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SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
Form 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-2385
THE DAYTON POWER AND LIGHT COMPANY
(Exact name of registrant as specified in its charter)
OHIO 31-0258470
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Courthouse Plaza Southwest, Dayton, Ohio 45402
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 513-224-6000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of Each Class which registered
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First Mortgage Bonds
8% Series Due 2003 New York Stock Exchange
Preferred Stock ($100 Par Value)
7.48% Series D, Cumulative New York Stock Exchange
7.70% Series E, Cumulative New York Stock Exchange
7.375% Series F, Cumulative New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. ( )
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES (X) NO ( )
Number of shares of registrant's common stock outstanding as of February 28,
1994, all of which were held by DPL Inc., was 41,172,173.
PART I
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Item 1 - BUSINESS*
THE COMPANY
The Dayton Power and Light Company (the "Company") is a
public utility incorporated under the laws of Ohio in 1911.
Located in West Central Ohio, it furnishes electric service to
464,000 retail customers in a 24 county service area of
approximately 6,000 square miles and furnishes natural gas service
to 286,000 customers in 16 counties. In addition, the Company
provides steam heating service in downtown Dayton, Ohio. The
Company serves an estimated population of 1.2 million. Principal
industries served include electrical machinery, automotive and
other transportation equipment, non-electrical machinery,
agriculture, paper, rubber and plastic products. The Company's
sales reflect the general economic conditions and seasonal weather
patterns of the area. The solid performance of the economy of
West Central Ohio and seasonal summer and winter weather in 1993
contributed to increased energy sales for the year. Electric
sales to business customers were up 4% for the year while total
electric and natural gas sales increased 4% and 3% respectively,
as compared to 1992. During 1993, cooling degree days were 4%
above the twenty year average and 35% above 1992. Heating degree
days in 1993 were 3% above the thirty year average and 6% above
1992. Sales patterns will change in future years as weather and
the economy fluctuate. The Company employed 3,147 persons as of
December 31, 1993, of which 2,653 are full-time employees and 494
are part-time employees.
All of the outstanding shares of common stock of the
Company are held by DPL Inc., which became the Company's corporate
parent, effective April 21, 1986. Subsidiaries of the Company
include MacGregor Park, Inc., an owner and developer of real
estate; DP&L Community Urban Redevelopment Corporation, the owner
of a downtown Dayton office building; and Miami Valley Equipment,
Inc., which presently owns no property and conducts no business.
The Company's principal executive and business office is
located at Courthouse Plaza Southwest, Dayton, Ohio 45402 -
telephone (513)224-6000.
Information relating to industry segments is contained in
Item 8 - Note 11 of Notes to Consolidated Financial Statements on
Page II-23 of this document, which Note is incorporated herein by
reference.
* Unless otherwise indicated, the information given in "Item 1 -
BUSINESS" is current as of March 11, 1994. No representation
is made that there have not been any subsequent changes to
such information.
I-1
COMPETITION
The Company competes with privately and municipally
owned electric utilities and rural electric cooperatives,
natural gas suppliers and other alternate fuel suppliers. The
Company competes on the basis of price and service.
Like other utilities, the Company from time to time may
have electric generating capacity available for sale to other
utilities. The Company competes with other utilities to sell
electricity provided by such capacity. The ability of the
Company to sell this electricity will depend on how the
Company's price, terms and conditions compare to those of other
utilities. In addition, from time to time, the Company also
makes power purchases from neighboring utilities.
In an increasingly competitive energy environment,
cogenerated power may be used by customers to meet their own
power needs. Cogeneration is the dual use of a form of energy,
typically steam, for an industrial process and for the
generation of electricity. The Public Utilities Regulatory
Policies Act of 1978 ("PURPA") provides regulations covering
when an electric utility is required to offer to purchase excess
electric energy from cogeneration and small power production
facilities that have obtained qualifying status under PURPA.
The National Energy Policy Act of 1992, which reformed
the Public Utilities Holding Company Act, allows the federal
government to mandate access by others to a utility's electric
transmission system and may accelerate competition in the supply
of electricity.
General deregulation of the natural gas industry has
continued to prompt the influence of market competition as the
driving force behind natural gas procurement. The maturation of
the natural gas spot market in combination with open access
interstate transportation provided by pipelines has provided the
Company, as well as its end-use customers, with an array of
procurement options. Customers with alternate fuel capability
can continue to choose between natural gas and their alternate
fuel based upon overall economics. Therefore, demand for
natural gas purchased from the Company or purchased elsewhere
transported to the end-use customer by the Company could
fluctuate based on the economics of each in comparison with
changes in alternate fuel prices. For the Company, price
competition and reliability among both natural gas suppliers and
interstate pipeline sources are major factors affecting
procurement decisions.
I-2
In April 1992, FERC issued Order No. 636 ("Order 636")
amending its regulations governing the service obligations, rate
design and cost recovery of interstate pipelines. The Company's
interstate pipeline suppliers have received approval from FERC
to implement their restructuring plans to comply with the
regulations.
The Public Utilities Commission of Ohio ("PUCO") has
held roundtable discussions and meetings regarding the
implications of Order 636 for local distribution companies,
producers and consumers. The PUCO has issued interim guidelines
allowing utilities to file revised natural gas transportation
tariffs to comply with the Order, and is continuing efforts to
examine the impact via roundtable discussions. The Company's
natural gas tariffs and operations comply with the PUCO's
interim guidelines and the requirements of Order 636.
In January 1994, the Company, the Staff of the PUCO and
the Office of the Ohio Consumers' Counsel (the "OCC") submitted
to the PUCO an agreement which resolves issues relating to the
recovery of Order 636 "transition costs" to be billed to the
Company by natural gas interstate pipeline companies. The
agreement, which is subject to PUCO approval, provides for the
full recovery of these transition costs from the Company's
customers. The interstate pipelines will file with the FERC for
authority to recover these transition costs, the exact magnitude
of which has not been established.
The Company provides service to 12 municipal customers
which distribute electricity within their corporate limits. One
municipality has signed a contract for the Company to provide
95% of its requirements. In addition to these municipal
customers, the Company maintains an interconnection agreement
with one municipality which can generate all or a portion of its
energy requirements. Sales to municipalities represented 1.3%
of total electricity sales in 1993. The Company maintains
discussions with these municipalities concerning potential
energy agreements.
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CONSTRUCTION AND FINANCING PROGRAM OF THE COMPANY
1994-1998 Construction Program
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The estimated construction additions for the years
1994-1998 are set forth below:
Estimated
1994 1995 1996 1997 1998 1994-1998
---- ---- ---- ---- ---- ---------
millions
Electric generation and
transmission commonly
owned with neighboring
utilities................ $ 22 $ 28 $ 24 $ 41 $ 23 $138
Other electric
generation and
transmission facilities.. 43 33 34 18 13 141
Electric distribution...... 24 26 31 34 37 152
General.................... 3 3 2 1 1 10
Gas, steam and other
facilities............... 13 13 11 12 12 61
--- --- --- --- --- ---
Total construction..... $105 $103 $102 $106 $ 86 $502
Estimated construction additions over the next five
years average $100 million annually which is approximately equal
to the projected depreciation expense over the same period.
The construction additions for the period include plans
to construct a series of 70 MW combustion turbine generating
units scheduled to be completed at varying intervals dependent
upon need. The first unit is scheduled for completion in June
1995.
Construction plans are subject to continuing review and
are expected to be revised in light of changes in financial and
economic conditions, load forecasts, legislative and regulatory
developments and changing environmental standards, among other
factors. The Company's ability to complete its capital projects
and the reliability of future service will be affected by its
financial condition, the availability of external funds at
reasonable cost and adequate and timely rate increases.
See ENVIRONMENTAL CONSIDERATIONS for a description of
environmental control projects and regulatory proceedings which
may change the level of future construction additions. The
potential impact of these events on the Company's operations
cannot be estimated at this time.
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1994-1998 Financing Program
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The Company will require a total of $106 million during
the next five years for bond maturities and preferred stock and
bond sinking funds in addition to any funds needed for the
construction program.
At year-end 1993, the Company had a cash and temporary
investment balance of $6 million. Proceeds from temporary cash
investments, together with internally generated cash and future
outside financings, will provide for the funding of the
construction program, sinking funds and general corporate
requirements.
In mid-March 1994, DPL Inc. plans to file a
registration statement with the Securities and Exchange
Commission for the issuance and sale of approximately
three-and-a-half million common shares. The net proceeds from
the planned sale of shares, estimated to equal approximately
$65 million, would be contributed to the Company which would use
the funds, along with temporary cash investments and/or
short-term borrowings, to redeem in May 1994 all of the
outstanding shares of its Preferred Stock, Series D, E, F, H and
I, which have an average dividend rate of 8.1%.
During late 1992 and early 1993, the Company took
advantage of favorable market conditions to reduce its cost of
debt and extend maturities through early refundings. Three new
series of First Mortgage Bonds were issued in 1992 in the
aggregate principal amount of $320 million at an average
interest rate of 7.8% to finance the redemption of a similar
principal amount of debt securities. Additionally, in early
1993, the Company issued two new series of First Mortgage Bonds
in the aggregate principal amount of $446 million at an average
interest rate of 8.0% to finance the redemption of a similar
principal amount of six series of First Mortgage Bonds. The
amounts and timings of future financings will depend upon market
and other conditions, rate increases, levels of sales and
construction plans.
In November 1989, DPL Inc. entered into a revolving
credit agreement ("the Credit Agreement") with a consortium of
banks renewable through 1998 which allows total borrowings by
DPL Inc. and its subsidiaries of $200 million. The Company has
authority from the PUCO to issue short term debt up to
$200 million with a maximum debt limit of $300 million including
loans from DPL Inc. under the terms of the Credit Agreement. At
December 31, 1993, DPL Inc. had no outstanding borrowings under
this Credit Agreement. The Company also has $97 million
available in short term informal lines of credit. At year-end,
the Company had $10 million outstanding from these lines of
credit and $15 million in commercial paper outstanding.
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Under the Company's First and Refunding Mortgage, First
Mortgage Bonds may be issued on the basis of (i) 60% of unfunded
property additions, subject to net earnings, as defined, being
at least two times interest on all First Mortgage Bonds
outstanding and to be outstanding, and (ii) 100% of retired
First Mortgage Bonds. The Company anticipates that, during
1994-98, it will be able to issue sufficient First Mortgage
Bonds to satisfy its long-term debt requirements in connection
with the financing of its construction and refunding programs
discussed above.
The maximum amount of First Mortgage Bonds which may be
issued in the future will fluctuate depending upon interest
rates, the amounts of bondable property additions, earnings and
retired First Mortgage Bonds. There are no coverage tests for
the issuance of preferred stock under the Company's Amended
Articles of Incorporation.
ELECTRIC OPERATIONS AND FUEL SUPPLY
The Company's present winter generating capability is
3,053,000 KW. Of this capability, 2,843,000 KW (approximately
93%) is derived from coal-fired steam generating stations and
the balance consists of combustion turbine and diesel-powered
peaking units. Approximately 87% (2,472,000 KW) of the existing
steam generating capability is provided by certain units owned
as tenants in common with the Cincinnati Gas & Electric Company
("CG&E") or with CG&E and Columbus Southern Power Company
("CSP"). Under the agreements among the companies, each company
owns a specified undivided share of each facility, is entitled
to its share of capacity and energy output, and has a capital
and operating cost responsibility proportionate to its ownership
share.
A merger agreement between CG&E and PSI Resources is
currently pending. The Company has intervened in the merger
proceeding currently pending at the FERC so that the operations
of its commonly owned generating units will not be materially
impacted by the merger.
The remaining steam generating capability (371,000 KW)
is derived from a generating station owned solely by the
Company. The Company's all time net peak load was 2,765,000 KW,
which occurred in July 1993. The present summer generating
capability is 3,017,000 KW.
I-6
GENERATING FACILITIES
---------------------
MW Rating
--------------
Owner- Operating Company
Station ship* Company Location Portion Total
- ----------- ----- --------- ------------ ------- -----
Coal Units
- ----------
Hutchings W Company Miamisburg, OH 371 371
Killen C Company Wrightsville, OH 402 600
Stuart C Company Aberdeen, OH 820 2,340
Conesville-Unit 4 C CSP Conesville, OH 129 780
Beckjord-Unit 6 C CG&E New Richmond, OH 210 420
Miami Fort-
Units 7&8 C CG&E North Bend, OH 360 1,000
East Bend-Unit 2 C CG&E Rabbit Hash, KY 186 600
Zimmer C CG&E Moscow, OH 365 1,300
Combustion Turbines or Diesel
- -----------------------------
Hutchings W Company Miamisburg, OH 32 32
Yankee Street W Company Centerville, OH 144 144
Monument W Company Dayton, OH 12 12
Tait W Company Dayton, OH 10 10
Sidney W Company Sidney, OH 12 12
* W = Wholly Owned; C = Commonly Owned
In order to transmit energy to their respective systems
from their commonly-owned generating units, the companies have
constructed and own, as tenants in common, 847 circuit miles of
345,000-volt transmission lines. The Company has several
interconnections with other companies for the purchase, sale and
interchange of electricity.
The Company derived over 99% of its electric output
from coal-fired units in 1993. The remainder was derived from
units burning oil or natural gas which were used to meet peak
demands.
The Company estimates that approximately 65-85% of its
coal requirements for the period 1994-1998 will be obtained
through long term contracts, with the balance to be obtained by
spot market purchases. The Company has been informed by CG&E
and CSP through the procurement plans for the commonly owned
units operated by them that sufficient coal supplies will be
available during the same planning horizon.
The prices to be paid by the Company under its long
term coal contracts are subject to adjustment in accordance with
various indices. Each contract has features that will limit
price escalations in any given year.
I-7
The total average price per million British Thermal
Units ("MMBTU") of coal received in each of 1993 and 1992 was
$1.46/MMBTU and $1.56/MMBTU in 1991.
The average fuel cost per kWh generated of all fuel
burned for electric generation (coal, gas and oil) for the year
was 1.43cents/ which represents a decrease from 1.48cents/ in 1992 and
1.60cents in 1991. Through the operation of a fuel cost
adjustment clause applicable to electric sales, the increases
and decreases in fuel costs are reflected in customer rates on a
timely basis. See RATE REGULATION AND GOVERNMENT LEGISLATION
and ENVIRONMENTAL CONSIDERATIONS.
GAS OPERATIONS AND GAS SUPPLY
The Company has long term firm pipeline transportation
agreements with ANR Gas Pipeline Company ("ANR") through 1997
and Columbia Gas Transmission Corporation ("Columbia"), Columbia
Gulf Transmission Corporation, Texas Gas Transmission
Corporation ("Texas Gas") and Panhandle Eastern Pipe Line
Company ("Panhandle") through 2004. Along with the firm
transportation services the Company has approximately 16 billion
cubic feet of storage service with the various pipelines. The
Company also maintains and operates four propane-air plants with
a daily rated capacity of approximately 67,500 thousand cubic
feet ("MCF") of natural gas.
Coordinated with the pipeline service agreements, the
Company has 14 firm natural gas supply agreements with various
natural gas producers. The Company purchased approximately 90%
of its 1993 supply under these producer agreements and the
remaining supplies on the spot/short term market. The Company
purchased natural gas during 1993 at an average price of $3.65
per MCF, compared to $3.31 per MCF and $2.70 per MCF in 1992 and
1991, respectively. Through the operation of a natural gas cost
adjustment clause applicable to gas sales, increases and
decreases in the Company's natural gas costs are reflected in
customer rates on a timely basis. SEE RATE REGULATION AND
GOVERNMENT LEGISLATION.
The Company is also interconnected with CNG
Transmission Corporation and Texas Eastern Transmission
Corporation. Several interconnections with various interstate
pipelines provide the Company the opportunity to purchase
competitively-priced natural gas supplies and pipeline services.
I-8
During 1993, the Company implemented requirements of
Order 636 with all of its natural gas interstate pipeline
suppliers. As a result of FERC's mandate that pipelines no
longer bundle the product of natural gas with pipeline
transportation into one package, the Company purchased the
majority of its natural gas in 1993 under direct market
purchases. Additionally, the implementation of Order 636
required the Company to purchase certain volumes of natural gas
from interstate pipelines to fill storage. In the future, the
Company will obtain its natural gas from direct market purchases
or pipelines based on cost and reliability. The Company has
natural gas agreements that meet 90% of its requirements. The
remainder will be purchased to meet seasonal requirements under
short term purchase agreements.
The PUCO continues to support open access,
nondiscriminatory transportation of natural gas by the state's
local distribution companies for end-use customers. The PUCO
has guidelines to provide a standardized structure for end-use
transportation programs which requires a tariff providing the
prices, terms and conditions for such service. The Company has
filed a transportation tariff to comply with these guidelines
and approval is pending. During 1993, the Company provided
transportation service to 185 end-use customers, delivering a
total quantity of 13,401,229 MCF.
Columbia and Panhandle have obtained conditional
approval from FERC to recover take-or-pay and contract
reformation costs from the Company through fixed demand
surcharges pursuant to revised FERC rules. The validity of the
revisions was reviewed and dismissed by the U.S. Court of
Appeals for the District of Columbia Circuit. Pursuant to a
settlement approved by the PUCO, the Company may recover
take-or-pay costs from its retail and transportation customers.
On April 30, 1990, Columbia filed an application with
FERC to implement a general rate increase in order to recover,
among other things, costs associated with construction of
certain "Global Settlement" facilities. The rates were accepted
to become effective November 1, 1990. A partial offer of
settlement was accepted on April 16, 1992, and an initial
decision on the remaining issues was issued on November 13,
1992. On May 31, 1991, Columbia filed a second application with
FERC to implement a general rate increase which was partially
accepted effective December 1, 1991. On October 1, 1991,
Columbia filed a third application to implement a general rate
increase which was partially accepted to become effective
April 1, 1992. The second and third applications were
subsequently consolidated into one rate proceeding, and rate
design, cost classification and cost allocations were further
consolidated into Columbia's restructuring proceeding referenced
in following paragraphs. A settlement dated November 9, 1992,
regarding the remaining cost of service and throughput issues
was approved by FERC April 2, 1993.
I-9
On April 27, 1990, Texas Gas filed an application with
FERC to implement a general rate increase which was accepted to
become effective November 1, 1990. This docket was consolidated
into the Texas Gas restructuring proceeding which was made
effective November 1, 1993. On May 1, 1992, Panhandle filed an
application with FERC to implement a general rate increase which
rates were accepted effective November 1, 1992. A hearing on
this matter is set for May 17, 1994. On April 29, 1993 Texas
Gas filed a second application with FERC to implement a rate
increase which was accepted effective November 1, 1993. A
hearing on this matter is set for June 28, 1994. On November 1,
1993, ANR filed an application with FERC to implement a rate
increase which was accepted effective May 2, 1994. Through the
operation of a natural gas cost adjustment clause applicable to
gas sales, increases and decreases in the Company's natural gas
costs are reflected in customer rates on a timely basis.
On July 31, 1991, Columbia Gas System Inc. and
Columbia, one of the Company's major pipeline suppliers, filed
separate Chapter 11 petitions in U.S. Bankruptcy Court. The
bankruptcy court permitted Columbia to break approximately 4,500
long term natural gas contracts with upstream suppliers on
August 22, 1991, January 6, 1992, and January 8, 1992. The
bankruptcy court issued an order on March 18, 1992, granting
approval of an agreement between the customers and Columbia
which assures the continuation of all firm service agreements
(including storage) through the winter of 1993, with
year-to-year continuation unless adequate notice is provided.
On February 13, 1992, the bankruptcy court ruled on a motion by
Columbia to flow through to its customers all appropriate
refunds, including take-or-pay refunds which were received from
its upstream suppliers and excessive rate refunds except for
approximately $18 million of pre-petition take-or-pay refunds.
However, on July 6, 1992, the United States District Court for
Delaware reversed the bankruptcy court. On July 8, 1993, the
Third Circuit Court of Appeals reversed the District Court for
Delaware and reinstated the U.S. Bankruptcy Court's ruling that
Columbia may flow through to its customers all post petition
take-or-pay refunds which were received from its upstream
suppliers. The U.S. Supreme Court denied an appeal on
February 18, 1994 of the Third Circuit Court of Appeals'
decision. The Company expects full recovery of all take-or-pay
refunds received by Columbia post petition. The parties to the
bankruptcy are currently evaluating Columbia's proposed plan of
reorganization. Based upon a July 1993 FERC order disallowing
the recovery of natural gas producer contracts rejected in the
bankruptcy case, the Company does not expect the bankruptcy
proceedings to have a material adverse effect on its earnings or
competitive position.
In April 1992 FERC issued Order 636 which amended its
regulations governing the service obligations of interstate
pipelines. Some of the major changes enacted include unbundling
I-10
of pipeline sales from transportation, the creation of a
"no-notice" transportation service, pre-granted abandonment for
all interruptible and short term firm transportation subject to
a right-of-first-refusal, capacity brokering, rate design and
transition costs. All interstate pipeline filings were made
effective by November 1, 1993.
In response to Order 636, the PUCO has initiated
roundtable discussions with natural gas utilities and other
interested parties to discuss the impact of the Order and the
state regulation of natural gas utilities. The PUCO has issued
interim guidelines allowing utilities to file revised natural
gas transportation tariffs to comply with Order 636, and is
continuing to examine the impact via ongoing roundtable
discussions that run concurrently with the interstate pipelines'
restructuring proceedings. The interim guidelines also require
each natural gas utility to file plans for peak day operations.
The Company's operations comply with all interim guidelines and
the Company expects full recovery of all Order 636 transition
costs.
RATE REGULATION AND GOVERNMENT LEGISLATION
The Company's sales of electricity, natural gas and
steam to retail customers are subject to rate regulation by the
PUCO and various municipalities. The Company's wholesale
electric rates to municipal corporations and other distributors
of electric energy are subject to regulation by FERC under the
Federal Power Act.
Ohio law establishes the process for determining rates
charged by public utilities. Regulation of rates encompasses
the timing of applications, the effective date of rate
increases, the cost basis upon which the rates are based and
other related matters. Ohio law also established the Office of
the OCC, which is authorized to represent residential consumers
in state and federal judicial and administrative rate
proceedings.
The Company's electric and natural gas rate schedules
contain certain recovery and adjustment clauses subject to
periodic audits by, and proceedings before, the PUCO. Electric
fuel and gas costs are expensed as recovered through rates.
Ohio legislation extends the jurisdiction of the PUCO
to the records and accounts of certain public utility holding
company systems, including DPL Inc. The legislation extends the
PUCO's supervisory powers to a holding company system's general
condition and capitalization, among other matters, to the extent
that they relate to the costs associated with the provision of
public utility service. Additionally, the legislation requires
PUCO approval of (i) certain transactions and transfers of
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assets between public utilities and entities within the same
holding company system, and (ii) prohibits investments by a
holding company in subsidiaries which are not public utilities
in an amount in excess of 15% of the aggregate capitalization of
the holding company on a consolidated basis at the time such
investments are made.
In April 1991, the Company filed an application with
the PUCO to increase its electric rates to recover costs
associated with the construction of the William H. Zimmer
Generating Station ("Zimmer"), earn a return on the Company's
investment and recover the current costs of providing electric
service to its customers. In November 1991, the Company entered
into a settlement agreement with various consumer groups
resolving all issues in the case. The PUCO approved the
agreement on January 22, 1992. Pursuant to that agreement, new
electric rates took effect February 1, 1992, January 2, 1993 and
January 3, 1994. The agreement also established a baseline
return on equity of 13% (subject to upward adjustment) until the
Company's next electric rate case. In the event that the
Company's return exceeds the allowed return by between one and
two percent, then one half of the excess return will be used to
reduce the cost of demand-side management ("DSM") programs. Any
return that exceeds the allowed return by more than two percent
will be entirely credited to these programs. Amounts deferred
during the phase-in period, including carrying charges, will be
capitalized and recovered over seven years commencing in 1994.
Deferrals were $58 million in 1992 and $28 million in 1993. The
recovery expected in 1994, net of additional carrying cost
deferrals, is $10 million. The phase-in plan meets the
requirements of the Financial Accounting Standards Board
("FASB") Statement No. 92.
In addition, the Company agreed to undertake
cost-effective DSM programs with an average annual cost of
$15 million for four years commencing in 1992. The amount
recovered in rates was $4.6 million in 1992. This amount
increased to $7.8 million in 1993 and will remain at that level
in subsequent years. The difference between expenditures and
amounts recovered through rates is deferred and is eligible for
recovery in future rates in accordance with existing PUCO
rulings.
In March 1991, the PUCO granted the Company the
authority to defer interest charges, net of income tax, on its
28.1% ownership investment in Zimmer from the March 30, 1991,
commercial in-service date through January 31, 1992. Deferred
interest charges on the investment in Zimmer have been adjusted
to a before tax basis in 1993 as a result of FASB Statement
No. 109. Amounts deferred are being amortized over the life of
the plant.
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Regulatory deferrals on the balance sheet were:
Dec. 31 Dec. 31
1993 1992
-------- --------
--millions--
Phase-in $ 85.8 $ 57.7
DSM 23.3 2.2
Deferred interest - Zimmer 63.7 43.9
------ ------
Total $172.8 $103.8
====== ======
In 1989 the PUCO approved rules for the implementation
of a comprehensive Integrated Resource Planning ("IRP") program
for all investor-owned electric utilities in Ohio. Under this
program, each utility is required to file an IRP as part of its
Long Term Forecast Report ("LTFR"). The IRP requires each
utility to evaluate available demand-side resource options in
addition to supply-side options to determine the most
cost-effective means for satisfying customer requirements. The
rules currently allow a utility to apply for deferred recovery
of DSM program expenditures and lost revenues between LTFR
proceedings. Ultimate recovery of expenditures is contingent on
review and approval of such programs as cost-effective and
consistent with the most recent IRP proceeding. The rules also
allow utilities to submit alternative proposals for the recovery
of DSM programs and related costs.
In 1991 the PUCO ruled that the Company's 1991 LTFR be
consolidated and reviewed in conjunction with the Company's 1992
LTFR proceeding. The Company filed its 1992 LTFR in June 1992.
The Company also filed its environmental compliance plan in June
1992, and asked the PUCO to consolidate the environmental
compliance plan proceeding with the LTFR proceeding. The PUCO
granted the Company's request to consolidate the cases. The
evidentiary hearing on the Company's 1991/1992 LTFR and
environmental compliance plan was held on February 17, 1993.
The parties entered into a stipulation in settlement of all
issues which continues the Company's commitment to DSM
programs. The stipulation was approved by the PUCO on May 6,
1993.
The Company has in place a percentage of income payment
plan ("PIPP") for eligible low-income households as required by
the PUCO. This plan prohibits disconnections for nonpayment of
customer bills if eligible low-income households pay a specified
percentage of their household income toward their utility bill.
The PUCO has approved a surcharge by way of a temporary base
rate tariff rider which allows companies to recover arrearages
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accumulated under PIPP. In 1993 the Company reached a
settlement with the PUCO staff, the Office of the OCC and the
Legal Aid Society to provide new and expanded programs for PIPP
eligible customers. The expanded programs include greater
arrears crediting, lower monthly payments, educational programs
and information reports. In exchange, the Company may
accelerate recovery of PIPP and pre-PIPP arrearages and recover
program costs. The settlement also established a four year
moratorium on changes to the program. The PUCO approved the
settlement on December 2, 1993. Pursuant to the terms of the
settlement, the Company filed an application on January 21, 1994
to lower its PIPP rate. To date, the PUCO has not acted on the
Company's application.
In 1991 the PUCO issued a Finding and Order which
encourages electric utilities to undertake the competitive
bidding of new supply-side energy projects. The policy also
encourages utilities to provide transmission grid access to
those supply-side energy providers awarded bids by utilities.
Electric utilities are permitted to bid on their own proposals.
The PUCO has issued for comment proposed rules for competitive
bidding but has not issued final rules at this time.
The Company initiated a competitive bidding process in
January 1993 for the construction of up to 140 MW of electric
peaking capacity and energy by 1997. Through an Ohio Power
Siting Board ("OPSB") investigative process, the Company's
self-built option was evaluated to be the least cost option. On
March 7, 1994, the OPSB approved the Company's applications for
up to three 70 MW combustion turbines and two natural gas supply
lines for the proposed site.
The OPSB issued rules on March 22, 1993 to provide
electric and magnetic field information in applications for
construction of major generating and transmission facilities.
The Company has addressed the topics covered by the new rules in
all recent projects. One utility requested a rehearing on the
rules which was denied by the OPSB on May 24, 1993. At this
time the Company cannot predict the ultimate impact on timing
and costs associated with the siting of new transmission lines.
On March 25, 1993, the PUCO adopted guidelines for the
treatment of emission allowances created by the Clean Air Act
Amendments of 1990. Under the guidelines, the Company's
emission allowance trading plans, procedures, practices,
activity and associated costs will be reviewed in its annual
electric fuel component audit proceeding. The PUCO guidelines
are being appealed by an industrial consumer group. In its
Entry on emission allowances, the PUCO directed its Staff to
develop proposed accounting guidelines for allowance trading
I-14
programs in accordance with FERC rulemaking efforts. According
to FERC Order No. 552 issued on March 23, 1993, the Company will
value allowances based on a weighted average cost methodology.
On May 26, 1993, the Senate of the State of Ohio
approved the appointment of Mr. David W. Johnson as PUCO
commissioner.
On January 12, 1994, the Ohio Consumers' Counsel
Governing Board appointed Robert S. Tongren, a former assistant
attorney general, to the position of Consumers' Counsel.
Mr. Tongren replaced William A. Spratley, whose resignation from
this position became effective September 30, 1993.
On February 22, 1994 a bill was introduced in the State
of Ohio House of Representatives which, if approved, would give
electric consumers the opportunity to obtain "retail" and
"wholesale at retail" services from electric suppliers other
than their current supplier at competitive rates. The ultimate
disposition of the bill or its effect on the Company cannot be
determined at this time.
ENVIRONMENTAL CONSIDERATIONS
The operations of the Company, including the commonly
owned facilities operated by the Company, CG&E and CSP, are
subject to federal, state, and local regulation as to air and
water quality, disposal of solid waste and other environmental
matters, including the location, construction and initial
operation of new electric generating facilities and most
electric transmission lines. The Company expended $6 million
for environmental control facilities during 1993. The
possibility exists that current environmental regulations could
be revised which could change the level of estimated 1994-1998
construction expenditures. See CONSTRUCTION AND FINANCING
PROGRAM OF THE COMPANY.
Air Quality
- -----------
In July 1985, the United States Environmental
Protection Agency ("U.S. EPA") adopted final stack height rules
which could result in the lowering of emission limits for sulfur
dioxide and particulate matter from affected units. The Company
operates one unit (Killen Station) potentially affected by these
rules. The Ohio Environmental Protection Agency ("Ohio EPA")
has determined that Killen Station is not impacting air quality
and, therefore, no further action is needed at this time. CSP
has informed the Company that Conesville Unit 4 is not affected
by the rules. CG&E has informed the Company that Miami Fort
Unit 7 is "grandfathered" from regulation and that Miami Fort
I-15
Unit 8 is not affected by the rules because Miami Fort Unit 5 is
picking up the necessary emission reductions. On June 17 and
July 12, 1988, the Company and others filed with the U.S.
Supreme Court two petitions for a Writ of Certiorari seeking a
review of the D.C. Circuit Court of Appeals decision that
addressed the 1985 stack height rules. Those petitions were
denied in October 1988 and, as a result, the U.S. EPA planned to
begin a remand rulemaking to address issues arising from lower
Court's opinion. The U.S. EPA continues to work on a remand
rulemaking.
In December 1988, the U.S. EPA notified the State of
Ohio that the portion of its State Implementation Plan ("SIP")
dealing with sulfur dioxide emission limitations for Hamilton
County (in southwestern Ohio) was deficient and required the
Ohio EPA to develop a new SIP within 18 months. The notice
affects industrial and utility sources and could require
significant reductions in sulfur dioxide emission limitations at
CG&E's Miami Fort Units 7 and 8 which are jointly owned with the
Company. In February 1989, CG&E, together with other industrial
sources affected by the notice, filed a petition for review in
the U.S. Court of Appeals for the Sixth Circuit of the U.S.
EPA's issuance of the notice. In July 1989, the Court of
Appeals dismissed the petition for review. In April 1990, the
Ohio EPA published its proposed revised SIP for comment. In
June 1990, CG&E submitted its comments challenging the
revisions, arguing that the proposed SIP is based on a computer
model which is unsuitable and invalid for the hilly terrain of
Hamilton County, and that in the last ten years, no violation of
the National Ambient Air Quality Standards for SO2 has ever
been monitored.
In order to support its position, CG&E is taking part
in an air monitoring program designed to prove that the present
SIP adequately protects the ambient air quality. In October
1991, the Ohio EPA adopted new SO2 regulations for Hamilton
County. These regulations do not change the preexisting
requirements for Miami Fort Units 7 and 8. The new regulations
have been submitted to the U.S. EPA. On January 27, 1994, the
U.S. EPA provided notice in the Federal Register that the new
regulations for the Ohio SIP for Hamilton County were
conditionally approved.
Changing environmental regulations continue to increase
the cost of providing service in the utility industry. The
Clean Air Act Amendments of 1990 (the "Act") will limit sulfur
dioxide and nitrogen oxide emissions nationwide. The Act will
restrict emissions in two phases with Phase I compliance
completed by 1995 and Phase II completed by 2000. Final
regulations were issued by the U.S. EPA on January 11, 1993.
These regulations are consistent with earlier Act restrictions
and do not change the expected costs of compliance of the
Company.
I-16
The Company's preliminary compliance plan was filed
with the PUCO in June 1992 and consolidated with the 1991/1992
LTFR proceeding. The Company anticipates meeting the
requirements of Phase I by switching to lower sulfur coal at
several commonly owned electric generating facilities and
increasing existing scrubber removal efficiency. Cost estimates
to comply with Phase I of the Act are approximately $10 million
in capital expenditures. Phase I compliance is expected to have
a minimal 1% to 2% price impact. Phase II requirements can be
met primarily by switching to lower sulfur coal at all
non-scrubbed coal-fired electric generating units. The
stipulation entered into on February 17, 1993 with regards to
the LTFR, including the environmental compliance plan, was
approved by the PUCO on May 6, 1993. The Company anticipates
that costs to comply with the Act will be eligible for recovery
in future fuel hearings and other regulatory proceedings.
On March 16, 1993, the Company received a Finding of
Violation from the U.S. EPA regarding opacity standards at
Killen Station and, on March 17, 1993, a Notice of Violation
from the U.S. EPA regarding opacity standards at Stuart
Station. The Company has subsequently conducted conferences
with the U.S. EPA to discuss the Finding and Notice. On
October 11, 1993, the Company entered into negotiated Consent
Orders with the U.S. EPA for the alleged violations at Killen
and Stuart Stations. The Consent Orders do not require payment
of any penalty but require the Company to formalize emissions
control measures.
Land Use
- --------
The Company and numerous other parties have been
notified by the U.S. EPA that it considers them Potentially
Responsible Parties ("PRPs") for clean-up at three superfund
sites in Ohio - the Sanitary Landfill Site on Cardington Road in
Montgomery County, Ohio, the United Scrap Lead Site in Miami
County, Ohio, and the Powell Road Landfill in Huber Heights,
Montgomery County, Ohio.
The Company received notification from the U.S. EPA in
July 1987, for the Cardington Road site. The Company has not
joined the PRP group formed at that site because of the absence
of any known evidence that the Company contributed hazardous
substances to this site. The Record of Decision issued by the
U.S. EPA identifies the chosen clean-up alternative at a cost
estimate of $8.1 million.
The Company received notification from the U.S. EPA in
September 1987, for the United Scrap Lead Site. The Company has
joined a PRP group for this site, which is actively conferring
with the U.S. EPA. The Record of Decision issued by the U.S.
I-17
EPA estimates clean-up costs at $27.1 million. The Company is
one of over 200 parties to this site, and its estimated
contribution to the site is less than .01%. Nearly 60 PRPs are
actively working to settle the case. The Company is
participating in the sponsorship of a study to evaluate
alternatives to the U.S. EPA's clean-up plan. The final
resolution of these investigations will not have a material
effect on the Company's financial position or earnings.
The Company and numerous other parties received
notification from the U.S. EPA on May 21, 1993 that it considers
them PRPs for clean-up of hazardous substances at the Powell
Road Landfill Site in Huber Heights, Ohio. The Company has
joined the PRP group for the site. On October 1, 1993, the U.S.
EPA issued its Record of Decision identifying a cost estimate of
$20.5 million for the chosen remedy. The Company is one of over
200 PRPs to this site, and its estimated contribution is less
than 1%. The final resolution will not have a material effect
on the Company's financial position or earnings.
I-18
THE DAYTON POWER AND LIGHT COMPANY
OPERATING STATISTICS
ELECTRIC OPERATIONS
Years Ended December 31,
-----------------------------------
1993 1992 1991
---- ---- ----
Electric Output (millions of kWh)
Generation -
Coal-fired units.................. 14,729 13,639 13,952
Other units....................... 17 3 7
Power purchases...................... 1,107 1,514 470
Exchanged and transmitted power...... (7) 14 (54)
Company use and line losses.......... (1,170) (1,116) (1,060)
-------- -------- --------
Total............................. 14,676 14,054 13,315
======== ======== ========
Electric Sales (millions of kWh)
Residential.......................... 4,558 4,260 4,571
Commercial........................... 3,006 2,896 2,945
Industrial........................... 4,089 3,938 3,949
Public authorities and railroads..... 1,356 1,311 1,360
Private utilities and wholesale...... 1,667 1,649 490
-------- -------- --------
Total............................. 14,676 14,054 13,315
======== ======== ========
Electric Customers at End of Period
Residential.......................... 416,508 413,040 409,925
Commercial........................... 40,606 39,685 39,151
Industrial........................... 2,387 2,415 2,432
Public authorities and railroads..... 5,287 5,130 5,038
Other................................ 17 16 15
-------- -------- --------
Total............................. 464,805 460,286 456,561
======== ======== ========
Operating Revenues (thousands)
Residential.......................... $373,760 $326,547 $332,114
Commercial........................... 200,124 180,890 178,883
Industrial........................... 205,996 189,720 186,837
Public authorities and railroads..... 72,859 67,596 68,135
Private utilities and wholesale...... 38,491 35,174 15,436
Other................................ 10,090 9,372 9,334
-------- -------- --------
Total............................. $901,320 $809,299 $790,739
======== ======== ========
Residential Statistics
(per customer-average)
Sales - kWh.......................... 10,998 10,358 11,213
Revenue.............................. $ 901.91 $ 794.03 $ 814.66
Rate per kWh (Month of December)..... 7.99 cents 7.23 cents 6.96 cents
I-19
THE DAYTON POWER AND LIGHT COMPANY
OPERATING STATISTICS
GAS OPERATIONS
Years Ended December 31,
----------------------------------
1993 1992 1991
---- ---- ----
Gas Output (thousands of MCF)
Direct market purchases .............. 44,284 46,229 46,057
Liquefied petroleum gas............... 58 7 11
Company use and unaccounted for....... (1,164) (1,717) (1,798)
Transportation gas received........... 13,704 10,973 8,387
-------- -------- --------
Total.............................. 56,882 55,492 52,657
======== ======== ========
Gas Sales (thousands of MCF)
Residential........................... 28,786 27,723 26,594
Commercial............................ 8,468 8,642 8,368
Industrial............................ 3,056 4,914 6,014
Public authorities.................... 3,171 3,402 3,187
Transportation gas delivered.......... 13,401 10,811 8,494
-------- -------- --------
Total.............................. 56,882 55,492 52,657
======== ======== ========
Gas Customers at End of Period
Residential........................... 262,834 260,471 258,092
Commercial............................ 20,853 20,589 20,347
Industrial............................ 1,527 1,577 1,661
Public authorities.................... 1,333 1,311 1,290
-------- -------- --------
Total.............................. 286,547 283,948 281,390
======== ======== ========
Operating Revenues (thousands)
Residential........................... $161,254 $127,532 $124,950
Commercial............................ 44,321 36,148 34,942
Industrial............................ 14,890 18,633 22,152
Public authorities.................... 15,248 12,516 11,961
Other................................. 9,366 8,953 7,033
-------- -------- --------
Total.............................. $245,079 $203,782 $201,038
======== ======== ========
Residential Statistics
(per customer-average)
Sales - MCF........................... 110.2 107.0 103.8
Revenue............................... $617.33 $492.33 $487.69
Rate per MCF (Month of December)...... $ 5.66 $ 5.27 $ 4.16
I-20
Item 2- PROPERTIES
Electric
- --------
Information relating to the Company's electric
properties is contained in Item 1 - BUSINESS, THE COMPANY
(page I-1), CONSTRUCTION AND FINANCING PROGRAM OF THE COMPANY
(pages I-4 through I-6), ELECTRIC OPERATIONS AND FUEL SUPPLY
(pages I-6 through I-8) and Item 8 - Notes 2 and 7 of Notes to
Consolidated Financial Statements on pages II-14 and II-19,
respectively, which pages are incorporated herein by reference.
Gas
- ---
Information relating to the Company's gas properties
is contained in Item 1 - BUSINESS, THE COMPANY (page I-1), and
GAS OPERATIONS AND GAS SUPPLY (pages I-8 through I-11), which
pages are incorporated herein by reference.
Steam
- -----
The Company owns two steam generating plants and the
steam distribution facility serving downtown Dayton, Ohio.
Other
- -----
The Company owns a number of area service buildings
located in various operating centers.
Substantially all property and plant of the Company is
subject to the lien of the Mortgage securing the Company's First
Mortgage Bonds.
Item 3 - LEGAL PROCEEDINGS
Information relating to legal proceedings involving
the Company is contained in Item 1 - BUSINESS, THE COMPANY
(page I-1), GAS OPERATIONS AND GAS SUPPLY (pages I-8 through
I-11), RATE REGULATION AND GOVERNMENT LEGISLATION (pages I-11
through I-15), ENVIRONMENTAL CONSIDERATIONS (pages I-15 through
I-18) and Item 8 - Note 2 of Notes to Consolidated Financial
Statements on page II-14, which pages are incorporated herein by
reference.
Item 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
None.
I-21
PART II
- -------
Item 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's common stock is held solely by DPL Inc.
and as a result is not listed for trading on any stock exchange.
The information required by this item of Form 10-K is
set forth in Item 8 - Selected Quarterly Information on page
II-24 and the Financial and Statistical Summary on page II-25,
which pages are incorporated herein by reference.
The Company's Mortgage restricts the payment of
dividends on the Company's Common Stock under certain
conditions. In addition, so long as any Preferred Stock is
outstanding, the Company's Amended Articles of Incorporation
contain provisions restricting the payment of cash dividends on
any of its Common Stock if, after giving effect to such
dividend, the aggregate of all such dividends distributed
subsequent to December 31, 1946 exceeds the net income of the
Company available for dividends on its Common Stock subsequent
to December 31, 1946, plus $1,200,000. As of year end, all
earnings reinvested in the business of the Company were
available for Common Stock dividends.
The Credit Agreement requires that the aggregate
assets of the Company and its subsidiaries constitute not less
than 60% of the total consolidated assets of DPL Inc., and that
the Company maintain common shareholder's equity (as defined in
the Credit Agreement) at least equal to $550 million.
Item 6 - SELECTED FINANCIAL DATA
The information required by this item of Form 10-K is
set forth in Item 8 - Financial and Statistical Summary on page
II-25, which page is incorporated herein by reference.
II-1
Item 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The Dayton Power and Light Company
Performance Highlights 1993 1992 1991
- -------------------------------------------------------------------------------------------------------
CAPITAL INVESTMENT PERFORMANCE:
Capital Structure (millions)
Common shareholder's equity...........................$ 1,049.2 1,022.0 995.9
Preferred stock.......................................$ 112.9 121.4 125.7
Long-term debt........................................$ 1,012.9 952.1 996.4
------- ------- -------
Total...............................................$ 2,175.0 2,095.5 2,118.0
OPERATING PERFORMANCE:
Electric--
Sales (millions of kWh)
Residential............................................ 4,558 4,260 4,571
Commercial............................................. 3,006 2,896 2,945
Industrial............................................. 4,089 3,938 3,949
Other.................................................. 3,023 2,960 1,850
------- ------- -------
Total................................................ 14,676 14,054 13,315
Revenues (millions)
Residential...........................................$ 373.8 326.5 332.1
Commercial............................................$ 200.1 180.9 178.9
Industrial............................................$ 206.0 189.7 186.8
Other.................................................$ 121.4 112.2 92.9
------- ------- -------
Total...............................................$ 901.3 809.3 790.7
Average price per kWh--retail and wholesale customers
(calendar year)...................................cents 6.07 5.69 5.87
Gas--
Sales (thousands of MCF)
Residential............................................ 28,786 27,723 26,594
Commercial............................................. 8,468 8,642 8,368
Industrial............................................. 3,056 4,914 6,014
Other.................................................. 16,572 14,213 11,681
------- ------- -------
Total................................................ 56,882 55,492 52,657
Revenues (millions)
Residential...........................................$ 161.3 127.5 125.0
Commercial............................................$ 44.3 36.2 34.9
Industrial............................................$ 14.9 18.6 22.1
Other.................................................$ 24.6 21.5 19.0
------- ------- -------
Total...............................................$ 245.1 203.8 201.0
Average price per MCF--all customers (calendar year)....$ 5.42 4.36 4.39
II-2
Results of Operations
- ---------------------
The 1993 earnings on common stock are $135 million compared
to $133 million in 1992 and $118 million in 1991.
Electric revenues increased 11% in 1993 and 2% in 1992.
Warm summer temperatures contributed to a 4% sales increase.
Implementation of the second phase of the electric rate increase
of 6.4% in January 1993 also contributed to the increase in
revenues. (See Financial Statement Note 2.) An overall sales
increase of 6% in 1992 reflected strong sales to other utilities
despite mild temperatures throughout the year.
Gas revenues increased 20% in 1993 due to significantly
higher gas cost rates. A 6.2% increase in base rates in March
1992 contributed to the increased revenues. Gas sales increased
by 3%. Gas revenues increased 1% in 1992 with lower gas cost
rates offsetting increased weather-related sales of 5%.
In 1993, interest and other income included $6 million of
interest income associated with a federal income tax refund from
the 1986-1988 audit period.
Operating and administrative expenses increased 16% in 1993
and decreased 5% in 1992. Included are redemption premiums and
other refinancing costs of $23 million in 1993 and $9 million in
1992. Maintenance expense increased 18% in 1993 and decreased
16% in 1992 reflecting changes in the level of planned
maintenance programs on the Company's production and
distribution equipment. Operating, administrative and
maintenance expenses are expected to stabilize in 1994.
Regulatory deferrals decreased in 1993 with the January
implementation of the second phase of the Company's electric
price increase. With this increase, current prices reflect more
cost recovery and reduce the deferral needed to recognize the
full revenue requirements of the phase-in plan. The phase-in
plan established a baseline return on equity of 13% (subject to
upward adjustment). In the event the return exceeds the allowed
return by between one to two percent, then one half of the
excess return will be used to reduce the cost of demand-side
management programs, and any return that exceeds the allowed
return by more than two percent will be entirely credited to
these programs.
Allowance for Funds Used During Construction ("AFC")
relating to the William H. Zimmer Generating Station ("Zimmer")
ceased upon its completion in March 1991. Prior to this
essentially all AFC related to Zimmer.
II-3
Total income taxes increased in 1993 and 1992 resulting from
higher pre-tax income. Additionally, in 1993, the corporate tax
rate was increased to 35% as enacted by the Omnibus Budget
Reconciliation Act of 1993, increasing income taxes $3 million.
Adopting FASB Statement No. 109 resulted in changes to the
consolidated balance sheet. The increase in total assets is due
to an increase in deferred interest-Zimmer (see Financial
Statement Note 2) of $23 million and the recognition of income
taxes recoverable through future revenues of $260 million.
Offsetting these assets were additional deferred tax liabilities
of $283 million.
Credit Ratings
- --------------
In July 1993, the Company's bond and preferred stock ratings
were raised by Duff & Phelps, a credit rating agency. First
mortgage bonds are now rated "AA-" and preferred stock is rated
"A+". This upgrade reflects the Company's significantly
improved financial performance and favorable qualitative credit
factors.
During the first quarter of 1992, the Company's bond,
preferred stock and commercial paper ratings were upgraded by
three credit rating agencies. Bonds were upgraded to "A2" by
Moody's Investors Service, "A+" by Duff & Phelps and "A" by
Standard & Poor's. These upgrades reflect the positive outcome
of the Zimmer coal conversion project and rate settlement
agreement. Each of these bond ratings is considered investment
grade.
Construction Program and Financing
- ----------------------------------
Construction additions were $79 million, $58 million and
$116 million in 1993, 1992 and 1991, respectively. For the
period 1994 through 1998, total construction additions are
projected to be $502 million with a total of $105 million
occurring in 1994. During this same period, a total of
$106 million will be required for sinking funds and mandatory
redemptions for preferred stock and bonds.
During 1993, total cash provided by operating activities was
$246 million. At year end, cash and temporary investments were
$6 million and short-term borrowings were $30 million.
During late 1992 and early 1993, the Company took advantage
of favorable market conditions to reduce its cost of debt and
extend maturities through early refundings. Overall, five new
series of First Mortgage Bonds were issued, aggregating
approximately $766 million with an average interest rate of
7.9%. The proceeds were used to finance the redemption of a
similar principal amount of debt securities with an average
interest rate of 8.7%.
II-4
Issuance of additional amounts of First Mortgage Bonds by
the Company is limited by provisions of its mortgage. At
December 31, 1993, more than $500 million of additional bonds
could have been issued. The amounts and timing of future
financings will depend upon market and other conditions, rate
increases, levels of sales and construction plans.
DPL Inc. has a revolving credit agreement, renewable through
1998, which allows total borrowings by DPL Inc. and its
subsidiaries of $200 million. At year end 1993, DPL Inc. had no
borrowings outstanding under this credit agreement. At
December 31, 1992, DPL Inc. had $90 million outstanding under
the revolving credit agreement which was used to fund share
purchases for DPL Inc.'s Employee Stock Ownership Plan. These
borrowings were repaid in January 1993 with the proceeds from
the issuance of $90 million of DPL Inc. 7.83% Notes due 2007.
The Company also has $97 million available in short-term
lines of credit. At year end, the Company had $10 million
outstanding from these lines of credit at a weighted average
interest rate of 3.68% and $15 million in commercial paper
outstanding at weighted average interest rate of 3.34%.
Issues and Financial Risks
- --------------------------
As a public utility, the Company is subject to processes
which determine the rates it charges for energy services.
Regulators determine which costs are eligible for recovery in
the rate setting process and when the recovery will occur. They
also establish the rate of return on utility investments which
are valued under Ohio law based on historical costs. The
utility industry is subject to inflationary pressures similar to
those experienced by other capital-intensive industries.
Because rates for regulated services are based on historical
costs, cash flows may not cover the total future costs of
providing services. Construction costs over the next five years
average $100 million annually which approximates the projected
depreciation over the same period.
The passage of the National Energy Policy Act allows the
federal government to mandate access by others to a utility's
transmission system and may accelerate competition in the supply
of electricity.
In 1992, FERC issued Order 636 (the "Order") amending its
regulations governing the service obligations, rate design and
cost recovery of interstate pipelines. In response to the
Order, the PUCO has approved interim guidelines for its
implementation and is continuing efforts to examine the impact
via round-table discussions. In 1993, the Company implemented
the requirements of the Order.
II-5
In January 1994, the Company, the Staff of the PUCO and the
Office of the OCC submitted to the PUCO an agreement which
resolves issues relating to the recovery of "transition costs" to
be billed to the Company by interstate pipeline companies. The
agreement, which is subject to PUCO approval, provides for the
full recovery of these transition costs from customers. The
interstate pipelines will file with the FERC in 1994 for authority
to recover these transition costs, the exact magnitude of which
has not been established.
The U.S. EPA has estimated total costs of $56 million for its
preferred clean-up plans of three hazardous waste sites in Ohio.
The U.S. EPA notified numerous parties, including the Company,
that they are considered "Potentially Responsible Parties" for
cleanup of these sites. The final resolution of these
investigations will not have a material effect on the Company's
financial position, earnings or cash flow.
Changing environmental regulations continue to increase the
cost of providing service in the utility industry. The Clean Air
Act Amendments of 1990 (the "Act") limit sulfur dioxide and
nitrogen oxide emissions nationwide. The Act will restrict
emissions in two phases with Phase I compliance completed by 1995
and Phase II completed by 2000.
In May 1993, the PUCO approved the Company's Clean Air Act
Compliance Plan. This plan outlines the methods by which the
emission reduction requirements will be met. Overall compliance
is expected to have a minimal 1% to 2% price impact. The Company
anticipates that costs to comply with the Act will be eligible for
recovery in future fuel hearings and other regulatory proceedings.
Income Statement Highlights
$ in millions 1993 1992 1991
- ---------------------------------------------------------------
Electric Utility:
Revenues..................... $901 $809 $791
Fuel used in production...... 225 219 235
---- ---- ----
Net revenues............... 676 590 556
Gas Utility:
Revenues..................... 245 204 201
Gas purchased for resale..... 156 118 130
---- ---- ----
Net revenues............... 89 86 71
Interest and other income...... 12 4 4
Operating and administrative... 181 155 163
Maintenance of equipment and
facilities................... 90 76 90
Regulatory deferrals........... (26) (59) (43)
Income taxes................... 76 64 40
Earnings on common stock....... 135 133 118
II-6
Item 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements Page No.
- ------------------------------------------ --------
Consolidated Statement of Results of
Operations for the three years in the
period ended December 31, 1993............... II-8
Consolidated Statement of Cash Flows
for the three years in the period ended
December 31, 1993............................ II-9
Consolidated Balance Sheet as of
December 31, 1993 and 1992................... II-10 - II-11
Notes to Consolidated Financial Statements... II-12 - II-23
Reports of Independent Accountants........... II-26 - II-27
Index to Supplemental Information Page No.
- --------------------------------- --------
Selected Quarterly
Information............................ II-24
Financial and Statistical
Summary................................ II-25
II-7
The Dayton Power and Light Company
CONSOLIDATED STATEMENT OF RESULTS OF OPERATIONS
- ---------------------------------------------------------------------------------------------------
For the years ended December 31,
$ in millions 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
INCOME
Utility service revenues--
Electric . . . . . . . . . . . . . . . . . . . . . $ 901.3 $ 809.3 $ 790.7
Gas . . . . . . . . . . . . . . . . . . . . . . . 245.1 203.8 201.0
Steam . . . . . . . . . . . . . . . . . . . . . . 7.3 6.7 6.3
-------------------------------------
Total utility service revenues . . . . . . . . 1,153.7 1,019.8 998.0
Interest and other income . . . . . . . . . . . . . . 11.5 3.5 4.1
-------------------------------------
Total income . . . . . . . . . . . . . . . . . 1,165.2 1,023.3 1,002.1
-------------------------------------
EXPENSES
Fuel used in electric and steam production . . . . . 226.6 220.7 237.4
Gas purchased for resale . . . . . . . . . . . . . . 156.4 117.6 130.4
Operating and administrative (Note 1) . . . . . . . 180.8 155.2 162.6
Maintenance of equipment and facilities . . . . . . 89.6 76.1 90.3
Depreciation and amortization . . . . . . . . . . . 109.0 104.4 94.2
General taxes . . . . . . . . . . . . . . . . . . . 111.7 108.2 95.1
Interest expense . . . . . . . . . . . . . . . . . . 97.4 94.3 93.1
Regulatory deferrals (Note 2) . . . . . . . . . . . (25.8) (58.7) (43.0)
Allowance for funds used during construction . . . . (0.5) (0.3) (25.6)
-------------------------------------
Total Operating Expenses . . . . . . . . . . . 945.2 817.5 834.5
-------------------------------------
Operating Income . . . . . . . . . . . . . . . . . . 220.0 205.8 167.6
Income taxes . . . . . . . .. . . . . . . . . . . . 76.4 63.8 40.2
-------------------------------------
Net Income . . . . . . . . . . . . . . . . . . . . . 143.6 142.0 127.4
Preferred dividends . . . . . . . . . . . . . . . . 8.7 9.4 9.7
-------------------------------------
Earnings on Common Stock . . . . . . . . . . . . . . $ 134.9 $ 132.6 $ 117.7
=====================================
See Notes to Consolidated Financial Statements.
II-8
The Dayton Power and Light Company
CONSOLIDATED STATEMENT OF CASH FLOWS
- ------------------------------------------------------------------------------------------------------
For the years ended December 31,
$ In millions 1993 1992 1991
- ------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Cash received from utility customers . . . . . . . . . . $1,140.0 $1,006.3 $ 996.9
Other operating cash receipts . . . . . . . . . . . . . . 13.0 4.4 4.4
Cash paid for:
Fuel and purchased power . . . . . . . . . . . . . . . (216.6) (234.0) (223.3)
Purchased gas . . . . . . . . . . . . . . . . . . . . (146.9) (137.5) (124.0)
Operation and maintenance labor . . . . . . . . . . . (80.3) (84.2) (80.3)
Nonlabor operating expenditures . . . . . . . . . . . (218.4) (144.2) (166.0)
Interest (net of amounts capitalized) . . . . . . . . (86.9) (97.0) (84.0)
Income taxes . . . . . . . . . . . . . . . . . . . . . (46.6) (44.4) (45.3)
Property, excise and payroll taxes . . . . . . . . . . (111.1) (98.4) (92.1)
-------- -------- --------
Net cash provided by operating activities . . . . . . . 246.2 171.0 186.3
-------- -------- --------
INVESTING ACTIVITIES
Net cash used for property expenditures and other . . . . (88.6) (61.5) (106.3)
-------- -------- --------
FINANCING ACTIVITIES
Dividends paid on common stock . . . . . . . . . . . . . (107.8) (103.6) (111.8)
Dividends paid on preferred stock . . . . . . . . . . . . (8.8) (9.4) (9.7)
Retirement of long-term debt . . . . . . . . . . . . . . (439.2) (321.0) (4.6)
Retirement of preferred stock . . . . . . . . . . . . . . (8.5) (4.3) (4.2)
Issuance of long-term debt . . . . . . . . . . . . . . . 446.0 320.4 -
Issuance (retirement) of short-term debt . . . . . . . . (37.0) (21.9) 40.4
Receipt of funds on deposit with trustee . . . . . . . . - 21.7 -
-------- -------- --------
Net cash used for financing activities . . . . . . . . . (155.3) (118.1) (89.9)
-------- -------- --------
Net increase (decrease) in cash and temporary cash
investments . . . . . . . . . . . . . . . . . . . . . 2.3 (8.6) (9.9)
Cash and temporary cash investments at beginning of
period . . . . . . . . . . . . . . . . . . . . . . . . 3.7 12.3 22.2
-------- -------- --------
Cash and temporary cash investments at end of period . . $ 6.0 $ 3.7 $ 12.3
======== ======== ========
See Notes to Consolidated Financial Statements.
II-9
The Dayton Power and Light Company
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------------------------------
At December 31,
$ in millions 1993 1992
- --------------------------------------------------------------------------------------------------
ASSETS
Electric property and plant . . . . . . . . . . . . . $2,923.8 $2,864.4
Gas property and plant . . . . . . . . . . . . . . . . 240.1 223.9
Steam and other property and plant . . . . . . . . . . 32.1 31.2
Construction work in progress . . . . . . . . . . . . 35.8 42.7
-------- --------
3,231.8 3,162.2
Less--
Accumulated depreciation and amortization . . . . . . (950.6) (857.6)
-------- --------
Net property and plant . . . . . . . . . . . . . . 2,281.2 2,304.6
-------- --------
CURRENT ASSETS
Cash and temporary cash investments (at cost) . . . . 6.0 3.7
Accounts receivable, less provision for uncollectible
accounts of $9.1 and $10.5, respectively . . . . . 130.1 126.3
Inventories, at average cost . . . . . . . . . . . . . 85.4 85.8
Taxes applicable to subsequent years . . . . . . . . . 72.8 70.6
Gas costs recoverable . . . . . . . . . . . . . . . . 23.1 11.7
Prepayments and other . . . . . . . . . . . . . . . . 44.7 50.7
-------- --------
Total current assets . . . . . . . . . . . . . . . 362.1 348.8
-------- --------
OTHER ASSETS
Regulatory deferrals (Note 2) . . . . . . . . . . . . 172.8 103.8
Income taxes recoverable through future
revenues (Note 3) . . . . . . . . . . . . . . . . . 269.1 -
Other assets . . . . . . . . . . . . . . . . . . . . . 129.1 109.5
-------- --------
Total other assets . . . . . . . . . . . . . . . . 571.0 213.3
-------- --------
Total Assets . . . . . . . . . . . . . . . . . . . . . $3,214.3 $2,866.7
======== ========
II-10
The Dayton Power and Light Company
CONSOLIDATED BALANCE SHEET
(continued)
- --------------------------------------------------------------------------------------------------
At December 31,
$ in millions 1993 1992
- --------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common shareholder's equity-- (Note 8)
Common stock . . . . . . . . . . . . . . . . . . . . $ 0.4 $ 0.4
Other paid-in capital . . . . . . . . . . . . . . . . 675.2 675.0
Earnings reinvested in the business . . . . . . . . . 373.6 346.6
-------- --------
Total common shareholder's equity . . . . . . . . . 1,049.2 1,022.0
-------- --------
Preferred stock-- (Note 9)
Without mandatory redemption provisions . . . . . . . 82.9 82.9
With mandatory redemption provisions . . . . . . . . 30.0 38.5
Long-term debt (Note 5) . . . . . . . . . . . . . . . 1,012.9 952.1
-------- --------
Total capitalization . . . . . . . . . . . . . . . 2,175.0 2,095.5
-------- --------
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . . . . . . 113.7 91.3
Short-term debt (Note 6) . . . . . . . . . . . . . . . 29.8 66.8
Current portion of first mortgage bonds
and preferred stock . . . . . . . . . . . . . . . . . 9.0 59.0
Accrued taxes . . . . . . . . . . . . . . . . . . . . 113.6 104.3
Accrued interest . . . . . . . . . . . . . . . . . . . 21.1 12.4
Other . . . . . . . . . . . . . . . . . . . . . . . . 51.3 50.0
-------- --------
Total current liabilities . . . . . . . . . . . . . 338.5 383.8
-------- --------
DEFERRED CREDITS AND OTHER
Deferred taxes (Note 3) . . . . . . . . . . . . . . . 536.2 232.0
Unamortized investment tax credit . . . . . . . . . . 84.9 87.4
Other . . . . . . . . . . . . . . . . . . . . . . . . 79.7 68.0
-------- --------
Total deferred credits and other . . . . . . . . . 700.8 387.4
-------- --------
Total Capitalization and Liabilities . . . . . . . . . $3,214.3 $2,866.7
======== ========
See Notes to Consolidated Financial Statements.
II-11
The Dayton Power and Light Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ----------------------------------------------------------------
PRINCIPLES OF CONSOLIDATION
The accounts of the Company and its wholly-owned subsidiaries
are included in the accompanying consolidated financial
statements. The consolidated financial statements principally
reflect the results of operations and financial condition of the
Company. The results of operations of the Company's
subsidiaries currently do not have a material financial impact
on the consolidated results.
REVENUES AND FUEL
Revenues include amounts charged to customers through fuel and
gas recovery clauses, which are adjusted periodically for
changes in such costs. Related costs that are recoverable or
refundable in future periods are deferred along with the related
income tax effects. Also included in revenues are amounts
charged to customers through a surcharge for recovery of
arrearages from certain eligible low-income households.
The Company records revenue for services provided but not yet
billed to more closely match revenues with expenses. "Accounts
Receivable" on the Consolidated Balance Sheet includes unbilled
revenue of (in millions) $30.0 in 1993 and $27.8 in 1992.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION ("AFC")
AFC represents the cost of capital funds (equity and debt) used
to finance construction projects. This cost is included in
construction work in progress along with other construction
costs. Essentially all AFC ceased upon completion of the
William H. Zimmer Generating Station ("Zimmer") in March 1991.
The average rate for 1991 was 10.3%, compounded semi-annually,
net of income taxes.
OPERATING AND ADMINISTRATIVE
Operating and administrative expense includes $22.8 million in
1993 and $9.1 million in 1992 of redemption premiums and other
costs relating to the refinancing of various bond issues. (See
Note 5.)
II-12
PROPERTY AND PLANT, MAINTENANCE AND DEPRECIATION
Property and plant is shown at its original cost. When a unit
of property is retired, the original cost of that property plus
the cost of removal less any salvage value is charged to
accumulated depreciation. Maintenance costs and replacements of
minor items of property are charged to expense.
Depreciation expense is calculated using the straight-line
method, which depreciates the cost of property over its
estimated useful life, at an annual rate which approximates 3.4%
for 1993, 1992 and 1991.
INCOME TAXES
In 1993, the Company implemented Financial Accounting Standards
Board ("FASB") Statement No. 109, "Accounting for Income
Taxes." The new statement requires a change from the deferral
method to the liability method for income tax accounting. Under
the liability method, deferred taxes are provided for all
differences between the financial statement basis and the tax
basis of assets and liabilities using the enacted tax rate.
Additional deferred income taxes and offsetting regulatory
assets or liabilities are recorded to recognize that the income
taxes will be recoverable/refundable through future revenues.
(See Note 3.)
CONSOLIDATED STATEMENT OF CASH FLOWS
The temporary cash investments presented on this Statement
consist of liquid investments with an original maturity of three
months or less.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The reported value of short-term financial instruments and other
investments on the balance sheet approximates fair value. The
long-term debt and preferred stock fair values are disclosed in
Notes 5 and 9, respectively.
RECLASSIFICATIONS
Reclassifications have been made in certain prior years' amounts
to conform to the current reporting presentation.
II-13
2. ELECTRIC RATE MATTERS
- ----------------------------------------------------------------
Pursuant to a PUCO-approved settlement agreement among the
Company and various consumer groups, an electric rate increase
was phased in with annual increases of 6.4% effective February
1992, January 1993 and January 1994. Deferrals (including
carrying charges) during the phase-in period of $28.1 million in
1993 and $57.7 million in 1992 were capitalized and will be
recovered over seven years commencing in 1994. The phase-in
plan meets the requirements of FASB Statement No. 92.
This settlement included an agreement by the Company to
undertake cost-effective demand-side management ("DSM") programs
with an average annual cost of $15 million for four years
commencing in 1992. The amount recovered in rates was
$4.6 million in 1992. This amount increases to $7.8 million in
1993 and subsequent years. The difference between expenditures
and amounts recovered through rates is deferred and is eligible
for future recovery in accordance with existing PUCO rulings.
The agreement established a baseline return on equity of 13%
(subject to upward adjustment). In the event that the return
exceeds the allowed return by between one to two percent, then
one half of the excess return will be used to reduce the cost of
DSM programs, and any return that exceeds the allowed return by
more than two percent will be entirely credited to these
programs.
The Company also deferred interest charges, net of income
taxes, on its investment in Zimmer from the March 30, 1991,
commercial in-service date through January 31, 1992, pursuant to
PUCO approval. Deferred interest charges on the investment in
Zimmer have been adjusted to a before tax basis in 1993 as a
result of FASB Statement No. 109. Amounts deferred are being
amortized over the life of Zimmer.
Regulatory deferrals on the balance sheet were:
At December 31,
1993 1992
------- -------
--millions--
Phase-in $ 85.8 $ 57.7
DSM 23.3 2.2
Deferred interest-Zimmer 63.7 43.9
------ -----
Total $172.8 $103.8
====== ======
II-14
- -------------------------------------------------------------------------------
3. INCOME TAXES
Adopting FASB Statement No. 109 at January 1, 1993, resulted in an increase in
deferred interest-Zimmer (see Note 2) of $22.6 million and the recognition of
income taxes recoverable through future revenues of $259.6 million. Offsetting
these assets is an additional $282.5 million of deferred tax liabilities.
For the years ended December 31,
$ in millions 1993 1992 1991
- ------------- --------------------------------
COMPUTATION OF TAX EXPENSE
Statutory income tax rate . . . . . . . . . . . . . . . . . . . . 35% 34% 34%
Federal income tax (statutory rates applied to pretax income
before preferred dividends and before tax expenses included
in regulatory deferrals) . . . . . . . . . . . . . . . . . . . . $77.0 $70.4 $64.5
Increases (decreases) in tax from -
Regulatory deferrals . . . . . . . . . . . . . . . . . . . . . . (6.1) (12.4) -
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2 9.3 (0.2)
Investment tax credit amortized . . . . . . . . . . . . . . . . (3.0) (3.0) (3.3)
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . (1.7) 0.9 1.4
-------------------------------
Total Tax Expense . . . . . . . . . . . . . . . . . . . . . . $76.4 $65.2 $62.4
===============================
Effective Tax Rate . . . . . . . . . . . . . . . . . . . . . 35% 32% 33%
COMPONENTS OF TAX EXPENSE
Taxes currently payable . . . . . . . . . . . . . . . . . . . . . . 54.3 $31.9 $43.9
Deferred taxes--
Regulatory deferrals . . . . . . . . . . . . . . . . . . . . . . 8.1 9.2 22.2
Liberalized depreciation and amortization . . . . . . . . . . . 17.6 18.6 13.2
Property taxes . . . . . . . . . . . . . . . . . . . . . . . . . (6.1) (5.9) (4.9)
Fuel and gas costs . . . . . . . . . . . . . . . . . . . . . . . 5.8 10.5 (7.9)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.8) 4.4 (2.5)
Deferred investment tax credit, net . . . . . . . . . . . . . . . . (2.5) (3.5) (1.6)
-------------------------------
Total Tax Expense . . . . . . . . . . . . . . . . . . . . . $76.4 $65.2 $62.4
===============================
CLASSIFICATION OF TAX EXPENSE
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . $76.4 $63.8 $40.2
Regulatory deferrals . . . . . . . . . . . . . . . . . . . . . . . - 1.4 22.2
-------------------------------
Total Tax Expense . . . . . . . . . . . . . . . . . . . . . . $76.4 $65.2 $62.4
===============================
COMPONENTS OF DEFERRED TAX ASSETS AND LIABILITIES AT DECEMBER 31, 1993
Depreciation/property basis . . . . . . . . . . $(429.6)
Regulatory deferrals . . . . . . . . . . . . . (57.4)
Income taxes recoverable. . . . . . . . . . . . (93.8)
Investment tax credit . . . . . . . . . . . . . 29.7
Other . . . . . . . . . . . . . . . . . . . . . 14.9
-------
Net non-current liability. . . . . . . . . . $(536.2)
=======
Net current liability . . . . . . . . . . . $ (13.4)
=======
II-15
- ------------------------------------------------------------------------------
4. PENSIONS AND POSTRETIREMENT BENEFITS
A. PENSIONS
Substantially all Company employees participate in pension plans paid for by
the Company. Employee benefits are based on their years of service, age at
retirement and, for salaried employees, their compensation. The plans are
funded in amounts actuarially determined to provide for these benefits.
An interest rate of 6.0% was used in 1993 and 1992 in developing the amounts
in the following tables. Actual returns on plan assets for 1993 and 1992,
respectively, were 6.2% and 8.8%. Increases in compensation levels
approximating 5% were used for all years.
The following table presents the components of pension cost (portions of which
were capitalized):
$ in millions 1993 1992 1991
- ------------- ---------------------------
Service cost - benefits earned . . . . . . . . . . . . . . . . . . . . . . . $ 5.4 $ 4.3 $ 3.5
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.0 12.5 11.8
Expected return on plan assets of 7.5% in each year . . . . . . . . . . . . . (16.9) (15.2) (14.1)
Amortization amounts, net . . . . . . . . . . . . . . . . . . . . . . . . . . (2.0) (2.6) (2.9)
---------------------------
Net pension cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (1.5) $ (1.0) $ (1.7)
===========================
The following table sets forth the plans' funded status at December 31:
$ in millions 1993 1992
- ------------- ----------------
Plan assets at fair value (a) . . .. . . . . . . . . . . . . . . . . . . . . . $255.0 $236.3
Less -
Actuarial present value of projected benefit obligation . . . . . . . . . . 230.6 210.5
----------------
Plan assets in excess of projected benefit obligation . . . . . . . . . . . . $ 24.4 $ 25.8
================
Vested benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . $183.9 $166.2
Accumulated benefit obligation without projected salary increases . . . . . . $207.4 $187.1
(a) Invested in guaranteed investment contracts, fixed income investments and equities including
$22.5 million and $21.6 million of DPL Inc. common stock in 1993 and 1992, respectively.
The following table shows the amounts recorded in Other Assets in the Consolidated Balance Sheet
at December 31:
$ in millions 1993 1992
- ------------- ----------------
Plan assets in excess of projected benefit obligation . . . . . . . . . . . . $ 24.4 $ 25.8
Transitional adjustments for amounts not reflected on the
Consolidated Balance Sheet
Unamortized transition amount . . . . . . . . . . . . . . . . . . . . . . (28.0) (32.1)
Prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.9 12.0
Changes in plan assumptions and actuarial gains and losses . . . . . . . . 25.1 23.5
----------------
Net pension assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 44.4 $ 29.2
================
II-16
B. POSTRETIREMENT BENEFITS
In 1993, the Company adopted FASB Statement No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." Previously, the Company had used
an accrual method to recognize these costs which approximated FASB Statement
No. 106 amounts. Implementation did not create regulatory deferrals or have a
material impact on expense.
Qualified employees who retired prior to 1987 and their dependents are eligible
for health care and life insurance benefits. The unamortized transition
obligation associated with these benefits is being amortized over the
approximate average remaining life expectancy of the retired employees. Active
employees are eligible for life insurance benefits, and this unamortized
transition obligation is being amortized over the average remaining service
period.
The following table sets forth the accumulated postretirement benefit amounts
at December 31:
$ in millions 1993
- ------------- -----
Accumulated postretirement benefit obligation
- retirees and dependents . . . . . . . . . . . . . . . . . . . . . . . . . $63.1
- active employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2
-----
Total 64.3
Unamortized transition obligation . . . . . . . . . . . . . . . . . . . . . . 27.7
-----
Accrued postretirement benefit liability . . . . . . . . . . . . . . . . . . . $36.6
=====
The following table presents the components of postretirement benefit costs:
$ in millions 1993
- ------------- -----
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3.7
Amortization of transition obligation . . . . . . . . . . . . . . . . . . . . 3.0
-----
Net periodic postretirement benefit cost . . . . . . . . . . . . . . . . . . . $ 6.7
=====
The assumed health care cost trend rate used in measuring the unfunded
accumulated postretirement benefit obligation is 15% for 1993 and decreases to
8% by 2004. A one percentage point increase in each future year's assumed
health care trend rate would increase net periodic postretirement benefit cost
by $0.4 million annually and would increase the accumulated postretirement
benefit obligation by $6.4 million. The weighted average discount rate used in
determining the accumulated postretirement benefit obligation was 6.0%.
II-17
- -------------------------------------------------------------------------------------------------------------
5. LONG-TERM DEBT
At December 31,
$ in millions 1993 1992
- ------------- ----------------------
First mortgage bonds maturing:
1997 5-5/8% . . . . . . . . . . . . . . . . . . . . . . . . . $ 40.0 $ 40.0
1998 7.06% and 7.22% (a) . . . . . . . . . . . . . . . . . . . 29.0 31.7
1999-2003 8.41% and 8.51% (a) . . . . . . . . . . . . . . . . . . . 49.0 210.0
2022-2026 8.14% and 8.67% (a) . . . . . . . . . . . . . . . . . . . 671.0 450.0
Pollution control series maturing through 2027 - 7.97% . . . . . . . . . 218.8 219.1
----------------------
1,007.8 950.8
Unamortized debt discount and premium (net) . . . . . . . . . . . . . . . (2.5) (6.5)
----------------------
1,005.3 944.3
Mortgage note due in installments through 2012-10.0% . . . . . . . . . . . . . . 7.6 7.8
----------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,012.9 $ 952.1
======================
Fair value (including current portion)-based upon quoted market price or debt
with similar characteristics . . . . . . . . . . . . . . . . . . . . . . $1,090.9 $1,066.2
(a) Weighted average interest rates for 1993 and 1992, respectively.
The amounts of maturities and mandatory redemptions for first mortgage bonds
are (in millions) $4.7 in 1994, 1995 and 1996, $44.8 in 1997 and $25.4 in
1998. Substantially all property and plant of the Company is subject to the
mortgage lien securing first mortgage bonds.
New debt was issued during 1993 as follows:
Principal Amount
Issuances ($ in millions)
--------- ----------------
First Mortgage Bonds:
8.15% Series due 2026 $226.0
7-7/8% Series due 2024 220.0
------
Total $446.0
Proceeds of these financings were used to call several series of bonds and to
repay short-term debt. There are no sinking fund provisions associated with
any of these new debt issues.
II-18
- -------------------------------------------------------------------------------
6. NOTES PAYABLE AND COMPENSATING BALANCES
DPL Inc., the Company's parent company, has $200 million available through a
revolving credit agreement. This agreement with a consortium of banks is
renewable through 1998. Commitment fees are approximately $350,000 per year,
depending upon the aggregate unused balance of the loan. At December 31, 1993,
DPL Inc. had no outstanding borrowings under this credit agreement.
The Company also has $97.1 million available in short-term informal lines of
credit. To support these lines of credit, the Company is required to maintain
average daily compensating balances of approximately $700,000 and also pay
$189,000 per year in fee compensation. At year-end, the Company had
$10 million outstanding from these lines of credit at a weighted average
interest rate of 3.68% and $15 million in commercial paper outstanding at a
weighted average interest rate of 3.34%.
- -------------------------------------------------------------------------------
7. COMMONLY OWNED FACILITIES
The Company owns certain electric generating and transmission facilities as
tenants in common with other Ohio utilities. Each utility is obligated to pay
its ownership share of construction and operation costs of each facility. As
of December 31, 1993, the Company had $12.3 million of commonly owned
facilities under construction. The Company's share of expenses is included in
the Consolidated Statement of Results of Operations.
The following table represents the Company's share of the commonly owned
facilities:
Company Share Investment
--------------------------- ---------------
Production Plant in
Ownership Capacity Service
-----------------------------------------------
(%) (MW) ($ in millions)
Production Units:
Beckjord Unit 6 . . . . . . . . . . . . . 50.0 210 50
Conesville Unit 4 . . . . . . . . . . . . 16.5 129 29
East Bend Station . . . . . . . . . . . . 31.0 186 147
Killen Station . . . . . . . . . . . . . . 67.0 402 405
Miami Fort Units 7 & 8 . . . . . . . . . . 36.0 360 112
Stuart Station . . . . . . . . . . . . . . 35.0 820 226
Zimmer Generating Station . . . . . . . . 28.1 365 985
Transmission (at varying percentages) . . . . 66
II-19
- -------------------------------------------------------------------------------------------------------------
8. COMMON SHAREHOLDER'S EQUITY
Common Stock (a)
--------------------- Other Paid-in Earnings
Outstanding Capital (premium, Reinvested in
$ in millions Shares Amount net of expense) the Business Total
- ------------------------------------------------------------------------------------------------------------
1991:
Beginning Balance . . . . . . . 41,172,173 $ 0.4 $674.6 $315.0 $ 990.0
Net income . . . . . . . . . . . 127.4 127.4
Common stock dividends . . . . . (111.8) (111.8)
Preferred stock dividends . . . (9.7) (9.7)
Other . . . . . . . . . . . . . 0.2 (0.2) -
-----------------------------------------------------------------------
Ending balance . . . . . . . . . . 41,172,173 $ 0.4 $674.8 $320.7 $ 995.9
1992:
Net income . . . . . . . . . . . 142.0 142.0
Common stock dividends . . . . . (103.6) (103.6)
Preferred stock dividends . . . (9.4) (9.4)
Other . . . . . . . . . . . . . 0.2 (3.1) (2.9)
-----------------------------------------------------------------------
Ending balance . . . . . . . . . . 41,172,173 $ 0.4 $675.0 $346.6 $1,022.0
1993:
Net income . . . . . . . . . . . 143.6 143.6
Common stock dividends . . . . . (107.7) (107.7)
Preferred stock dividends . . . (8.7) (8.7)
Other . . . . . . . . . . . . . 0.2 (0.2) -
-----------------------------------------------------------------------
Ending balance . . . . . . . . . . 41,172,173 $ 0.4 $675.2 $373.6 $1,049.2
=======================================================================
(a) 50,000,000 shares authorized
II-20
- ---------------------------------------------------------------------------------------------------
9. PREFERRED STOCK
$25 par value, 4,000,000 shares authorized, no shares outstanding; and $100 par value,
4,000,000 shares authorized, 1,170,998 shares outstanding.
Without Mandatory With Mandatory
Redemption Provisions Redemption Provisions (a)
Current Current ----------------------------------------------------
Series/ Redemption Shares At December 31, At December 31,
Rate Price Outstanding 1993 1992 1993 1992
(millions) (millions)
- --------------------------------------------------------------------------------------------------
A 3.75% $102.50 93,280 $ 9.3 $ 9.3
B 3.75% $103.00 69,398 7.0 7.0
C 3.90% $101.00 65,830 6.6 6.6
D 7.48% $103.23 150,000 15.0 15.0
E 7.70% $101.00 199,990 20.0 20.0
F 7.375% $101.00 250,000 25.0 25.0
H 8-5/8% $101.00 120,000 $12.0 $16.0
I 9-3/8% $104.00 (b) 180,000 18.0 22.5
-----------------------------------------------------
Total . . . . . . . . . . . . . . . . . $82.9 $82.9 $30.0 $38.5
=====================================================
Fair value (including current portion)-
based upon quoted market prices . . . $34.6 $44.1
(a) Exclusive of sinking fund payment due within one year.
(b) Prior to May 1, 1994 and $101.00 thereafter.
The shares without mandatory redemption provisions may be redeemed at the
option of the Company at the per share prices indicated, plus accrued
dividends.
The shares with mandatory redemption provisions are redeemable pursuant to
mandatory sinking fund requirements, but may also be redeemed at the option of
the Company at the per share prices indicated, plus accrued dividends. The
annual sinking fund requirements for Series H and I are 5% of the original
amount of each issue. Over the next five years, mandatory redemptions are
$4.3 million (42,500 shares) per year. Shares redeemed or purchased to meet
sinking fund requirements may not be reissued.
Sinking fund requirements and redemptions of outstanding shares were 85,000
shares in 1993 and 42,500 in 1992 and 1991.
II-21
- ------------------------------------------------------------------------------------------------
10. RECONCILIATION OF NET INCOME TO NET CASH PROVIDED BY OPERATING ACTIVITIES
For the years ended December 31,
$ in millions 1993 1992 1991
- ------------------------------------------------------------------------------------------------
Net income . . . . . . . . . . . . . . . . . . . . . . . $143.6 $142.0 $127.4
Adjustments for non-cash items:
Depreciation and amortization . . . . . . . . . . . . 109.0 104.4 94.2
Deferred income taxes . . . . . . . . . . . . . . . . 22.1 31.9 (3.6)
Allowance for equity funds used during construction . (0.2) (0.2) (18.5)
Regulatory deferrals . . . . . . . . . . . . . . . . . (25.8) (58.7) (43.0)
Changes in working capital:
Accounts receivable and unbilled revenue . . . . . . . (3.8) (0.3) 4.0
Accounts payable . . . . . . . . . . . . . . . . . . . 23.4 (1.5) (16.9)
Deferred gas costs . . . . . . . . . . . . . . . . . . (7.9) (28.8) 9.7
Accrued interest . . . . . . . . . . . . . . . . . . . 8.7 (4.4) 0.1
Other . . . . . . . . . . . . . . . . . . . . . . . . 11.9 (11.6) 11.8
DSM deferred costs . . . . . . . . . . . . . . . . . . . (23.3) (2.2) -
Other operating activities . . . . . . . . . . . . . . . (11.5) 0.4 21.1
-----------------------------
Net cash provided by operating activities . . . . . . . $246.2 $171.0 $186.3
=============================
II-22
- ------------------------------------------------------------------------------------------------
11. FINANCIAL INFORMATION BY BUSINESS SEGMENTS
For the years ended December 31,
$ in millions 1993 1992 1991
- ------------------------------------------------------------------------------------------------
Utility service revenues
Electric . . . . . . . . . . . . . . . . . . . . . $ 901.3 $ 809.3 $ 790.7
Gas . . . . . . . . . . . . . . . . . . . . . . . 245.1 203.8 201.0
Other . . . . . . . . . . . . . . . . . . . . . . 7.3 6.7 6.3
-------------------------------
Total utility service revenues . . . . . . . . . . . . 1,153.7 1,019.8 998.0
Interest and other income . . . . . . . . . . . . . . . 11.5 3.5 4.1
-------------------------------
Total income . . . . . . . . . . . . . . . . . . . . $1,165.2 $1,023.3 $1,002.1
===============================
Operating profit before tax
Electric . . . . . . . . . . . . . . . . . . . . . $ 282.2 $ 224.3 $ 193.5
Gas . . . . . . . . . . . . . . . . . . . . . . . 19.9 22.1 0.7
Other . . . . . . . . . . . . . . . . . . . . . . 3.7 2.2 (1.1)
-------------------------------
Total operating profit before tax . . . . . . . . . . . 305.8 248.6 193.1
Other income, net (a) . . . . . . . . . . . . . . . . . 11.6 51.5 67.6
Interest expense . . . . . . . . . . . . . . . . . . . 97.4 94.3 93.1
-------------------------------
Operating income . . . . . . . . . . . . . . . . . . $ 220.0 $ 205.8 $ 167.6
===============================
Depreciation and amortization
Electric . . . . . . . . . . . . . . . . . . . . . $ 102.4 $ 97.9 $ 87.9
Gas . . . . . . . . . . . . . . . . . . . . . . . 5.7 5.6 6.0
Other . . . . . . . . . . . . . . . . . . . . . . 0.9 0.9 0.3
-------------------------------
Total depreciation and amortization . . . . . . . . $ 109.0 $ 104.4 $ 94.2
===============================
Construction additions
Electric . . . . . . . . . . . . . . . . . . . . . $ 66.3 $ 46.6 $ 103.4
Gas . . . . . . . . . . . . . . . . . . . . . . . 11.9 11.0 12.4
Other . . . . . . . . . . . . . . . . . . . . . . 0.3 0.1 0.5
-------- -------- --------
Total construction additions . . . . . . . . . . . . $ 78.5 $ 57.7 $ 116.3
===============================
Assets
Electric . . . . . . . . . . . . . . . . . . . . . $2,825.5 $2,522.8 $2,521.1
Gas . . . . . . . . . . . . . . . . . . . . . . . 236.0 219.5 217.6
Other (b) . . . . . . . . . . . . . . . . . . . . 152.8 124.4 112.8
-------------------------------
Total assets at year end . . . . . . . . . . . . . . $3,214.3 $2,866.7 $2,851.5
===============================
(a) Includes primarily interest income, AFC, regulatory deferrals and bond redemption costs.
(b) Includes primarily cash, temporary cash investments, and certain deferred items.
II-23
SELECTED QUARTERLY INFORMATION
For the three months ended
March 31, June 30, September 30, December 31,
$ in millions 1993 1992 1993 1992 1993 1992 1993 1992
- --------------------------------------------------------------------------------------------------------------
$ $ $ $ $ $ $ $
Utility service revenues . . . . 346.4 286.6 238.7 226.1 262.6 224.0 306.0 283.1
Income before income taxes . . . 81.9 74.1 47.2 46.6 56.2 47.5 34.7 37.6
Net income . . . . . . . . . . . 54.8 50.3 32.5 31.8 34.3 32.5 22.0 27.4
Earnings on common stock . . . . 52.5 47.9 30.4 29.5 32.2 30.2 19.8 25.0
Dividends paid . . . . . . . . . 26.9 25.9 26.9 25.9 27.0 25.9 27.0 25.9
II-24
FINANCIAL AND STATISTICAL SUMMARY
1993 1992 1991 1990 1989
- -----------------------------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31,
Utility service revenues (millions) . . . $ 1,153.7 1,019.8 998.0 948.0 956.3
Earnings on common stock (millions) . . . $ 134.9 132.6 117.7 152.0 133.7
Earnings per share of common stock . . . . $ 3.28 3.22 2.86 3.69 3.25
Dividends paid (millions). . . . . . . . . $ 107.8 103.6 111.8 82.3 93.5
Electric sales (millions of kWh)--
Residential . . . . . . . . . . . . . . 4,558 4,260 4,571 4,125 4,321
Commercial . . . . . . . . . . . . . . . 3,006 2,896 2,945 2,738 2,717
Industrial . . . . . . . . . . . . . . . 4,089 3,938 3,949 3,958 3,774
Other . . . . . . . . . . . . . . . . . 3,023 2,960 1,850 1,807 1,772
------- ------- ------- -------- -------
Total . . . . . . . . . . . . . . . . 14,676 14,054 13,315 12,628 12,584
Gas sales (thousands of MCF)--
Residential . . . . . . . . . . . . . . 28,786 27,723 26,594 25,486 29,917
Commercial . . . . . . . . . . . . . . . 8,468 8,642 8,368 8,259 9,125
Industrial . . . . . . . . . . . . . . . 3,056 4,914 6,014 5,934 6,670
Other . . . . . . . . . . . . . . . . . 3,171 3,402 3,187 3,076 3,347
Transportation gas delivered . . . . . . 13,401 10,811 8,494 8,093 7,252
------- ------- ------- ------- -------
Total . . . . . . . . . . . . . . . . 56,882 55,492 52,657 50,848 56,311
AT DECEMBER 31,
Total assets (millions) . . . . . . . . . $ 3,214.3 2,866.7 2,851.5 2,800.7 2,668.0
Long-term debt and preferred stock with
mandatory redemption provisions
(millions) . . . . . . . . . . . . . . . $ 1,042.9 990.6 1,039.2 1,047.5 1,055.9
First mortgage bond ratings--
Duff & Phelps, Inc. . . . . . . . . . . AA- A+ BBB+ BBB+ BBB+
Moody's Investors Service . . . . . . . A2 A2 A3 A3 A3
Standard & Poor's Corporation . . . . . A A BBB+ BBB+ BBB+
NUMBER OF SHAREHOLDERS
Preferred . . . . . . . . . . . . . . . . 1,873 1,969 2,034 2,100 2,166
II-25
Report of Independent Accountants
---------------------------------
To the Board of Directors and Shareholder of The Dayton Power
and Light Company
In our opinion, the consolidated financial statements
listed in the index, appearing under Item 8 on page II-7 of this
Form 10-K, present fairly, in all material respects, the
financial position of The Dayton Power and Light Company and its
subsidiaries at December 31, 1993 and 1992, and the results of
their operations and their cash flows for each of the three
years in the period ended December 31, 1993, in conformity with
generally accepted accounting principles. These consolidated
financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these
consolidated financial statements based on our audits. We
conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about
whether the consolidated financial statements are free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
consolidated financial statements, assessing the accounting
principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the
opinion expressed above.
As discussed in Note 1 to the consolidated financial
statements, the Company changed its method of accounting for
income taxes in 1993.
Price Waterhouse
Dayton, Ohio
January 25, 1994
II-26
Report of Independent Accountants
on Financial Statement Schedules
--------------------------------
To the Board of Directors of The Dayton Power and Light Company
Our audits of the consolidated financial statements of
The Dayton Power and Light Company and its subsidiaries referred
to in our report dated January 25, 1994 appearing on page II-26
of this Annual Report on Form 10-K also included an audit of the
Financial Statement Schedules listed in Item 14(a) of this
Form 10-K. In our opinion, these Financial Statement Schedules
present fairly, in all material respects, the information set
forth therein when read in conjunction with the related
consolidated financial statements.
Price Waterhouse
Dayton, Ohio
January 25, 1994
II-27
Item 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
- --------
Item 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT
Directors of the Registrant
- ---------------------------
The Board is presently authorized to consist of nine
directors. These nine directors are also directors of DPL Inc.,
the holding company of the Company. Eight incumbent directors
plus one new nominee are to be elected this year to serve until
1995 or until their successors are duly elected and qualified.
Should any nominee become unable to accept nomination or
election, the Board will vote for the election of such other
person as a director as the present directors may recommend in
the place of such nominee.
Dr. Robert J. Kegerreis will be retiring as a Director
in April 1994. Dr. Kegerreis, the President Emeritus of Wright
State University, has served as a Director since 1975, making
significant and lasting contributions during the most
challenging and successful period of the Company's history. We
offer our sincere appreciation to Dr. Kegerreis on behalf of all
of our Shareholders, Directors, Customers and Employees and wish
him well in his future endeavors.
Mr. David R. Holmes will stand for election to his first
term as a member of the Board. Mr. Holmes is Chairman,
President and Chief Executive Officer of The Reynolds and
Reynolds Company in Dayton, Ohio. The Reynolds and Reynolds
Company is a leading supplier of information management systems,
including business forms and computer systems for automotive,
professional, medical and general markets. His business
experience and community leadership will be a valuable asset to
the Board.
III-1
The following information regarding the nominees is
based on information furnished by them:
Director
Principal Occupation and Other Information Since
- ------------------------------------------ --------
Incumbent Directors
- -------------------
THOMAS J. DANIS, Age 44 1989
Former Chairman and Chief Executive Officer,
The Danis Companies, Dayton, Ohio,
construction, real estate and environmental services.
Trustee: University of Dayton, Dayton Business Committee,
Dayton Foundation.
Member: Area Progress Council.
JAMES F. DICKE, II, Age 48 1990
President, Crown Equipment Corporation,
New Bremen, Ohio, international manufacturer
and distributor of electric lift trucks and
material handling products.
Director: Regional Boys and Girls Clubs
of America, Plaid Holdings Company.
Treasurer: Trinity University Board of
Trustees.
Secretary: Culver Educational Foundation.
PETER H. FORSTER, Age 51 1979
Chairman, President and Chief Executive Officer,
DPL Inc.; Chairman, The Dayton Power and Light Company.
Chairman: Miami Valley Research Foundation.
Director: Bank One, Dayton, NA, Amcast
Industrial Corp., Comair Holdings, Inc.
Trustee: F. M. Tait Foundation,
MedAmerica Health Systems Corp., Dayton Business
Committee, Arts Center Foundation.
ERNIE GREEN, Age 55 1991
President and Chief Executive Officer, Ernie Green
Industries, Dayton, Ohio, automotive components
manufacturer.
Director: Bank One, Dayton, NA, Day-Med Health
Maintenance Plan, Inc., WPTD-TV, The Duriron
Company.
Trustee: Central State University, Dayton Area
Chamber of Commerce, YMCA, Childrens Medical Center,
The Ronald McDonald Childrens Charities.
III-2
JANE G. HALEY, Age 63 1978
President, Gosiger, Inc., Dayton, Ohio,
national importer and distributor
of machine tools.
Director: Society Bank, NA, Advisory
Board, Dayton, Ohio.
Trustee: University of Dayton, Chaminade-
Julienne High School, Dayton, Ohio.
Member: Area Progress Council.
ALLEN M. HILL, Age 48 1989
President and Chief Executive Officer,
The Dayton Power and Light Company.
Director: Citizens Federal Bank, F.S.B.,
Dayton Boys/Girls Club, Miami Valley
Regional Planning Commission, Ohio Electric
Utility Institute.
Trustee: The University of Dayton, Hipple Cancer
Research Center.
W AUGUST HILLENBRAND, Age 53 1992
President and Chief Executive Officer, Hillenbrand
Industries, Batesville, Indiana, a diversified
public holding company with seven wholly-owned and
autonomously operated subsidiaries manufacturing
caskets, hospital furniture, hospital supplies,
luggage and high-tech security locks and providing
funeral planning services.
Director: Forecorp, Inc., Forethought Life
Insurance Company.
Trustee: Denison University, National
Committee for Quality Health Care, Batesville
Girl Scouts.
BURNELL R. ROBERTS, Age 66 1987
Chairman, Sweetheart Holdings, Inc.
Retired Chairman of the Board and Chief Executive
Officer, The Mead Corporation, Dayton, Ohio,
forest products and electronic publishing.
Director: Armco, Inc., National City Corporation,
The Perkin-Elmer Corporation, Universal Protective
Plastics, Inc.
Trustee: Japan Society.
III-3
Nominated for Election at 1994 Annual Meeting of Shareholders
- -------------------------------------------------------------
DAVID R. HOLMES, Age 53
Chairman, President and Chief Executive
Officer, The Reynolds and Reynolds Company,
Dayton, Ohio, information management systems.
Director: Bank One, Dayton, NA.
Advisor: J.L. Kellogg Graduate School of
Management, Northwestern University.
Co-Chair: Downtown Dayton Partnership.
Member: Dayton Business Committee, Area
Progress Council.
III-4
EXECUTIVE OFFICERS OF THE REGISTRANT
(As of March 1, 1994)
Business Experience,
Last Five Years
(Positions with Registrant
Name Age Unless Otherwise Indicated) Dates
- --------------------- --- ----------------------------- ------------------
Peter H. Forster 51 Chairman 4/06/92 - 3/01/94
Chairman, President and Chief 4/05/88 - 3/01/94
Executive Officer, DPL Inc.
Chairman and Chief Executive 8/02/88 - 4/06/92
Officer
Allen M. Hill 48 President and Chief Executive 4/06/92 - 3/01/94
Officer
President and Chief Operating 8/02/88 - 4/06/92
Officer
Paul R. Anderson 51 Controller 4/12/81 - 3/01/94
Controller, DPL Inc. 4/10/86 - 4/10/89
Stephen P. Bramlage 47 Assistant Vice President 1/01/94 - 3/01/94
Director, Service Operations 10/29/89 - 1/01/94
Manager, Engineering 5/26/87 - 10/29/89
Robert E. Buerger 49 Group Vice President 4/24/89 - 3/01/94
Group Vice President - 12/04/86 - 4/24/89
Service Operations, DPL Inc.
and the Company
Robert M. Combs 48 Treasurer 3/17/93 - 3/01/94
Director, J. M. Stuart 9/16/91 - 3/17/93
Electric Generating Station
United States Navy
Production Officer, 8/01/88 - 9/16/91
Charleston Naval Shipyard
Georgene H. Dawson 44 Assistant Vice President 1/01/94 - 3/01/94
Director, Service Operations 4/03/92 - 1/01/94
Service Center Manager 6/11/89 - 4/03/92
Manager, Environmental 6/14/87 - 6/11/89
Management
III-5
EXECUTIVE OFFICERS OF THE REGISTRANT
(As of March 1, 1994)
Business Experience,
Last Five Years
(Positions with Registrant
Name Age Unless Otherwise Indicated) Dates
- --------------------- --- ----------------------------- ------------------
Jeanne S. Holihan 37 Assistant Vice President 3/17/93 - 3/01/94
Treasurer 11/06/90 - 3/17/93
Director, Financial 4/01/90 - 11/06/90
Administration and Planning
Manager, Financial 4/02/89 - 4/01/90
Administration and Planning
Manager, Financial Analysis 4/07/85 - 4/02/89
and Investor Relations
Thomas M. Jenkins 42 Group Vice President, 11/06/90 - 3/01/94
Group Vice President and
Treasurer, DPL Inc.
Vice President and Treasurer, 11/01/88 - 11/06/90
DPL Inc. and the Company
Stephen F. Koziar, Jr. 49 Group Vice President, 12/10/87 - 3/01/94
DPL Inc. and the Company
Judy W. Lansaw 42 Group Vice President and 12/07/93 - 03/01/94
Secretary, DPL Inc. and
the Company
Vice President and 08/01/89 - 12/07/93
Secretary, DPL Inc. and
the Company
Corporate Secretary, DPL Inc. 11/01/88 - 8/01/89
and the Company
Lloyd E. Lewis, Jr. 67 Assistant Vice President 12/08/83 - 3/01/94
Bryce W. Nickel 37 Assistant Vice President 1/01/94 - 3/01/94
Director, Service Operations 10/29/89 - 1/01/94
Service Center Manager 4/19/87 - 10/29/89
H. Ted Santo 43 Group Vice President 12/08/92 - 3/01/94
Vice President 2/28/88 - 12/08/92
III-6
Item 11 - EXECUTIVE COMPENSATION
COMPENSATION OF DIRECTORS
- -------------------------
Directors of the Company who are not employees receive $12,000
annually for services as a director, $600 for attendance at a Board meeting,
and $500 for attendance at a committee meeting or operating session, of
DPL Inc. and the Company. Members of the Executive Committee of DPL Inc.
receive $2,000 annually for services on that committee. Each committee
chairman receives an additional $1,600 annually. Directors who are not
employees of the Company also participate in a Directors' Deferred Stock
Compensation Plan (the "Stock Plan") under which a number of DPL Inc. common
shares are awarded to directors each year. All shares awarded under the Stock
Plan are transferred to a grantor trust (the "Master Trust") maintained by
DPL Inc. to secure its obligations under various directors' and officers'
deferred and incentive compensation plans. Receipt of the shares or cash equal
to the value thereof is deferred until the participant retires as a director or
until such other time as designated by the participant and approved by the
Compensation and Management Review Committee (the "Committee") of DPL Inc. In
the event of a change of control (as defined in the Stock Plan), the authority
and discretion which is exercisable by the Committee, will be exercised by the
trustees of the Master Trust. In April 1993, each non-employee director was
awarded 1,400 shares.
DPL Inc. maintains a Deferred Compensation Plan (the "Compensation
Plan") for non-employee directors of DPL Inc. and the Company in which payment
of directors' fees may be deferred. The Compensation Plan also includes a
supplementary deferred income program which provides that DPL Inc. will match
$5,000 annually of deferred directors' fees for a maximum of ten years. Under
the supplementary program, a $150,000 death benefit is provided until such
director ceases to participate in the Compensation Plan. Under the standard
deferred income program directors are entitled to receive a lump sum payment or
payments in approximately equal installments over a ten-year period. A
director may elect payment in either cash or common shares. Participants in
the supplementary program are entitled to receive deferred payments over a
ten-year period in equal installments. The Compensation Plan provides that in
the event of a change in control of DPL Inc., as defined in the Compensation
Plan, all benefits provided under the supplementary deferred income program
become immediately vested without the need for further contributions by the
participants and the discretion which, under the Compensation Plan, is
exercisable by the Chief Executive Officer of DPL Inc. will be exercised by the
trustees of the Master Trust. If the consent of the Chief Executive Officer of
DPL Inc. is obtained, individuals who have attained the age of 55 and who are
no longer directors of DPL Inc. or the Company may receive a lump sum payment
of amounts credited to them under the supplementary deferred income program.
III-7
EXECUTIVE OFFICER COMPENSATION
- ------------------------------
Summary Compensation Table
- --------------------------
Set forth below is certain information concerning the compensation of
the Chief Executive Officer and each of the other four most highly compensated
executive officers of the Company for the last three fiscal years, for services
rendered in all capacities to the Company and its subsidiaries, DPL Inc., and
the other subsidiaries of DPL Inc.
Long-Term
Compensation
Annual ----------------
Compensation Restricted
----------------- Stock Unit All Other
Name and Principal Salary Bonus(1) Awards(2) Compensation(3)
Position Year ($) ($) ($) ($)
- ------------------ ---- ------ -------- ---------------- ----------------
Peter H. Forster 1993 496,000 298,000 580,000 ('94-96) 1,000
Chairman 1992 496,000 298,000 436,000 ('93-95) 0
1991 468,000 281,000 435,000 ('92-94) 0
Allen M. Hill 1993 315,000 193,000 249,000 ('94-96) 1,000
President and Chief 1992 294,000 180,000 183,000 ('93-95) 0
Executive Officer 1991 248,000 150,000 248,000 ('92-94) 0
Stephen F. Koziar, Jr. 1993 189,000 86,000 103,000 ('94-96) 1,000
Group Vice President 1992 181,000 83,000 86,000 ('93-95) 0
1991 174,000 61,000 108,000 ('92-94) 0
Thomas M. Jenkins 1993 172,000 81,000 188,000 ('94-96) 1,000
Group Vice President 1992 150,000 72,000 150,000 ('93-95) 0
1991 140,000 53,000 128,000 ('92-94) 0
H. Ted Santo 1993 151,000 73,000 192,000 ('94-96) 1,000
Group Vice President 1992 129,000 64,000 153,000 ('93-95) 0
1991 117,000 48,000 105,000 ('92-94) 0
- ------------------------
(1) Amounts in this column represent awards made under the Management
Incentive Compensation Program ("MICP"). Awards are based on achievement
of specific predetermined operating and management goals in the year
indicated and paid in the year earned or in the following year.
III-8
(2) Amounts shown in this column have not been paid, but are contingent on
performance and represent the dollar value of restricted stock incentive
units ("SIU's") awarded to the named executive officer under the
Management Stock Incentive Plan ("MSIP") based on the closing price of a
DPL Inc. common share on the New York Stock Exchange--Consolidated
Transactions Tape on the date of award. SIU's awarded for 1992 and 1993
vest only to the extent that the DPL Inc. average return on equity
("ROE") over a three-year performance period is above the RRA industry
median.
Depending on the performance of DPL Inc., these SIU's vest in amounts
ranging from 0% to 100% of the target award at an ROE between 0 and
100 basis points above median ROE and from 100% to 150% of target award
at an ROE between 100 and 200 basis points above median ROE. No units
vest if the three-year average ROE is below 10%. Amounts shown for 1992
and 1993 reflect target awards. Amounts shown for 1991 represent the
annual pro rata portion of SIU's earned over the eight-year period from
inception of the MSIP in 1984 through 1991, including the pro rata
portion of supplemental SIU awards made in 1991 to the named executive
officers in recognition of corporate performance over the eight-year
period. For each SIU which vests, a participant receives the cash
equivalent of one DPL Inc. common share plus dividend equivalents from
the date of award. Prior to payout at retirement, an individual may
elect to convert a portion of vested SIU's to a cash equivalent and
accrue interest thereon. As of December 31, 1993, the aggregate target
number and value (based on the closing price of a DPL Inc. common share
on the NYSE--Consolidated Transactions Tape on December 31, 1993) of
unearned restricted SIU's contingently awarded to each named executive
officer was as follows: Mr. Forster, 75,800 ($1,563,000); Mr. Hill,
36,612 ($755,000); Mr. Koziar, 14,911 ($307,000); Mr. Jenkins 25,640
($528,000); and Mr. Santo, 26,012 ($536,000). These unearned restricted
SIU's may vest in 1994, 1995 and 1996 at 0% to 150% of the target number
depending on Company performance during the period from 1992 through
1996. All payouts of vested SIU's under the MSIP are deferred until
retirement.
(3) Amounts in this column represent employer matching contributions on
behalf of each named executive under the DP&L Employee Savings Plan made
to the DPL Inc. Employee Stock Ownership Plan.
Certain Severance Pay Agreements
- --------------------------------
DPL Inc. entered into severance pay agreements with each of
Messrs. Forster, Hill, Koziar, Jenkins and Santo providing for the payment of
severance benefits in the event that the individual's employment with DPL Inc.
or its subsidiaries is terminated under specified circumstances within three
years after a change in control of DPL Inc. or DP&L (as defined in the
agreement). The agreements entered into between 1987 and 1991 require the
individuals to remain with DPL Inc. throughout the period during which any
change of control is pending in order to help put in place the best plan for
the shareholders. The principal severance benefits under each agreement
III-9
include payment of the following: (i) the individual's full base salary and
accrued benefits through the date of termination and any awards for any
completed or partial period under the MICP and the individual's award for the
current period under the MICP (or for a completed period if no award for that
period has yet been determined) fixed at an amount equal to his average annual
award for the preceding three years; (ii) 300% of the sum of the individual's
annual base salary at the rate in effect on the date of termination (or, if
higher, at the rate in effect as of the time of the change in control) plus the
average amount awarded to the individual under the MCIP for the three preceding
years; (iii) all awarded or earned but unpaid SIU's; and (iv) continuing
medical, life, and disability insurance. In the event any payments under these
agreements are subject to an excise tax under the Internal Revenue Code of
1986, the payments will be adjusted so that the total payments received on an
after-tax basis will equal the amount the individual would have received
without imposition of the excise tax. The severance pay agreements are
effective for one year but are automatically renewed each year unless DPL Inc.
or the participant notifies the other one year in advance of its or his intent
not to renew. DPL Inc. has agreed to secure its obligations under the
severance pay agreements by transferring required payments to the Master Trust.
Pension Plans
- -------------
The following table sets forth the estimated total annual benefits
payable under the Company retirement income plan and the supplemental executive
retirement plan to executive officers at normal retirement date (age 65) based
upon years of accredited service and final average annual compensation
(including base and incentive compensation) for the three highest years during
the last ten:
Total Annual Retirement Benefits for
Years of Accredited Service
Final Average ------------------------------------
Annual Earnings 10 Years 30 Years
--------------- -------- --------
$ 200,000 $ 53,000 $106,000
400,000 110,000 220,000
600,000 167,000 334,000
800,000 224,000 448,000
1,000,000 281,000 562,000
The years of accredited service for the named executive officers are
Mr. Forster -- 29 yrs.; Mr. Hill -- 24 yrs.; Mr. Koziar -- 24 yrs.;
Mr. Jenkins -- 16 yrs and Mr. Santo -- 18 years. Years of service under the
retirement income plan are capped at 30 years, however, the retirement and
supplemental plans, taken together, can provide full benefits after 20 years of
accredited service. Benefits shown above are computed on a straight-life
annuity basis, are subject to deduction for Social Security benefits and may be
reduced by benefits payable under retirement plans of other employers. For
each year an individual retires prior to age 62, benefits under the
supplemental plan are reduced by 3% or 21% for early retirement at age 55.
III-10
Item 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The Company's stock is beneficially owned by DPL Inc.
Set forth below is information concerning the beneficial ownership of
shares of Common Stock of DPL Inc. by each director of the Company as of
January 31, 1994.
Amount and Nature of
Name of Director Beneficial Ownership (1)
---------------- ------------------------
Incumbent Directors
-------------------
Thomas J. Danis 15,923 shares
James F. Dicke, II 56,438 shares
Peter H. Forster 21,416 shares
Ernie Green 12,404 shares
Jane G. Haley 23,414 shares
Allen M. Hill 19,646 shares
W August Hillenbrand 5,922 shares
Burnell R. Roberts 14,125 shares
Nominated for Election at the
1994 Annual Meeting of Shareholders
----------------------------------
David R. Holmes 100 shares
Set forth below is information concerning the beneficial ownership of
shares of Common Stock of DPL Inc. by each executive officer of the Company
named in the Summary Compensation Table (other than executive officers who are
directors of the Company whose security ownership is found above) as of
January 31, 1994.
Amount and Nature of
Name of Executive Officer Beneficial Ownership (1)
------------------------- ------------------------
Stephen F. Koziar, Jr. 6,380 shares
Thomas M. Jenkins 5,108 shares
H. Ted Santo 1,430 shares
(1) The number of shares shown represents in each instance less than 1% of the
outstanding Common Shares of DPL Inc.
There were 237,749 shares or 0.23% of the total number of Common Shares
beneficially owned by all directors and executive officers of DPL Inc. and
the Company as a group at January 31, 1994. The number of shares shown for
the directors includes Common Shares transferred to the Master Trust for
non-employee directors pursuant to the Directors' Deferred Stock
Compensation Plan.
Item 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
III-11
PART IV
- -------
Item 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Documents filed as part of the Form 10-K
1. Financial Statements
--------------------
See Item 8 - Index to Financial Statements on page II-7, which
page is incorporated herein by reference.
2. Financial Statement Schedules
-----------------------------
For the three years in the period ended December 31, 1993:
Page
No.
-------------
Schedule V - Property and plant IV-7 - IV-12
Schedule VI - Accumulated depreciation
and amortization IV-13 - IV-15
Schedule VII - Obligations relating to
securities of other issuers IV-16
Schedule VIII - Valuation and qualifying
accounts IV-17
Schedule IX - Short-term borrowings IV-18
Schedule X - Supplementary income statement
information IV-19
The information required to be submitted in Schedules I, II, III, IV,
XI, XII and XIII is omitted as not applicable or not required under rules of
Regulation S-X.
IV-1
3. Exhibits
--------
The following exhibits have been filed with the Securities and Exchange
Commission and are incorporated herein by reference.
Incorporation by
Reference
-----------------
2 Copy of the Agreement of Merger among Exhibit A to the 1986
DPL Inc., Holding Sub Inc. and the Proxy Statement
Company dated January 6, 1986................. (File No. 1-2385)
3(a) Regulations and By-Laws of the Company........ Exhibit 2(e) to
Registration
Statement No. 2-68136
to Form S-16.
3(b) Copy of Amended Articles of Incorporation Exhibit 3(b) to Report
of the Company dated January 3, 1991.......... on Form 10-K for the
year ended December 31,
1991 (File No. 1-2385)
4(a) Copy of Composite Indenture dated as of Exhibit 4(a) to Report
October 1, 1935, between the Company and on Form 10-K for year
The Bank of New York, Trustee with all ended December 31, 1985
amendments through the Twenty-Ninth (File No. 1-2385)
Supplemental Indenture........................
4(b) Copy of the Thirtieth Supplemental Indenture Exhibit 4(h) to
dated as of March 1, 1982, between the Registration Statement
Company and The Bank of New York, Trustee..... No. 33-53906
4(c) Copy of the Thirty-First Supplemental Exhibit 4(h) to
Indenture dated as of November 1, 1982, Registration Statement
between the Company and The Bank of New York, No. 33-56162
Trustee.......................................
4(d) Copy of the Thirty-Second Supplemental Inden- Exhibit 4(i) to
ture dated as of November 1, 1982, between the Registration Statement
Company and The Bank of New York, Trustee..... No. 33-56162
4(e) Copy of the Thirty-Third Supplemental Exhibit 4(e) to
Indenture dated as of December 1, 1985, Report on Form 10-K
between the Company and The Bank of New York, for year ended
Trustee....................................... December 31, 1985
(File No. 1-2385)
4(f) Copy of the Thirty-Fourth Supplemental Exhibit 4 to Report
Indenture dated as of April 1, 1986, on Form 10-Q for
between the Company and The Bank of New York, quarter ended
Trustee....................................... June 30, 1986
(File No. 1-2385)
IV-2
4(g) Copy of the Thirty-Fifth Supplemental Exhibit 4(h) to Report
Indenture dated as of December 1, 1986, on Form 10-K for the
between the Company and The Bank of New York, year ended December 31,
Trustee....................................... 1986 (File No. 1-9052)
4(h) Copy of the Thirty-Sixth Supplemental Exhibit 4(i) to
Indenture dated as of August 15, 1992, Registration Statement
between the Company and The Bank of New York, No. 33-53906
Trustee.......................................
4(i) Copy of the Thirty-Seventh Supplemental Exhibit 4(j) to
Indenture dated as of November 15, 1992, Registration Statement
between the Company and The Bank of New York, No. 33-56162
Trustee.......................................
4(j) Copy of the Thirty-Eighth Supplemental Exhibit 4(k) to
Indenture dated as of November 15, 1992, Registration Statement
between the Company and The Bank of New York, No. 33-56162
Trustee.......................................
4(k) Copy of the Thirty-Ninth Suplemental Exhibit 4(k) to
Indenture dated as of January 15, 1993, Registration Statement
between the Company and The Bank of New York, No. 33-57928
Trustee.......................................
4(l) Copy of the Fortieth Supplemental Indenture Exhibit 4(m) to Report
dated as of February 15, 1993, between on Form 10-K for the
the Company and The Bank of New York, year ended December 31,
Trustee....................................... 1992 (File No. 1-2385)
10(a) Description of Management Incentive Exhibit 10(d) to Report
Compensation Program for Certain Executive on Form 10-K for the
Officers...................................... year ended December 31,
1986 (File No. 1-9052)
10(b) Copy of Severance Pay Agreement Exhibit 10(g) to Report
with Certain Executive Officers............... on Form 10-K for the
year ended December 31,
1987 (File No. 1-2385)
10(c) Copy of Supplemental Executive Retirement Exhibit 10(f) to Report
Plan amended August 6, 1991................... on Form 10-K for the
year ended December 31,
1991 (File No. 1-2385)
18 Copy of preferability letter relating to Exhibit 18 to Report
change in accounting for unbilled revenues on Form 10-K for the
from Price Waterhouse......................... year ended December 31,
1988 (File No. 1-2385)
IV-3
The following exhibits are filed herewith:
Page No.
--------
10(d) Amended description of Directors' Deferred
Stock Compensation Plan effective
January 1, 1993...............................
10(e) Amended description of Deferred Compensation
Plan for Non-Employee Directors effective
January 1, 1993...............................
10(f) Copy of Management Stock Incentive Plan
amended January 1, 1993.......................
21 Copy of List of Subsidiaries of the Company...
(b) Reports on Form 8-K
-------------------
Date of Report Items Reported
-------------- --------------
February 3, 1993 Item 5. Other Events.
Item 7. Financial
Statements and
Exhibits.
IV-4
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
THE DAYTON POWER AND LIGHT COMPANY
Registrant
March 15, 1994 Peter H. Forster
------------------------------------
Peter H. Forster
Chairman
Pursuant to the requirements of the Securities Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated.
P. R. Anderson Controller (principal March 15, 1994
- ------------------------- accounting officer)
(P. R. Anderson)
T. J. Danis Director March 15, 1994
- ------------------------
(T. J. Danis)
Director March , 1994
- -------------------------
(J. F. Dicke, II)
P. H. Forster Director and Chairman March 15, 1994
- ------------------------- (principal executive
(P. H. Forster) officer)
E. Green Director March 15, 1994
- -------------------------
(E. Green)
IV-5
J. G. Haley Director March 15, 1994
- -------------------------
(J. G. Haley)
A. M. Hill Director, President and March 15, 1994
- ------------------------- Chief Executive Officer
(A. M. Hill)
Director March , 1994
- -------------------------
(W A. Hillenbrand)
T. M. Jenkins Group Vice President March 15, 1994
- ------------------------- (principal financial
(T. M. Jenkins) officer)
Director March , 1994
- -------------------------
(R. J. Kegerreis)
Director March , 1994
- -------------------------
(B. R. Roberts)
IV-6
Schedule V - 1993
Page 1 of 2
THE DAYTON POWER AND LIGHT COMPANY
PROPERTY AND PLANT (1)
For the year ended December 31, 1993
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
-------- -------- -------- -------- -------- --------
Balance Other Changes - Balance
Beginning Additions Retirements Additions at End
Classification of Period At Cost or Sales (2) (Deductions) (3) of Period
-------------- -------------------------------Thousands-------------------------------
Electric--
Production. . . . . . . . . . . $2,035,059 $ 19,712 $ 4,440 $ 230 $2,050,561
Transmission. . . . . . . . . . 234,461 13,130 383 (22) 247,186
Distribution. . . . . . . . . . 496,015 31,377 3,891 22 523,523
General . . . . . . . . . . . . 96,126 4,741 680 (136) 100,051
Plant held for future use
(undistributed) . . . . . . . 2,032 - - - 2,032
Acquisition adjustments,
being amortized . . . . . . . 685 - - (196) 489
---------- -------- ------- ------- ----------
Total electric . . . . . . . 2,864,378 68,960 9,394 (102) 2,923,842
---------- -------- ------- ------- ----------
Gas--
Production. . . . . . . . . . . 2,954 352 - - 3,306
Storage . . . . . . . . . . . . 2,167 16 - - 2,183
Distribution. . . . . . . . . . 217,303 16,233 745 - 232,791
General . . . . . . . . . . . . 1,140 442 - - 1,582
Acquisition adjustments,
being amortized . . . . . . . 284 - - (20) 264
---------- -------- ------- ------- ----------
Total gas. . . . . . . . . . 223,848 17,043 745 (20) 240,126
---------- -------- ------- ------- ----------
Steam--
Production. . . . . . . . . . . 9,594 30 27 - 9,597
Distribution. . . . . . . . . . 4,563 350 25 - 4,888
General . . . . . . . . . . . . 69 3 - 211 283
---------- -------- ------- ------- ----------
Total steam. . . . . . . . . 14,226 383 52 211 14,768
---------- -------- ------- ------- ----------
Other property and plant . . . 17,020 190 - - 17,210
---------- -------- ------- ------- ----------
Total property and plant . . 3,119,472 86,576 10,191 89 3,195,946
Construction work in progress . 42,720 (7,855) - 960 35,825
---------- -------- ------- ------- ----------
Total. . . . . . . . . . . . $3,162,192 $ 78,721 $10,191 $ 1,049 $3,231,771
========== ======== ======= ======= ==========
Notes: See Page 2 of 2.
IV-7
Schedule V - 1993
Page 2 of 2
THE DAYTON POWER AND LIGHT COMPANY
PROPERTY AND PLANT
NOTES TO PAGE ONE OF SCHEDULE V
For the year ended December 31, 1993
(1) See Notes 1 and 7 of Notes to Consolidated Financial Statements of the 1993 Form 10-K Report.
(2) Retirements are at original cost.
(3) Consists primarily of amortization of acquisition adjustments and other adjustments or transfers
between plant accounts.
IV-8
Schedule V - 1992
Page 1 of 2
DAYTON POWER AND LIGHT COMPANY
PROPERTY AND PLANT (1)
For the year ended December 31, 1992
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
-------- -------- -------- -------- -------- --------
Balance Other Changes - Balance
Beginning Additions Retirements Additions at End
Classification of Period At Cost or Sales (2) (Deductions) (3) of Period
-------------- -------------------------------Thousands-------------------------------
Electric--
Production. . . . . . . . . . . $2,018,716 $22,759 $ 6,464 $ 48 $2,035,059
Transmission. . . . . . . . . . 233,495 1,594 530 (98) 234,461
Distribution. . . . . . . . . . 481,064 18,773 3,920 98 496,015
General . . . . . . . . . . . . 97,079 1,188 617 (1,524) 96,126
Plant held for future use
(undistributed) . . . . . . 1,943 89 - - 2,032
Acquisition adjustments,
being amortized . . . . . . . 880 - - (195) 685
---------- ------- ------- ------- ----------
Total electric . . . . . . . 2,833,177 44,403 11,531 (1,671) 2,864,378
---------- ------- ------- ------- ----------
Gas--
Production. . . . . . . . . . . 2,893 61 - - 2,954
Storage . . . . . . . . . . . . 2,167 - - - 2,167
Distribution. . . . . . . . . . 210,146 8,073 916 - 217,303
General . . . . . . . . . . . . 1,136 1 - 3 1,140
Acquisition adjustments,
being amortized . . . . . . . 305 - - (21) 284
---------- ------- ------- ------- ----------
Total gas. . . . . . . . . . 216,647 8,135 916 (18) 223,848
---------- ------- ------- ------- ----------
Steam--
Production. . . . . . . . . . . 9,458 137 12 11 9,594
Distribution. . . . . . . . . . 4,555 62 54 - 4,563
General . . . . . . . . . . . . 69 - - - 69
---------- ------- ------- ------- ----------
Total steam. . . . . . . . . 14,082 199 66 11 14,226
---------- ------- ------- ------- ----------
Other property and plant . . . - 26 - 16,994 17,020
---------- ------- ------- ------- ----------
Total property and plant . . 3,063,906 52,763 12,513 15,316 3,119,472
Construction work in progress . 36,287 4,973 - 1,460 42,720
---------- ------- ------- ------- ----------
Total. . . . . . . . . . . . $3,100,193 $57,736 $12,513 $16,776 $3,162,192
========== ======= ======= ======= ==========
Notes: See Page 2 of 2.
IV-9
Schedule V - 1992
Page 2 of 2
THE DAYTON POWER AND LIGHT COMPANY
PROPERTY AND PLANT
NOTES TO PAGE ONE OF SCHEDULE V
For the year ended December 31, 1992
(1) See Notes 1 and 3 of Notes to Consolidated Financial Statements of the 1992 Form 10-K Report.
(2) Retirements are at original cost.
(3) Consists primarily of consolidation of Company subsidiaries' amortization of acquistion adjustments
and other adjustments or transfers between plant accounts.
IV-10
Schedule V - 1991
Page 1 of 2
THE DAYTON POWER AND LIGHT COMPANY
PROPERTY AND PLANT (1)
For the year ended December 31, 1991
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
-------- -------- -------- -------- -------- --------
Balance Other Changes - Balance
Beginning Additions Retirements Additions at End
Classification of Period At Cost or Sales (2) (Deductions) (3) of Period
-------------- -------------------------------Thousands-------------------------------
Electric--
Production. . . . . . . . . . . $1,023,875 $1,001,546 $ 6,779 $ 74 $2,018,716
Transmission. . . . . . . . . . 221,366 12,420 221 (70) 233,495
Distribution. . . . . . . . . . 448,452 34,598 1,763 (223) 481,064
General . . . . . . . . . . . . 89,217 10,038 1,910 (266) 97,079
Plant held for future use
(undistributed) . . . . . . . 1,944 - - (1) 1,943
Acquisition adjustments,
being amortized . . . . . . . 1,076 - - (196) 880
---------- ---------- ------- -------- ----------
Total electric . . . . . . . 1,785,930 1,058,602 10,673 (682) 2,833,177
---------- ---------- ------- -------- ----------
Gas--
Production. . . . . . . . . . . 2,893 - - - 2,893
Storage . . . . . . . . . . . . 2,167 - - - 2,167
Distribution. . . . . . . . . . 200,658 9,946 489 31 210,146
General . . . . . . . . . . . . 1,071 65 - - 1,136
Acquisition adjustments,
being amortized . . . . . . . 325 (653) - 633 305
---------- ---------- ------- -------- ----------
Total gas. . . . . . . . . . 207,114 9,358 489 664 216,647
---------- ---------- ------- -------- ----------
Steam--
Production. . . . . . . . . . . 9,257 221 20 - 9,458
Distribution. . . . . . . . . . 4,183 481 109 - 4,555
General . . . . . . . . . . . . 69 - - - 69
---------- ---------- ------- -------- ----------
Total steam. . . . . . . . . 13,509 702 129 - 14,082
---------- ---------- ------- -------- ----------
Other property and plant . . . - - - - -
Total property and plant . . 2,006,553 1,068,662 11,291 (18) 3,063,906
Construction work in progress . 991,569 (952,316) - (2,966) 36,287
---------- ---------- ------- -------- ----------
Total. . . . . . . . . . . . $2,998,122 $ 116,346 $11,291 $ (2,984) $3,100,193
========== ========== ======= ======== ==========
Notes: See Page 2 of 2.
IV-11
Schedule V - 1991
Page 2 of 2
THE DAYTON POWER AND LIGHT COMPANY
PROPERTY AND PLANT
NOTES TO PAGE ONE OF SCHEDULE V
For the year ended December 31, 1991
(1) See Notes 1, 2 and 11 of Notes to Financial Statements of the 1991 Form 10-K Report.
(2) Retirements are at original cost.
(3) Consists primarily of amortization of acquisition adjustments and other adjustments or transfers
between plant accounts.
IV-12
Schedule VI
THE DAYTON POWER AND LIGHT COMPANY
ACCUMULATED DEPRECIATION AND AMORTIZATION (1)
For the year ended December 31, 1993
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
-------- -------- -------- -------- -------- --------
Balance at Additions Retirements, Other Changes - Balance
Beginning Charged to Renewals and Additions at End
Classification of Period Income Replacements (Deductions) of Period
-------------- ------------------------------Thousands---------------------------------
Electric--
Production. . . . . . . . . . . $510,187 $ 74,134 $ 4,437 $ (1,963) $577,921
Transmission. . . . . . . . . . 81,451 5,971 376 (104) 86,942
Distribution. . . . . . . . . . 137,042 16,015 3,891 (1,728) 147,438
General . . . . . . . . . . . . 25,342 3,277 676 1,085 29,028
Plant held for future use
(undistributed) . . . . . . . 253 - - 23 276
-------- -------- -------- -------- --------
Total electric . . . . . . . 754,275 99,397 9,380 (2,687) 841,605
Gas . . . . . . . . . . . . . . 90,632 5,748 745 (186) 95,449
Steam . . . . . . . . . . . . . 8,528 315 53 (22) 8,768
Other . . . . . . . . . . . . . 4,149 575 - - 4,724
-------- -------- -------- -------- --------
Total. . . . . . . . . . . . $857,584 $106,035 (2) $ 10,178 $ (2,895) (3) $950,546
======== ======== ======== ======== ========
(1) See Note 1 of Notes to Consolidated Financial Statements of the 1993 Form 10-K Report.
(2) Additions charged to income--
Depreciation and amortization expense (per above) . . . . . . . . . . . . $106,035
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,963
--------
Total per Consolidated Statement of Results of Operations . . . . . . . $108,998
========
(3) Consists of--
Reclassification of accumulated depreciation to deferred charges . . . . (709)
Depreciation and amortization charged to other accounts . . . . . . . . . 268
Net removal cost/salvage--
Removal cost . . . . . . . . . . . $(2,310)
Salvage . . . . . . . . . . . . . . 944
-------
Net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,366)
Adjustments of previously recorded activity . . . . . . . . . . . . . . . 146
Adjustments to consolidate the Company's subsidiaries . . . . . . . . . -
Net increase (decrease) in Retirement work in progress. . . . . . . . . . (1,234)
--------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (2,895)
========
IV-13
Schedule VI
THE DAYTON POWER AND LIGHT COMPANY
ACCUMULATED DEPRECIATION AND AMORTIZATION (1)
For the year ended December 31, 1992
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
-------- -------- -------- -------- -------- --------
Balance at Additions Retirements, Other Changes - Balance
Beginning Charged to Renewals and Additions at End
Classification of Period Income Replacements (Deductions) of Period
-------------- ------------------------------Thousands---------------------------------
Electric--
Production. . . . . . . . . . . $445,070 $ 73,340 $ 6,700 $ (1,523) $510,187
Transmission. . . . . . . . . . 76,190 5,848 530 (57) 81,451
Distribution. . . . . . . . . . 127,657 15,186 3,920 (1,881) 137,042
General . . . . . . . . . . . . 22,593 3,116 609 242 25,342
Plant held for future use
(undistributed) . . . . . . . 231 - - 22 253
-------- -------- -------- -------- --------
Total electric . . . . . . . 671,741 97,490 11,759 (3,197) 754,275
Gas . . . . . . . . . . . . . . 86,113 5,554 916 (119) 90,632
Steam . . . . . . . . . . . . . 8,289 309 67 (3) 8,528
Other . . . . . . . . . . . . . - 551 - 3,598 4,149
-------- -------- -------- -------- --------
Total. . . . . . . . . . . . $766,143 $103,904 (2) $ 12,742 $ 279 (3) $857,584
======== ======== ======== ======== ========
(1) See Note 1 of Notes to Consolidated Financial Statements of the 1992 Form 10-K Report.
(2) Additions charged to income--
Depreciation and amortization expense (per above) . . . . . . . . . . . . $103,904
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 466
--------
Total per Consolidated Statement of Results of Operations . . . . . . . $104,370
========
(3) Consists of--
Reclassification of accumulated depreciation to deferred charges . . . . (524)
Depreciation and amortization charged to other accounts . . . . . . . . . 214
Net removal cost/salvage--
Removal cost . . . . . . . . . . . $(6,606)
Salvage . . . . . . . . . . . . . . 750
-------
Net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,856)
Adjustments of previously recorded activity . . . . . . . . . . . . . . . (196)
Adjustments to consolidate the Company's subsidiaries . . . . . . . . . 3,598
Net increase (decrease) in Retirement work in progress. . . . . . . . . . 3,043
--------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 279
========
IV-14
Schedule VI
THE DAYTON POWER AND LIGHT COMPANY
ACCUMULATED DEPRECIATION AND AMORTIZATION (1)
For the year ended December 31, 1991
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
-------- -------- -------- -------- -------- --------
Balance at Additions Retirements, Other Changes - Balance
Beginning Charged to Renewals and Additions at End
Classification of Period Income Replacements (Deductions) of Period
-------------- ------------------------------Thousands---------------------------------
Electric--
Production. . . . . . . . . . . $387,820 $ 66,216 $ 6,782 $ (2,184) $445,070
Transmission. . . . . . . . . . 70,959 5,522 221 (70) 76,190
Distribution. . . . . . . . . . 122,636 13,033 1,763 (6,249) 127,657
General . . . . . . . . . . . . 20,811 2,988 1,910 704 22,593
Plant held for future use
(undistributed) . . . . . . . 207 - - 24 231
-------- -------- -------- -------- --------
Total electric . . . . . . . 602,433 87,759 10,676 (7,775) 671,741
Gas . . . . . . . . . . . . . . 80,850 5,972 489 (220) 86,113
Steam . . . . . . . . . . . . . 8,118 301 129 (1) 8,289
-------- -------- -------- -------- --------
Total . . . . . . . . . . . $691,401 $ 94,032 (2) $ 11,294 $ (7,996) (3) $766,143
======== ======== ======== ======== ========
(1) See Note 1 of Notes to Financial Statements of the 1991 Form 10-K Report.
(2) Additions charged to income--
Depreciation and amortization expense (per above) . . . . . . . . . . . . $ 94,032
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179
--------
Total per Statement of Results of Operations . . . . . . . . . . . . . $ 94,211
========
(3) Consists of--
Reclassification of accumulated depreciation to deferred charges . . . . (888)
Depreciation and amortization charged to other accounts . . . . . . . . . 509
Net removal cost/salvage--
Removal cost . . . . . . . . . . . $(6,232)
Salvage . . . . . . . . . . . . . . (98)
-------
Net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,330)
Adjustments of previously recorded activity . . . . . . . . . . . . . . . (8)
Net increase (decrease) in Retirement work in progress. . . . . . . . . . (1,279)
--------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (7,996)
========
IV-15
Schedule VII - 1993
THE DAYTON POWER AND LIGHT COMPANY
OBLIGATIONS RELATING TO SECURITIES OF OTHER ISSUERS
At December 31, 1993
Title of Issue
Name of Issuer of Each Class of Nature of
of Securities Securities Amount Obligation
- ------------------------- ------------------------- --------------- ---------------
County of Boone, Kentucky Collateralized Pollution $48 million (1) Principal plus
Control Revenue Refunding $3.1 million of
Bonds interest
(1) The Company is obligated to pay the principal of and interest on $48 million
of 6.50% Collateralized Pollution Control Revenue Refunding Bonds Series
A Due 2022 issued by Boone County, Kentucky. In December 1992, the
Company transferred $12.7 million of the proceeds from the sale of these
bonds to The Cincinnati Gas & Electric Company (CG&E). CG&E is
responsible for the payment of the principal and related interest;
however the Company retains primary liability for the obligations.
This transfer resulted from the reduction of the Company's ownership
share in the first unit at the East Bend generating station, commonly
owned with CG&E.
IV-16
Schedule VIII
THE DAYTON POWER AND LIGHT COMPANY
VALUATION AND QUALIFYING ACCOUNTS
For the year ended December 31, 1993, 1992 and 1991
- --------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- --------------------------------------------------------------------------------------------------------
Additions
Balance at ------------------- Balance
Beginning Charged to Deductions at End
Description of Period Income Other (1) of Period
- --------------------------------------------------------------------------------------------------------
------------------------thousands----------------------------
1993:
Deducted from accounts receivable--
Provision for uncollectible accounts... $ 10,461 $ 1,353 $ - $2,692 $ 9,122
1992:
Deducted from accounts receivable--
Provision for uncollectible accounts... $ 11,510 $ 1,675 $ - $2,724 $ 10,461
1991:
Deducted from accounts receivable--
Provision for uncollectible accounts... $ 10,267 $ 5,058 $ - $3,815 $ 11,510
(1) Amounts written off, net of recoveries of accounts previously written off.
IV-17
Schedule IX
THE DAYTON POWER AND LIGHT COMPANY
SHORT-TERM BORROWINGS
For the years 1993, 1992 and 1991
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -------------------------------------------------------------------------------------------------------
Maximum Average Weighted
Category of Weighted Amount Amount Average
Aggregate Balance Average Outstanding Outstanding Interest Rate
Short-Term at End of Interest During the During the During the
Borrowings Period Rate Period Period (1) Period (1)
- ------------------------------------------------------------------------------------------------------
--thousands-- ---------thousands---------
1993--
Commercial Paper... $15,000 3.339% $62,000 $ 9,005 3.373%
Lines of Credit.... $10,000 3.679% $24,000 $ 8,399 3.380%
Notes Payable to
Related Parties.. $ 4,805 6.000% $ 4,805 $ 4,805 8.441%
1992--
Commercial Paper... $62,000 3.550% $62,000 $19,060 3.650%
Lines of Credit.... - - $52,500 $10,026 4.309%
Revolving Credit
Agreement........ - - $40,000 $ 2,740 4.881%
Notes Payable to
Related Parties.. $ 4,805 9.340% $ 4,805 $ 4,530 9.340%
1991--
Commercial Paper... $23,500 5.293% $69,500 $18,704 6.333%
Lines of Credit.... $21,000 5.214% $29,000 $10,170 5.896%
Revolving Credit
Agreement.......... $40,000 5.500% $40,000 $ 6,630 6.707%
(1) Based on daily balances.
IV-18
Schedule X
THE DAYTON POWER AND LIGHT COMPANY
SUPPLEMENTARY INCOME STATEMENT INFORMATION
For the years ended December 31, 1993, 1992 and 1991
- ------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B
- ------------------------------------------------------------------------------------------------------
Classification 1993 1992 1991
- ------------------------------------------------------------------------------------------------------
------------------thousands------------------
General taxes--
Property . . . . . . . . . . . . . . . . $ 56,063 $ 54,165 $42,386
State public utility excise . . . . . . 47,014 45,405 44,548
Payroll and other . . . . . . . . . . . 8,611 8,664 8,201
-------- -------- -------
Total per Consolidated Statement
of Results of Operation . . . . . $111,688 $108,234 $95,135
======== ======== =======
IV-19
EXHIBIT INDEX
-------------
Exhibit Page No.
- ------- --------
10(d) Amended description of Directors' Deferred
Stock Compensation Plan effective
January 1, 1993...............................
10(e) Amended description of Deferred Compensation
Plan for Non-Employee Directors effective
January 1, 1993...............................
10(f) Copy of Management Stock Incentive Plan
amended January 1, 1993.......................
21 Copy of List of Subsidiaries of the Company...