the
West Virginia tax was based on generating capacity in West Virginia
rather than on generation in West Virginia resulting in lower taxes in
1995. Taxes other than federal income taxes will be less volatile due
to the change in methodology for computing the West Virginia B&O tax.
In 1996 and 1995 federal income tax expense attributable to
operations increased primarily due to an increase in pre-tax operating
income.
Interest Charges and Preferred Stock Dividends
In 1996 interest charges decreased due to a reduction in the
average outstanding balance of long-term debt and a decrease in
carrying charges recorded on deferred gains on the sale of emission
allowances.
Preferred stock dividend requirements decreased due to the
reacquisition of three series of preferred stock in November 1995.
Construction Spending
Total plant and property additions were $145 million in 1996 and
$154 million in 1995. Management estimates construction expenditures
for the next three years to be $572 million. 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 93% of
the construction expenditures for the next three years are expected to
be financed with internally generated funds.
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, 1996, $409 million of
unused short-term lines of credit shared with other AEP System
companies were available. Short-term debt borrowings are limited by
provisions of the Public Utility Holding Company Act of 1935 to $250
million. Periodic reductions of outstanding short-term debt are made
through issuances of long-term debt and preferred stock and
additional capital contributions by the parent company.
The Company's earnings coverage presently exceeds all minimum
coverage requirements for the 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, 1996, the mortgage bonds and
preferred stock coverage ratios were 6.62 and 3.63, respectively.
In January 1997 a tender offer was announced for all of the
Company's preferred stock in conjunction with a special meeting
scheduled to be held on February 28, 1997. The special meeting's
purpose is to consider amendments to the Company's articles of
incorporation to remove certain capitalization ratio requirements.
These restrictions limit the Company's financial flexibility and could
place it at a competitive disadvantage in the future. The amount paid
to redeem the preferred stock that is tendered could total as much as
$141 million. A combination of short-term debt and unsecured
long-term debt is expected to be used to pay for the preferred stock
tendered.
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 ultimate 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 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
the negative impact of inflation.
Corporate Owned Life Insurance
In connection with the audit of the AEP System's 1991, 1992 and
1993 consolidated federal income tax returns the Internal Revenue
Service (IRS) agents sought a ruling from the IRS National Office that
certain interest deductions relating to a corporate owned life
insurance (COLI) program should not be allowed. The Company
established the COLI program in 1990 as a part of its strategy to fund
and reduce the cost of medical benefits for retired employees. AEP
filed a brief with the IRS National Office refuting the agents'
position. Although no adjustments have been proposed, a disallowance
of the COLI interest deductions through December 31, 1996 would reduce
earnings by approximately $91 million (including interest).
Management believes it will ultimately prevail on this issue and will
vigorously contest any disallowance that may be assessed.
In 1996 Congress enacted legislation that prospectively phases
out the tax benefits for COLI interest deductions over a three-year
period beginning in 1996. As a result the Company intends to
restructure its COLI program. The restructuring of the COLI program
is not expected to have a material impact on results of operations.
New Accounting Rule
In 1996 the Financial Accounting Standards Board (FASB) issued an
exposure draft "Accounting for Certain Liabilities Related to Closure
or Removal of Long-Lived Assets." The Company generally records such
liabilities over the life of its plant commensurate with rate
recovery. The exposure draft proposes that the present value of
certain closure or removal obligations 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. However, as a cost-based
rate-regulated entity, the Company would expect to record a corresponding
regulatory asset for the cumulative effect of initially applying the
new standard. The FASB is reconsidering several aspects of the
exposure draft. It is unclear at this time what, if any, changes the
FASB will make to the proposal. Until it becomes apparent what the
FASB will decide and how certain questions raised by the exposure
draft are resolved the Company cannot determine its ultimate impact.
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Ohio Power Company:
We have audited the accompanying consolidated balance sheets of Ohio
Power Company and its subsidiaries as of December 31, 1996 and 1995,
and the related consolidated statements of income, retained earnings,
and cash flows for each of the three years in the period ended
December 31, 1996. 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 Ohio Power Company
and its subsidiaries as of December 31, 1996 and 1995, and the results
of their operations and their cash flows for each of the three years
in the period ended December 31, 1996 in conformity with generally
accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 25, 1997
Consolidated Statements of Income
Year Ended December 31,
1996 1995 1994
(in thousands)
OPERATING REVENUES $1,911,708 $1,822,997 $1,738,726
OPERATING EXPENSES:
Fuel 647,391 616,132 682,537
Purchased Power 63,862 61,945 59,956
Other Operation 322,567 327,026 207,292
Maintenance 152,495 144,202 150,568
Depreciation and Amortization 137,804 135,844 132,498
Taxes Other Than Federal Income Taxes 168,017 170,047 181,435
Federal Income Taxes 122,411 95,641 79,567
Total Operating Expenses 1,614,547 1,550,837 1,493,853
OPERATING INCOME 297,161 272,160 244,873
NONOPERATING INCOME 6,374 11,240 7,722
INCOME BEFORE INTEREST CHARGES 303,535 283,400 252,595
INTEREST CHARGES 85,880 93,953 89,969
NET INCOME 217,655 189,447 162,626
PREFERRED STOCK DIVIDEND REQUIREMENTS 8,778 14,668 15,301
EARNINGS APPLICABLE TO COMMON STOCK $ 208,877 $ 174,779 $ 147,325
See Notes to Consolidated Financial Statements.
/TABLE
Consolidated Statements of Cash Flows
Year Ended December 31,
1996 1995 1994
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 217,655 $ 189,447 $ 162,626
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 164,485 154,915 147,347
Deferred Federal Income Taxes 18,682 29,573 (9,471)
Deferred Investment Tax Credits (3,552) (3,570) (3,630)
Deferred Fuel Costs (net) (17,745) (26,213) (8,030)
Changes in Certain Current Assets and
Liabilities:
Accounts Receivable (net) (32,008) (41,631) 21,513
Fuel, Materials and Supplies 18,151 7,451 31,474
Accrued Utility Revenues 1,248 (11,325) 3,459
Accounts Payable (13,181) (19,852) (17,657)
Taxes Accrued 1,368 4,905 (11,570)
Other (net) 16,498 58,753 (18,500)
Net Cash Flows From Operating Activities 371,601 342,453 297,561
INVESTING ACTIVITIES:
Construction Expenditures (113,481) (122,132) (151,255)
Proceeds from Sales of Property and Other 8,756 4,241 46,202
Net Cash Flows Used For Investing
Activities (104,725) (117,891) (105,053)
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 82,331 48,906
Retirement of Cumulative Preferred Stock (6,788) (86,917) -
Retirement of Long-term Debt (160,486) (44,348) (54,733)
Change in Short-term Debt (net) 31,902 (7,835) (23,015)
Dividends Paid on Common Stock (142,856) (139,428) (138,468)
Dividends Paid on Cumulative Preferred Stock (8,645) (15,065) (15,301)
Net Cash Flows Used For Financing
Activities (286,873) (211,262) (182,611)
Net Increase (Decrease) in Cash and Cash
Equivalents (19,997) 13,300 9,897
Cash and Cash Equivalents January 1 44,000 30,700 20,803
Cash and Cash Equivalents December 31 $ 24,003 $ 44,000 $ 30,700
See Notes to Consolidated Financial Statements.
/TABLE
Consolidated Balance Sheets
December 31,
1996 1995
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,556,507 $2,534,893
Transmission 820,636 798,854
Distribution 872,936 833,944
General (including mining assets) 680,443 688,253
Construction Work in Progress 66,099 59,278
Total Electric Utility Plant 4,996,621 4,915,222
Accumulated Depreciation and Amortization 2,216,534 2,091,148
NET ELECTRIC UTILITY PLANT 2,780,087 2,824,074
OTHER PROPERTY AND INVESTMENTS 106,485 107,510
CURRENT ASSETS:
Cash and Cash Equivalents 24,003 44,000
Accounts Receivable:
Customers 118,551 125,710
Affiliated Companies 69,412 48,193
Miscellaneous 44,771 26,814
Allowance for Uncollectible Accounts (1,433) (1,424)
Fuel - at average cost 113,361 126,952
Materials and Supplies - at average cost 75,908 80,468
Accrued Utility Revenues 38,852 40,100
Prepayments 44,203 42,286
TOTAL CURRENT ASSETS 527,628 533,099
REGULATORY ASSETS 540,123 562,329
DEFERRED CHARGES 137,843 129,552
TOTAL $4,092,166 $4,156,564
See Notes to Consolidated Financial Statements.
/TABLE
December 31,
1996 1995
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 460,662 459,474
Retained Earnings 584,015 518,029
Total Common Shareholder's Equity 1,365,878 1,298,704
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 38,532 41,240
Subject to Mandatory Redemption 109,900 115,000
Long-term Debt 1,002,436 1,138,425
TOTAL CAPITALIZATION 2,516,746 2,593,369
OTHER NONCURRENT LIABILITIES 245,032 214,726
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 67,293 89,207
Short-term Debt 41,302 9,400
Accounts Payable - General 51,506 74,360
Accounts Payable - Affiliated Companies 37,893 28,220
Taxes Accrued 162,798 161,430
Interest Accrued 18,094 20,807
Obligations Under Capital Leases 24,153 25,172
Other 84,385 80,507
TOTAL CURRENT LIABILITIES 487,424 489,103
DEFERRED INCOME TAXES 738,626 731,959
DEFERRED INVESTMENT TAX CREDITS 46,308 49,860
DEFERRED CREDITS 58,030 77,547
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $4,092,166 $4,156,564
/TABLE
Consolidated Statements of Retained Earnings
Year Ended December 31,
1996 1995 1994
(in thousands)
Retained Earnings January 1 $518,029 $483,222 $474,500
Net Income 217,655 189,447 162,626
735,684 672,669 637,126
Deductions:
Cash Dividends Declared:
Common Stock 142,856 139,428 138,468
Cumulative Preferred Stock:
4.08% Series 189 204 204
4-1/2% Series 911 911 911
4.20% Series 235 252 252
4.40% Series 417 440 440
5.90% Series 2,587 2,655 2,655
6.02% Series 2,401 2,408 2,408
6.35% Series 1,905 1,905 1,905
7.60% Series - 2,564 2,660
7-6/10% Series - 2,564 2,660
8.04% Series - 1,162 1,206
Total Dividends 151,501 154,493 153,769
Capital Stock Expense 168 147 135
Total Deductions 151,669 154,640 153,904
Retained Earnings December 31 $584,015 $518,029 $483,222
See Notes to Consolidated Financial Statements.
/TABLE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Ohio Power Company (the Company or OPCo) 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 and provides electric power
to over 673,000 retail customers in northwestern, east central, eastern and
southern sections of Ohio. Wholesale electric power is supplied to
neighboring utility systems, power marketers and the American Electric Power
(AEP) System Power Pool (Power Pool). As a member of the Power Pool and a
signatory company to the AEP Transmission Equalization Agreement, OPCo's
facilities are operated in conjunction with the facilities of certain other
AEP affiliated utilities as an integrated system.
The Company has three wholly-owned coal-mining subsidiaries: Central Ohio
Coal Company (COCCo), Southern Ohio Coal Company (SOCCo) and Windsor Coal
Company (WCCo) which conduct mining operations at the Muskingum mine, Meigs
mine and Windsor mine, respectively. Substantially all coal produced by the
coal-mining subsidiaries is sold to the Company at cost including a
Securities and Exchange Commission (SEC) approved return on investment.
Regulation
As a subsidiary of AEP Co., Inc., the Company is subject to regulation by
the 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 OPCo and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consol-
idation.
Basis of Accounting
As a cost-based rate-regulated entity, the Company's consolidated
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 (deferred expenses) and
regulatory liabilities (deferred income) are recorded to reflect the economic
effects of regulation.
Use of Estimates
The preparation of these financial statements in conformity with generally
accepted accounting principles requires in certain instances the use of
management's estimates. Actual results could differ from those estimates.
Utility Plant
Electric utility plant is stated at original cost and is generally subject
to first mortgage liens. Additions, major replacements and betterments are
added to the plant accounts. Retirements from the plant accounts and
associated removal costs, net of salvage, are deducted from accumulated
depreciation. The costs of labor, materials and overheads incurred to
operate and maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash nonoperating income item that is recovered with
regulator approval over the service life of utility plant through
depreciation and represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 1996, 1995
and 1994 were not significant.
Depreciation, Depletion and Amortization
Depreciation of electric utility plant is provided on a straight-line
basis over the estimated useful lives of property other than coal-mining
property and is calculated largely through the use of composite rates by
functional class as follows:
Composite
Functional Class Depreciation
of Property Annual Rates
Production:
Steam-Fossil-Fired 3.4%
Hydroelectric-Conventional 2.7%
Transmission 2.3%
Distribution 4.0%
General 2.6%
Amounts to be used for removal of plant are recovered through depreciation
charges included in rates. Depreciation, depletion and amortization of
coal-mining assets are provided over each asset's estimated useful life,
ranging up to 30 years, and are calculated using the straight-line method for
mining structures and equipment. The units-of-production method is used to
amortize coal rights and mine development costs based on estimated recoverable
tonnages at a current average rate of $1.49 per ton. These costs are
included in the cost of coal charged to fuel expense.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with original
maturities of three months or less.
Operating Revenues
Revenues include the accrual of electricity consumed but unbilled at
month-end as well as billed revenues.
Fuel Costs
Changes in retail fuel cost are deferred until reflected in revenues
through a PUCO fuel cost recovery mechanism. The PUCO approved a February
1995 Settlement Agreement between OPCo and certain other parties which fixed
the fuel cost recovery rate factor at 1.465 cents per kwh through November of
1998 and reserved certain items including emission allowances for later
consideration in determining total fuel recovery. See Note 3. 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, deferred income taxes are
recorded with related regulatory assets and liabilities in accordance with
SFAS 71.
Investment Tax Credits
The Company's policy is 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. Deferred
investment tax credits, which represent a regulatory liability, are being
amortized over the life of the related plant investment commensurate with
recovery in rates.
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 included in 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
is credited to paid-in capital and amortized to retained earnings.
Other Property and Investments
Other property and investments are stated at cost.
2. EFFECTS OF REGULATION:
In accordance with SFAS 71 the consolidated financial statements include
assets (deferred expenses) and liabilities (deferred income) recorded in
accordance with regulatory actions to match expenses and revenues in cost-
based rates. Regulatory assets are expected to be recovered in future
periods through the rate-making process and regulatory liabilities are
expected to reduce future cost recoveries. Among other things SFAS 71
requires that the Company's rates be cost-based regulated. The Company has
reviewed all the evidence currently available and concluded that it continues
to meet the requirements to apply SFAS 71. In the event a portion of the
Company's business no longer meets those requirements net regulatory assets
would have to be written off for that portion of the business and assets
would have to be tested for possible impairment.
Regulatory assets and liabilities are comprised of the following at:
December 31,
1996 1995
(in thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $412,946 $420,697
Deferred Fuel Costs 28,538 13,887
Unamortized Loss On
Reacquired Debt 18,022 19,352
Other 80,617 108,393
Total Regulatory Assets $540,123 $562,329
Regulatory Liabilities:
Deferred Investment Tax Credits $46,308 $ 49,860
Deferred Gains From Emission
Allowance Sales* 39,706 55,229
Other* 10,034 11,630
Total Regulatory Liabilities $96,048 $116,719
*Included in Deferred Credits on Consolidated Balance Sheets.
3. RATE MATTERS:
Recovery of Fuel Costs
Under the terms of a 1992 stipulation agreement the cost of coal burned at
the Gavin Plant is subject to a 15-year predetermined price of $1.575 per
million Btu's with quarterly escalation adjustments through November 2009. A
1995 Settlement Agreement set the fuel component of the electric fuel
component (EFC) factor at 1.465 cents per kwh for the period June 1, 1995
through November 30, 1998 and reserved certain items including emission
allowances for later consideration in determining total fuel recovery. The
PUCO ordered the amortization of the Ohio jurisdictional share of gains on the
sale of emission allowances through the EFC rate effective December 1, 1996.
The agreements provide OPCo with the opportunity to recover over the term of
the stipulation agreement the Ohio jurisdictional share of OPCo's investment in
and the liabilities and future shutdown costs of its affiliated mines as well
as any fuel costs incurred above the fixed rate to the extent the actual cost
of coal burned at the Gavin Plant is below the predetermined price. After
November 2009 the price that OPCo can recover for coal from its affiliated
Meigs mine which supplies the Gavin Plant will be limited to the lower of cost
or the then-current market price. Pursuant to these agreements the Company
has deferred $28.5 million for future recovery at December 31, 1996.
Based on the estimated future cost of coal burned at Gavin Plant,
management believes that the Ohio jurisdictional portion of the investment in
and liabilities and closing costs of the affiliated mining operations including
deferred amounts will be recovered under the terms of the predetermined price
agreement. Management intends to seek from ratepayers recovery of the non-Ohio
jurisdictional portion of the investment in and the liabilities and closing
costs of the affiliated Meigs, Muskingum and Windsor mines. The non-Ohio
jurisdictional portion of shutdown costs for these mines which includes the
investment in the mines, leased asset buyouts, reclamation costs and employee
benefits is estimated to be approximately $180 million after tax at December
31, 1996.
The affiliated Muskingum and Windsor mines may have to close by January
2000 in order to comply with the Phase II requirements of the Clean Air Act
Amendments of 1990 (CAAA). The Muskingum and/or Windsor mines could close prior
to January 2000 depending on the economics of continued operation under the
terms of the above Settlement Agreement. Unless future shutdown costs and/or
the cost of affiliated coal production of the Meigs, Muskingum and Windsor mines
can be recovered, results of operations and possibly financial condition would
be adversely affected.
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 1997-1999 are estimated to be $572
million.
In addition to fuel acquired from coal-mining subsidiaries and spot-
markets, the Company has long-term fuel supply contracts with unaffiliated
companies. The contracts generally contain clauses that provide for periodic
price adjustments. The Company's retail jurisdictional fuel clause mechanism
provides, with the PUCO's review and approval, for deferral and subsequent
recovery or refund of changes in the cost of fuel. (See Note 3 for changes in
the fuel clause mechanism resulting from the Settlement and Stipulation
Agreements.) The unaffiliated contracts are for various terms, the longest of
which extends to 2012, and contain clauses that would release the Company from
its obligation under certain force majeure conditions.
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 System's generating plants are shared by members
of the Power Pool. The Company is a member of the Power Pool. Under the terms
of the System Interconnection Agreement, capacity charges and credits are
designed to allocate the cost of the System's 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. The Company is a net supplier to the pool and, therefore, receives
capacity credits from the Power Pool.
Operating revenues includes revenues for capacity and energy supplied to
the Power Pool as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Capacity Revenues $158,599 $147,317 $127,928
Energy Revenues 152,909 132,604 133,189
Total $311,508 $279,921 $261,117
Purchased power expense includes charges of $31.1 million in 1996, $26.6
million in 1995 and $20.9 million in 1994 for energy received from the Power
Pool.
Power Pool members share in wholesale sales to unaffiliated entities made
by the Power Pool. The Company's share of the Power Pool's wholesale sales
included in operating revenues were $106.1 million in 1996, $94 million in 1995
and $98.4 million in 1994.
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 $11.8 million in
1996, $15.6 million in 1995 and $21.7 million in 1994. Revenues from these
transactions including a transmission fee are included in the above Power Pool
wholesale operating revenues.
Purchased power expense includes $5 million in 1996, $2.9 million in 1995
and $2.1 million in 1994 for energy bought from the Ohio Valley Electric
Corporation, an affiliated company that is not a member of the Power Pool.
Operating revenues include energy sold directly to Wheeling Power Company
in the amounts of $57.1 million in 1996, $55.2 million in 1995 and $56.8 million
in 1994. Wheeling Power Company is an affiliated distribution utility 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 $12.5
million, $13.7 million and $14.3 million in 1996, 1995 and 1994, respectively.
Coal-transportation costs paid to affiliated companies aggregate
approximately $8.6 million, $4.3 million and $7.9 million in 1996, 1995 and
1994, respectively. These charges are included in fuel expense. The prices
charged by the affiliates for coal transportation services are computed in
accordance with orders issued by the SEC.
The Company and an affiliate, Appalachian 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 and the investment 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:
AEP System Pension Plan
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employees
meeting eligibility requirements, except participants in the United Mine Workers
of America (UMWA) pension plans. Benefits are based on service years and
compensation levels. Pension costs are allocated by first charging each
participating AEP 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. The Company's share
of net pension cost of the AEP System pension plan for the years ended December
31, 1996, 1995 and 1994 was $4.1 million, $2.4 million and $5.8 million,
respectively.
AEP System Savings Plan
An employee savings plan is offered to non-UMWA employees 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 employer's annual contributions totaled $4 million in 1996,
$4.4 million in 1995 and $4.3 million in 1994.
UMWA Pension Plans
The Company's coal-mining subsidiaries provide UMWA pension benefits for
UMWA employees meeting eligibility requirements. Benefits are based on age at
retirement and years of service. As of June 30, 1996, the UMWA actuary
estimates that the OPCo coal-mining subsidiaries' share of the UMWA pension
plans unfunded vested liabilities was approximately $26 million. In the event
the coal-mining subsidiaries cease or significantly reduce mining operations or
contributions to the UMWA pension plans, a withdrawal obligation may be
triggered for all or a portion of their share of the unfunded vested liability.
Contributions to the UMWA pension fund are based on the number of hours worked,
are expensed when paid and totaled $1.5 million in 1996, $1.4 million in 1995
and $1.6 million in 1994.
Postretirement Benefits Other Than Pensions (OPEB)
The AEP System provides certain other benefits for retired employees.
Substantially all non-UMWA employees are eligible for postretirement health care
and life insurance if they retire from active service after reaching age 55 and
have at least 10 service years.
Postretirement medical benefits for UMWA employees who have or will retire
after January 1, 1976 are the liability of the coal-mining subsidiaries.
Eligibility for postretirement medical benefits is based on retirement from
active service after reaching age 55 with at least 10 service years. In
addition, non-active UMWA employees will become eligible at age 55 if they have
had 20 service years.
The funding policy for OPEB cost is to make contributions to an external
Voluntary Employees Beneficiary Association trust fund equal to the incremental
OPEB costs (i.e., the amount that the total postretirement benefits cost under
SFAS 106, "Employers Accounting for Postretirement Benefits Other Than
Pensions," exceeds the pay-as-you-go amount). Contributions were $14.6 million
in 1996, $11.7 million in 1995, and $3.3 million in 1994. OPEB costs are
determined by the application of AEP System actuarial assumptions to each
company's employee complement. The Company's annual accrued costs for 1996, 1995
and 1994 required by SFAS 106 for employees and retirees were $32.1 million, $35
million and $33.7 million, respectively.
With the issuance of SFAS 106, the Company received regulatory authority
to defer the increased OPEB costs resulting from the SFAS 106 required change
from pay-as-you-go to accrual accounting which were not being recovered in
rates. The deferred amounts are being amortized over a 4-year period ending in
March 1999. At December 31, 1996 and 1995, $10.9 million and $17.4 million,
respectively, of OPEB costs were deferred.
Several UMWA health plans pay the postretirement medical benefits for the
Company's UMWA retirees who retired before January 2, 1976 and their survivors
plus retirees and others whose last employer is no longer a signatory to the
UMWA contract or is no longer in business. The UMWA health plans are funded by
payments from current and former UMWA wage agreement signatories, the
1950 UMWA Pension Plan surplus and the Abandoned Mine Land Reclamation Fund
Surplus. Required annual payments to the UMWA health funds made by the coal-
mining subsidiaries were recognized as expense when paid and totaled $400,000
in 1996, $500,000 in 1995 and $800,000 in 1994.
By law, excess Black Lung Trust funds can be used to pay certain UMWA
postretirement medical benefits under one of the UMWA health plans. Excess
Black Lung Trust funds used to reimburse OPCo's coal-mining subsidiaries for
UMWA postretirement medical benefits totaled $5 million in 1996, $5.8 million
in 1995 and $6.7 million in 1994. The Black Lung Trust had excess funds related
to OPCo's subsidiaries at December 31, 1996 of approximately $10.5 million of
which $9.5 million may be used to pay future costs.
7. COMMON SHAREHOLDER'S EQUITY:
Mortgage indentures, 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, 1996, $23.9 million
of retained earnings were restricted. Regulatory approval is required to pay
dividends out of paid-in capital.
In 1996 and 1995 net changes in paid-in capital of $1.2 million and $(3.6)
million, respectively, represented gains and expenses associated with cumulative
preferred stock transactions.
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $102,406 $67,513 $89,638
Deferred 21,835 29,960 (8,237)
Deferred Investment Tax Credits (1,830) (1,832) (1,834)
Total 122,411 95,641 79,567
Charged (Credited) to Nonoperating Income (net):
Current (293) 183 (1,715)
Deferred (3,153) (387) (1,234)
Deferred Investment Tax Credits (1,722) (1,738) (1,796)
Total (5,168) (1,942) (4,745)
Total Federal Income Taxes as Reported $117,243 $93,699 $74,822
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,
1996 1995 1994
(in thousands)
Net Income $217,655 $189,447 $162,626
Federal Income Taxes 117,243 93,699 74,822
Pre-tax Book Income $334,898 $283,146 $237,448
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35%) $117,214 $99,101 $83,107
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 13,394 14,250 12,670
Removal Costs (5,775) (5,775) (5,775)
Corporate Owned Life Insurance (3,735) (8,415) (7,552)
Investment Tax Credits (net) (3,552) (3,453) (3,630)
Other (303) (2,009) (3,998)
Total Federal Income Taxes as Reported $117,243 $93,699 $74,822
Effective Federal Income Tax Rate 35.0% 33.1% 31.5%
The following tables show the elements of the net deferred tax liability
and the significant temporary difference giving rise to such deferrals:
December 31,
1996 1995
(in thousands)
Deferred Tax Assets $ 161,409 $ 150,118
Deferred Tax Liabilities (900,035) (882,077)
Net Deferred Tax Liabilities $(738,626) $(731,959)
Property Related Temporary
Differences $(621,254) $(606,667)
Amounts Due From Customers For
Future Federal Income Taxes (135,281) (141,364)
Deferred State Income Taxes (21,337) (17,642)
All Other (net) 39,246 33,714
Total Net Deferred
Tax Liabilities $(738,626) $(731,959)
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
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. During the audit the IRS agents requested a ruling
from their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company for 1991 through
1993 should not be allowed. The COLI program was established in 1990 as part
of the Company's strategy to fund and reduce the cost of medical benefits for
retired employees. AEP filed a brief with the IRS National Office refuting
the agents' position. Although no adjustments have been proposed, a
disallowance of the COLI interest deductions through December 31, 1996 would
reduce earnings by approximately $91 million (including interest).
Management believes it will ultimately prevail on this issue and will
vigorously contest any adjustments that may be assessed. Accordingly, no
provision for this amount has been recorded. In the opinion of management,
the final settlement of open years will not have a material effect on results
of operations.
9. LEASES:
Leases of property, plant and equipment are for periods of up to 30
years and require payments of related property taxes, maintenance and operat-
ing 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,
1996 1995 1994
(in thousands)
Operating Leases $64,891 $61,979 $20,976
Amortization of
Capital Leases 23,217 24,467 23,355
Interest on
Capital Leases 8,473 8,528 6,955
Total Rental Costs $96,581 $94,974 $51,286
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
1996 1995
(in thousands)
Electric Utility Plant:
Production $ 21,689 $ 21,457
General (including mining assets) 184,489 187,218
Total Electric Utility Plant 206,178 208,675
Accumulated Amortization 82,973 83,794
Net Electric Utility Plant 123,205 124,881
Other Property (net) 8,080 7,045
Net Property under
Capital Leases $131,285 $131,926
Obligations under Capital Leases:*
Noncurrent Liability $107,132 $106,754
Liability Due Within One Year 24,153 25,172
Total Capital Lease Obligations $131,285 $131,926
*Represents the present value of future minimum lease payments.
Noncurrent capital lease obligations are included in other noncurrent
liabilities in the Consolidated Balance Sheets.
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease rentals consisted of the following at December 31,
1996:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1997 $ 31,585 $ 57,301
1998 26,723 56,119
1999 21,597 55,118
2000 17,886 54,552
2001 13,894 54,127
Later Years 50,111 508,005
Total Future Minimum
Lease Rentals 161,796 $785,222
Less Estimated
Interest Element 30,511
Estimated Present Value
of Future Minimum
Lease Rentals $131,285
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1996, authorized shares of cumulative preferred stock
were as follows:
Par Value Shares Authorized
$100 3,762,403
25 4,000,000
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 par value.
In 1995 the Company redeemed and canceled all of the outstanding shares of
the following series of cumulative preferred stock not subject to mandatory
redemption: 7.60%, 350,000 shares; 7-6/10%, 350,000 shares; and 8.04%,
150,000 shares.
In January 1997 a tender offer for all series of preferred stock was
announced. In conjunction with the tender offer a special shareholders
meeting was scheduled to be held on February 28, 1997 for the purpose of
considering amendments to the Company's articles of incorporation to remove
certain capitalization ratio requirements.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1996 Value Year Ended December 31, December 31, 1996 1996 1995
1996 1995 1994 (in thousands)
4.08% $103 $100 7,425 - - 42,575 $ 4,258 $ 5,000
4-1/2% 110 100 - - - 202,403 20,240 20,240
4.20% 103.20 100 8,025 - - 51,975 5,198 6,000
4.40% 104 100 11,637 - - 88,363 8,836 10,000
$38,532 $41,240
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Shares Amount
Par Number of Shares Redeemed Outstanding December 31,
Series (a) Value Year Ended December 31, December 31, 1996 1996 1995
1996 1995 1994 (in thousands)
5.90% (b) $100 46,000 - - 404,000 $ 40,400 $ 45,000
6.02% (c) 100 5,000 - - 395,000 39,500 40,000
6.35% (d) 100 - - - 300,000 30,000 30,000
$109,900 $115,000
(a) Not callable until after 2002. There are no aggregate sinking fund
provisions through 2001. Shares have been reacquired on the open market.
(b) Commencing in 2004 and continuing through the year 2008, a sinking fund
for the 5.90% cumulative preferred stock will require the redemption of
22,500 shares each year and the redemption of the remaining shares
outstanding on January 1, 2009, in each case at $100 per share.
(c) Commencing in 2003 and continuing through the year 2007, a sinking fund
for the 6.02% cumulative preferred stock will require the redemption of
20,000 shares each year and the redemption of the remaining shares
outstanding on December 1, 2008, in each case at $100 per share.
(d) Commencing in 2003 and continuing through the year 2007, a sinking fund
for the 6.35% cumulative preferred stock will require the redemption of
15,000 shares each year and the redemption of the remaining shares
outstanding on June 1, 2008, in each case at $100 per share.
11. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1996 1995
(in thousands)
First Mortgage Bonds $ 664,429 $ 796,084
Installment Purchase
Contracts 232,474 232,351
Notes Payable 81,681 90,000
Debentures 82,475 99,854
Other 8,670 9,343
1,069,729 1,227,632
Less Portion Due Within
One Year 67,293 89,207
Total $1,002,436 $1,138,425
First mortgage bonds outstanding were as follows:
December 31,
1996 1995
(in thousands)
% Rate Due
5 1996 - January 1 $ - $ 38,759
6-1/2 1997 - August 1 46,620 46,620
6-3/4 1998 - March 1 55,661 55,661
8.10 2002 - February 15 50,000 50,000
8.25 2002 - March 15 50,000 50,000
7-5/8 2002 - April 1 - 16,910
7-3/4 2002 - October 1 - 24,000
6.75 2003 - April 1 40,000 40,000
6.875 2003 - June 1 40,000 40,000
6.55 2003 - October 1 40,000 40,000
6.00 2003 - November 1 25,000 25,000
6.15 2003 - December 1 50,000 50,000
9-7/8 2020 - August 1 - 2,543
9.625 2021 - June 1 - 50,000
8.80 2022 - February 10 50,000 50,000
8.75 2022 - June 1 50,000 50,000
7.75 2023 - April 1 40,000 40,000
7.85 2023 - June 1 40,000 40,000
7.375 2023 - October 1 40,000 40,000
7.10 2023 - November 1 25,000 25,000
7.30 2024 - April 1 25,000 25,000
Unamortized Discount (net) (2,852) (3,409)
664,429 796,084
Less Portion Due Within
One Year 46,620 62,759
Total $617,809 $733,325
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:
December 31,
1996 1995
(in thousands)
Ohio Air Quality Development
7.4% Series B
due 2009 - August 1 $ 50,000 $ 50,000
Mason County, West Virginia:
5.45% Series B
due 2016 - December 1 50,000 50,000
Marshall County, West
Virginia:
5.45% Series B
due 2014 - July 1 50,000 50,000
5.90% Series D
due 2022 - April 1 35,000 35,000
6.85% Series C
due 2022 - June 1 50,000 50,000
Unamortized Discount (2,526) (2,649)
Total $232,474 $232,351
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 redemption) of related
pollution control revenue bonds issued to finance the construction of
pollution control facilities at certain plants.
The notes payable have due dates ranging from January 1997 to January 2001
with variable and fixed interest payable quarterly. Interest rates range
from 5.88% to 7.19% at December 31, 1996.
Debentures outstanding were as follows:
December 31,
1996 1995
(in thousands)
5-1/8% Series
due 1996 - January 1 $ - $ 8,297
6-5/8% Series
due 1997 - August 1 - 4,253
7-7/8% Series
due 1999 - March 1 - 4,905
8.16% Series A
due 2025 - September 30 85,000 85,000
Unamortized Discount (net) (2,525) (2,601)
82,475 99,854
Less Portion Due Within
One Year - 17,455
Total $82,475 $82,399
At December 31, 1996, future long-term debt payments, excluding premium or
discount, are as follows:
Principal Amount
(in thousands)
1997 $ 67,293
1998 73,015
1999 15,674
2000 648
2001 30,570
Later Years 890,432
Total $1,077,632
Short-term debt borrowings are limited by provisions of the 1935 Act to
$250 million. Lines of credit are shared with other AEP System companies and
at December 31, 1996 and 1995 were available in the amounts of $409 million
and $372 million, respectively. Commitment fees of approximately 1/8 of 1%
of the unused short-term lines of credit are required to maintain the lines
of credit. Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1996:
Notes Payable $ 4,600 5.4%
Commercial Paper 36,702 7.2
Total $41,302 7.0
December 31, 1995:
Commercial Paper $9,400 6.2%
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. Fair values for preferred stock
subject to mandatory redemption were $109.7 million and $117.4 million and for
long-term debt were $1.08 billion and $1.28 billion at December 31, 1996
and 1995, respectively. The carrying amounts for preferred stock subject to
mandatory redemption were $109.9 million and $115 million and for long-term debt
were $1.07 billion and $1.2 billion at December 31, 1996 and 1995,
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,
1996 1995 1994
(in thousands)
Cash was paid for:
Interest (net of
capitalized
amounts) $ 85,769 $93,126 $ 85,496
Income Taxes 105,035 65,629 107,514
Noncash Acquisitions
Under Capital Leases
were 30,942 31,799 65,008
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1996
March 31 $504,741 $87,844 $66,536
June 30 449,383 67,283 43,949
September 30 483,957 69,252 54,920
December 31 473,627 72,782 52,250
1995
March 31 416,827 67,329 47,742
June 30 435,976 67,870 45,798
September 30 507,516 68,278 48,808
December 31 462,678 68,683 47,099