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UNITED STATES 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, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
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 IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
COURTHOUSE PLAZA SOUTHWEST, DAYTON, OHIO 45402
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's telephone number, including area code: 937-224-6000
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE
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. X
---
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 15,
2000, all of which were held by DPL Inc., was 41,172,173.
PART I
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. The Company sells electricity and
natural gas to residential, commercial and governmental customers in a 6,000
square mile area of West Central Ohio. Electricity for the Company's 24 county
service area is generated at eight power plants and is distributed to 495,000
retail customers. Natural gas is provided to 308,000 customers in 16 counties.
Principal industries served include electrical machinery, automotive and other
transportation equipment, non-electrical machinery, agriculture, paper, and
rubber and plastic products. The Company's sales reflect the general economic
conditions and seasonal weather patterns of the area. In 1999, electric revenues
decreased 1% due to lower sales to other public utilities and residential
customers. Utility gas revenues and gas purchased for resale each increased 2%
in 1999 due to higher sales to business customers. During 1999, cooling degree
days were 13% above the twenty year average and 3% below 1998. Heating degree
days in 1999 were 8% below the thirty year average and 12% above 1998. Sales
patterns will change in future years as weather and the economy fluctuate. The
Company employed 2,102 persons as of December 31, 1999, of which 1,778 are
full-time employees and 324 are part-time employees.
All of the outstanding shares of common stock of the Company are held
by DPL Inc. ("DPL"), which became the Company's corporate parent, effective
April 21, 1986.
In 1999, the Company transferred its ownership interests in the assets
and liabilities of MacGregor Park, Inc. to DPL and transferred its ownership
interests in the assets and liabilities of MVE, Inc. to Plaza Building Inc.,
which is another wholly-owned subsidiary of DPL.
The Company's principal executive and business office is located at
Courthouse Plaza Southwest, Dayton, Ohio 45402 - telephone (937) 224-6000.
* Unless otherwise indicated, the information given in "Item 1 -
Business" is current as of February 15, 2000. No representation is
made that there have not been 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 makes power purchases from other suppliers.
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 that govern the purchase of 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 of 1935, 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.
The Company provides transmission and wholesale electric service to
twelve municipal customers which distribute electricity within their corporate
limits. In addition to these municipal customers, the Company maintains an
interconnection agreement with one municipality that has the capability to
generate a portion of its energy requirements. Sales to municipalities
represented 1.3% of total electricity sales in 1999.
The municipal agreements provide, among other things, for the sale of
firm power by the Company to the municipals on specified terms. However, the
parties disagree in their interpretation of this portion of the agreement and
the Company filed suit against the eleven municipals on December 28, 1998. The
dispute was subsequently settled in 1999. In December 1999, the Company filed a
second suit against the municipals claiming their failure to pay for certain
services rendered under the contract. The municipals filed a complaint at the
Federal Energy Regulatory Commission ("FERC") claiming violation of a mediation
clause. This dispute is expected to be resolved through the FERC process, and is
not expected to result in a material impact on the Company's financial position.
I-2
On February 15, 1996, the Public Utilities Commission of Ohio ("PUCO")
issued guidelines for interruptible service, including services that accommodate
the attainment and delivery of replacement electricity during periods when the
utility faces constraints on its own resources. The Company's interruptible
electric service tariffs were approved on May 1, 1997, and tariffs conforming to
this order were subsequently filed with the PUCO on May 15, 1997.
On December 24, 1996, the PUCO issued a Finding and Order adopting
conjunctive electric service ("CES") guidelines and directing utilities to file
tariffs regarding CES service. CES programs enable customers to aggregate for
cost of service, rate design, rate eligibility and billing purposes. On December
30, 1998, the PUCO approved the Company's CES tariff, with an effective date of
January 4, 1999. Implementation of this program is essentially revenue neutral.
In October 1999, legislation ("the Legislation") became effective in
Ohio giving electric utility customers a choice of energy providers starting
January 1, 2001. Under the Legislation, electric generation, aggregation, power
marketing and power brokerage services supplied to retail customers in Ohio will
be deemed competitive and will not be subject to supervision and regulation by
the PUCO. Existing limitations on an electric public utility's ownership rights
of a non-public utility were eliminated. All earnings obligations, restrictions
or caps imposed on an electric utility in a PUCO order became void as of the
effective date of the Legislation.
As required by the Legislation, the Company filed its transition plan
at the PUCO on December 20, 1999. As part of the transition plan, the Company
also filed for the opportunity to receive transition revenues. These transition
revenues, once determined by the PUCO, will be recovered through a transition
charge during the market development period which ends no later than December
31, 2005. Regulatory assets that are part of the total allowable amount of
transition costs will be separately identified as part of the transition charge,
and the PUCO may set the revenue requirements for their recovery to end no later
than December 31, 2010. A shopping incentive may be factored into the setting of
the transition charge to induce 20% load switching by customer class by December
31, 2003, or halfway through the utility's market development period.
On April 24, 1996, FERC issued orders requiring all electric utilities
that own or control transmission facilities to file open-access transmission
service tariffs. Open-access transmission tariffs provide third parties with
non-discriminatory transmission service comparable to what the utility provides
itself. In its orders, FERC further stated that FERC-jurisdictional stranded
costs reasonably incurred and costs of complying with the rules will be
recoverable by electric utilities. Both in 1997 and 1998, the Company reached an
agreement in principle with staff and intervenors in these tariff cases. The
Company's revenues from customers will not be materially impacted by the final
resolution of these cases.
I-3
FERC issued an Order accepting the Stipulation between the parties in
the Company's Open Access Transmission Tariff cases on July 30, 1999 and
September 17, 1999. The Company was not materially impacted by the Order. FERC
issued a final rule on December 20, 1999 specifying the minimum characteristics
and functions for Regional Transmission Organizations ("RTO"). The rule required
that all public utilities that own, operate or control interstate transmission
file a proposal to join a RTO by October 15, 2000 or file a description of
efforts taken to participate in an RTO, reasons for not participating in an RTO,
any obstacles to participation in an RTO, and any plans for further work towards
participation.
On September 30, 1996, FERC conditionally accepted the Company's
market-based sales tariff which will allow the Company to sell wholesale
generation supply at prices that reflect current market prices. At the same
time, FERC approved the application and authorization of DPL Energy Inc., a
wholly-owned subsidiary of DPL, to sell and broker wholesale electric power and
also charge market-based prices for such power.
On July 22, 1998, the PUCO approved the implementation of Minimum
Electric Service Standards for all of Ohio's investor-owned electric utilities.
This Order details minimum standards of performance for a variety of service
related functions effective July 1, 1999. On December 21, 1999, the PUCO issued
additional rules proposed by the PUCO Staff which are designed to guide the
electric utility companies as they prepare to enter into deregulation. These
rules include certification of providers of competitive retail electric
services, minimum competitive retail electric service standards, monitoring the
electric utility market, and establishing procedures for alternative dispute
resolution. There were also rules issued to amend existing rules for
noncompetitive electric service and safety standards and electric companies
long-term forecast reporting. The Company submitted comments on the proposed
rules on January 31, 2000.
General deregulation of the natural gas industry has continued to
influence market competition as the driving force behind natural gas
procurement. The evolution of an efficient natural gas spot market in
combination with open-access interstate transportation 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 performance and
economics. Therefore, demand for natural gas purchased from the Company or
purchased elsewhere and 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-4
CONSTRUCTION AND FINANCING PROGRAM OF THE COMPANY
CONSTRUCTION PROGRAM
Construction additions were $80 million, $111 million, and $109 million
in 1999, 1998 and 1997, respectively. The Company recently completed its Phase
One peaking generation expansion with the addition of three GE combustion
turbines representing 250 MW. The capital program for 2000 consists of
construction costs of approximately $114 million.
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 recovery.
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.
FINANCING PROGRAM
At year-end 1999, cash and temporary cash investments were $96 million
and financial assets were $1 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.
On February 2, 2000, DPL announced that it had signed a definitive
agreement with affiliates of Kohlberg Kravis Roberts & Co. ("KKR"), an
investment company, under which KKR will make a strategic investment of $550
million in DPL. DPL intends to use the proceeds from this investment, combined
with $425 million of new debt capital, to continue its planned generation
strategy, retire short-term debt and purchase up to 31.6 million common shares.
The $425 million issuance of 8.25% Senior Notes due 2007 closed on February 24,
2000, and the $550 million investment by KKR closed on March 13, 2000. These
transactions resulted in an increase in the financial leverage of DPL in its
capital structure.
Under the terms of the agreement with KKR, which has been unanimously
approved by DPL's Board of directors, the investment includes a combination of
voting preferred and trust preferred securities and warrants to purchase DPL
common stock. The 31.6 million warrants, with an exercise price of $21,
represent approximately 19.9% of DPL shares currently outstanding. The voting
preferred securities carry voting rights for up to 4.9% of DPL's total voting
rights. The trust preferred securities have a term of 30 years (subject to
acceleration to six months after the exercise of warrants) and carry a dividend
rate of 8.5% payable in cash.
I-5
On February 4, 2000, DPL initiated an Offer to Purchase for Cash up to
25 million common shares, or approximately 16% of outstanding shares, at a price
of $20-$23, via a modified Dutch Auction process. This tender expired on March
3, 2000. Under the Offer, approximately 28 million shares, or 18% of outstanding
shares, were properly tendered and not withdrawn at prices at or below $23 per
share. Therefore, the buyback was prorated with a final proration factor of
91.3%. DPL accepted for purchase 25 million shares, or 16% of its common stock,
at a price of $23 per share. DPL currently intends to purchase up to an
additional 6.6 million shares after this offer is completed. The method, timing
and financing of such purchases have not yet been decided.
In December 1997, the Company redeemed a series of first mortgage bonds
in the principal amount of $40 million with an interest rate of 8.0%. The bonds
had been scheduled to mature in 2003. Another series of first mortgage bonds in
the principal amount of $40 million matured in 1997. Sinking fund payments
required for the next five years are $2 million.
In April 1999, DPL completed a private placement issuance of $500
million of Senior Notes Due 2004, with an interest rate of 6.32%. The proceeds
were used to redeem the 8.40% Series First Mortgage Bonds, the reduction of
short-term debt and for general corporate purposes.
DPL and its subsidiaries have $300 million available through revolving
credit agreements with a consortium of banks. One agreement, for $200 million,
expires in 2002 and the other, for $100 million, expires in 2000. The agreements
were amended effective March 10, 2000 so that the financial covenants would be
consistent with the effects of the Tender Offer and the associated financings.
At year-end 1999, DPL had no outstanding borrowings under these credit
agreements. The Company also has $75 million available in short-term lines of
credit. The Company had no outstanding borrowings from these lines of credit at
year-end 1999 and $81 million at year-end 1998. The Company had $123 million and
$99 million in commercial paper outstanding at year-end 1999 and 1998,
respectively.
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, or (ii) 100% of retired First
Mortgage Bonds. The Company anticipates that 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.
I-6
ELECTRIC OPERATIONS AND FUEL SUPPLY
The Company's present winter generating capability is 3,371,000 KW. Of
this capability, 2,843,000 KW (approximately 84%) 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.
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 3,130,000 KW, occurring in 1999. The present summer generating
capability is 3,269,000 KW.
GENERATING FACILITIES
MW Rating
------------------
Operating Company
Station Ownership* 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 33 33
Yankee Street W Company Centerville, OH 138 138
Monument W Company Dayton, OH 12 12
Tait W Company Dayton, OH 10 10
Sidney W Company Sidney, OH 12 12
Tait Gas Turbine 1 W Company Moraine, OH 100 100
Tait Gas Turbine 2 W Company Moraine, OH 102 102
Tait Gas Turbine 3 W Company Moraine, OH 102 102
Killen C Company Wrightsville, OH 16 24
Stuart C Company Aberdeen, OH 3 10
*W = Wholly Owned
C = Commonly Owned
I-7
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 1999. 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 2000-2004 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.
The average fuel cost per kWh generated of all fuel burned for electric
generation (coal, gas and oil) for the year was 1.30(cent) in 1999 and 1998 and
1.31(cent) in 1997. Beginning in February 2000, the Company's Electric Fuel
Component ("EFC") will be fixed at 1.30(cent) for the remainder of 2000. As
competition begins on January 1, 2001 the EFC will become part of the Standard
Offer Generation Rate. See RATE REGULATION AND GOVERNMENT LEGISLATION and
ENVIRONMENTAL CONSIDERATIONS.
GAS OPERATIONS AND GAS SUPPLY
The Company reached an agreement to sell its natural gas retail
distribution business unit for $425 million. This all-cash sale of assets (book
value approximating $250 million at December 31, 1999) is subject to regulatory
approvals and is expected to close by the end of the second quarter, 2000. The
after-tax proceeds from the sale will be used in the expansion of the electric
combustion turbine business, to finance in part other business unit capital
needs, to continue the stock buyback program and to reduce outstanding
short-term debt.
The Company has long-term firm pipeline transportation agreements with
ANR Gas Pipeline Company ("ANR"), Texas Gas Transmission Corporation ("Texas
Gas"), Panhandle Eastern Pipe Line Company ("Panhandle"), Columbia Gas
Transmission Corporation ("Columbia") and Columbia Gulf Transmission Corporation
for varying terms, up to early 2005. Along with firm transportation services,
the Company has approximately 14 billion cubic feet of firm storage service with
various pipelines.
I-8
In addition, the Company is interconnected with CNG Transmission
Corporation. Interconnections with interstate pipelines provide the Company the
opportunity to purchase competitively priced natural gas supplies and pipeline
services. The Company purchases its natural gas supplies using a portfolio
approach that minimizes price risks and ensures sufficient firm supplies at peak
demand times. The portfolio consists of long-term, short-term and spot supply
agreements. In 1999, firm agreements provided approximately 60% of total supply,
with the remaining supplies purchased on a spot/short-term basis.
In 1999, the Company purchased natural gas at an average price of $3.68
per MCF, compared to $3.22 per MCF in 1998 and $3.45 per MCF in 1997. 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 PUCO supports 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 an approved tariff and provides
transportation service to approximately 600 end-use customers, delivering a
total quantity of nearly 20,200,000 MCF per year.
RATE REGULATION AND GOVERNMENT LEGISLATION
The Company's sales of electricity and natural gas 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 establishes the Office of the
Ohio Consumers' Counsel (the "OCC"), which has the authority 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. Beginning in February 2000, the Company's EFC will be fixed at 1.30(cent)
for the remainder of 2000. As competition begins on January 1, 2001 the EFC will
become part of the Standard Offer Generation Rate.
I-9
On June 18, 1996, Ohio Governor Voinovich signed into law House Bill
476 which allows for alternate natural gas rate plans and exemption from PUCO
jurisdiction for some gas services, and establishes a code of conduct for
natural gas distribution companies. Final rules were issued on March 12, 1997.
Ohio legislation extends the jurisdiction of the PUCO to the records
and accounts of certain public utility holding company systems, including DPL.
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.
Regulatory assets recorded during the phase-in of electric rates were
recovered in revenues through 1999. A 1992 PUCO-approved agreement for the
phase-in plan provided that after the end of the deferral period the Company
would maintain a balance sheet reserve account which shall operate to reduce the
otherwise applicable jurisdictional production plant valuation subject to
recovery in rates. In addition, deferred interest charges on the William H.
Zimmer Generating Station are being amortized at $2.8 million per year over the
projected life of the asset.
The 1992 PUCO-approved settlement agreement for the demand-side
management ("DSM") programs, as updated in 1995, provided for accelerated
recovery of DSM costs and, thereafter, production plant costs to the extent that
the Company's return on equity exceeds a baseline 13% (subject to upward
adjustment). If the return exceeds the baseline return by one to two percent,
one-half of the excess is used to accelerate recovery of these costs. If the
return is greater than two percent over the baseline, the entire excess is used
for such purpose. In 1998, amortization of regulatory assets included an
additional $10.4 million of accelerated cost recovery. In 1999, the Legislation
removed the return on equity cap.
Regulatory deferrals on the balance sheet were:
Dec. 31 Dec. 31
1999 1998
-------- --------
--millions--
Phase-in $ (6.8) $ 12.9
DSM 13.2 19.6
Deferred interest - Zimmer 46.9 49.7
Income taxes recoverable through
future revenues 168.5 195.5
-------- --------
Total $ 221.8 $ 277.7
======== ========
I-10
Under the Legislation passed in 1999, the percentage of income payment
plan ("PIPP") for eligible low-income households will be converted to a
universal service fund. The universal service program will be administered by
the Ohio Department of Development. As part of the Company's Electric Transition
Plan, the Company has requested to recover PIPP arrearages remaining as of
December 31, 2000 as part of a transition charge.
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. On April 15, 1999 and June 1, 1999, respectively, the Company filed
its electric and natural gas LTFR with the PUCO. Legislation for competitive
retail electric service will change the scope of the electric LTFR filing
requirements in the future.
The PUCO is composed of five commissioners appointed to staggered
five-year terms. The current Commission is composed of the following members:
Name Beginning of Term End of Term
- ---- ----------------- -----------
Chairman Alan R. Schriber April 1999 April 2004
Donald L. Mason April 1998 April 2003
Judith A. Jones April 1997 April 2002
Craig A. Glazer April 1996 April 2001
Rhonda H. Fergus April 1995 April 2000
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 possibility exists that current environmental regulations could be
revised which could change the level of estimated construction expenditures. See
CONSTRUCTION AND FINANCING PROGRAM OF THE COMPANY.
I-11
AIR QUALITY
The Clean Air Act Amendments of 1990 (the "Act") have limited sulfur
dioxide and nitrogen oxide emissions nationwide. The Act restricts emissions in
two phases. Phase I compliance requirements became effective on January 1, 1995
and Phase II requirements will become effective on January 1, 2000. Compliance
by the Company has not caused any material changes in the Company's costs or
operations.
The Company's environmental compliance plan ("ECP") was approved by the
PUCO on May 6, 1993 and, on November 9, 1995, the PUCO approved the continued
appropriateness of the ECP. Phase I requirements were met by switching to lower
sulfur coal at several commonly owned electric generating facilities and
increasing existing scrubber removal efficiency. Total capital expenditures to
comply with Phase I of the Act were approximately $5.5 million. Phase II
requirements are being met primarily by switching to lower sulfur coal at all
non-scrubbed coal-fired electric generating units. Overall compliance is
projected to have a minimal price impact.
In November 1999, the United States Environmental Protection Agency
("U.S. EPA") filed civil complaints and Notices of Violations ("NOVs") against
operators and owners of certain generation facilities for alleged violations of
the Clean Air Act ("CAA"). Generation units operated by partners Cincinnati Gas
& Electric (Beckjord 6) and Columbus Southern Power (Conesville 4) and co-owned
by the Company were referenced in these actions. On March 1, 2000, the U.S. EPA
filed amended complaints in the civil actions that U.S. EPA had brought against
the partners in November 1999. The amended complaint against Cincinnati Gas &
Electric includes alleged violations pertaining to Beckjord 6. Numerous
northeast states have filed complaints or have indicated that they will be
joining the EPA's action against the partners. The Company was not identified in
the NOVs, civil complaints or state actions. The partners will vigorously
challenge the NOVs and complaints in court. At this time, it is not possible to
determine the outcome of these claims or the impact, if any, on the Company.
In September 1998, the U.S. EPA issued a final rule requiring states to
modify their State Implementation Plans ("SIPs") under the CAA. The modified
SIPs are likely to result in further nitrogen oxide ("NOx") reduction
requirements placed on coal-fired generating units by 2003. In order to meet
these NOx requirements, the Company's total capital expenditures are estimated
to be approximately $175 million over the next five years. Industry groups and
others appealed the rules in United States District Court. The requirement for
states to submit revised implementation plans has been stayed until the outcome
of the litigation. In March 2000, the United States District Court upheld the
rule. Industry groups and others are considering an appeal of this decision. In
late December 1999, the U.S. EPA issued final rules granting various CAA Section
126 petitions filed by northeast states. The Company's facilities were
identified, among many others, in the rulemaking. The Company's current NOx
reduction strategy and associated expenditures to meet the SIP call should
satisfy the rulemaking reduction requirements.
I-12
LAND USE
The Company and numerous other parties have been notified by U.S. EPA
or the Ohio Environmental Protection Agency ("Ohio EPA") that it considers them
Potentially Responsible Parties ("PRPs") for clean-up at two superfund sites in
Ohio: the Sanitary Landfill Site on Cardington Road in Montgomery County, Ohio
and the North Sanitary (a.k.a. Valleycrest) Landfill in Dayton, 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 final resolution is not expected to have a material effect on
the Company's financial position, earnings or cash flow.
The Company and numerous other parties received notification from the
Ohio EPA on July 27, 1994 that it considers them PRPs for clean up of hazardous
substances at the North Sanitary Landfill site in Dayton, Ohio. The Company has
not joined the PRP group formed for the site because the available information
does not demonstrate that the Company contributed wastes to the site. The final
resolution is not expected to have a material effect on the Company's financial
position, earnings or cash flow.
I-13
THE DAYTON POWER AND LIGHT COMPANY
OPERATING STATISTICS
ELECTRIC OPERATIONS
YEARS ENDED DECEMBER 31
-----------------------------------------------------
1999 1998 1997
------------ ------------ ------------
Electric Output (millions of kWh)
General -
Coal-fired units ........................ 16,539 16,854 16,246
Other units ............................. 189 99 52
Power purchases ............................. 1,523 1,475 1,239
Company use and line losses ................. (1,384) (947) (928)
------------ ------------ ------------
Total ................................... 16,867 17,481 16,609
============ ============ ============
Electric Sales (millions of kWh)
Residential ................................. 4,725 4,790 4,788
Commercial .................................. 3,390 3,518 3,408
Industrial .................................. 4,876 4,655 4,749
Public authorities and railroads ............ 1,305 1,360 1,330
Private utilities and wholesale ............. 2,571 3,158 2,334
------------ ------------ ------------
Total ................................... 16,867 17,481 16,609
============ ============ ============
Electric Customers at End of Period
Residential ................................. 441,468 437,674 433,563
Commercial .................................. 45,470 44,716 43,923
Industrial .................................. 1,917 1,909 1,881
Public authorities and railroads ............ 5,994 5,838 5,736
Other ....................................... 46 43 42
------------ ------------ ------------
Total ................................... 494,895 490,180 485,145
============ ============ ============
Operating Revenues (thousands)
Residential ................................. $ 412,808 $ 419,948 $ 409,857
Commercial .................................. 235,309 242,526 234,206
Industrial .................................. 242,410 228,685 225,775
Public authorities and railroads ............ 69,777 76,686 74,018
Private utilities and wholesale ............. 79,196 86,485 53,598
Other ....................................... 18,844 18,651 12,523
------------ ------------ ------------
Total ................................... $ 1,058,344 $ 1,072,981 $ 1,009,977
============ ============ ============
Residential Statistics (per customer-average)
Sales - kWh ................................. 10,758 10,999 11,120
Revenue ..................................... $ 940.00 $ 964.40 $ 951.90
Rate per kWh ................................ 8.74CENTS 8.77CENTS 8.56CENTS
* See Note 14 to Consolidated Financial Statements for additional information.
I-14
THE DAYTON POWER AND LIGHT COMPANY
OPERATING STATISTICS
GAS OPERATIONS
YEARS ENDED DECEMBER 31
-------------------------------------------
1999 1998 1997
---------- ---------- ----------
Gas Output (thousands of MCF)
Direct market purchases ..................... 37,865 36,497 43,808
Liquefied petroleum gas ..................... 2 3 66
Company use and unaccounted for ............. (2,116) (912) (1,016)
Transportation gas received ................. 19,964 18,125 19,182
---------- ---------- ----------
Total ................................... 55,715 53,713 62,040
========== ========== ==========
Gas Sales (thousands of MCF)
Residential ................................. 24,450 24,877 29,277
Commercial .................................. 7,647 7,433 9,567
Industrial .................................. 2,246 1,916 2,520
Public authorities .......................... 1,182 1,699 2,153
Transportation gas delivered ................ 20,190 17,788 18,523
---------- ---------- ----------
Total ................................... 55,715 53,713 62,040
========== ========== ==========
Gas Customers at End of Period
Residential ................................. 282,706 279,784 276,189
Commercial .................................. 22,635 22,491 22,298
Industrial .................................. 1,303 1,441 1,396
Public authorities .......................... 1,173 1,509 1,475
---------- ---------- ----------
Total ................................... 307,817 305,225 301,358
========== ========== ==========
Operating Revenues (thousands)
Residential ................................. $ 139,545 $ 138,802 $ 160,279
Commercial .................................. 40,225 38,243 48,302
Industrial .................................. 11,017 9,291 11,867
Public authorities .......................... 5,908 8,230 10,311
Other ....................................... 18,284 16,640 12,948
---------- ---------- ----------
Total ................................... $ 214,979 $ 211,206 $ 243,707
========== ========== ==========
Residential Statistics (per customer-average)
Sales - MCF ................................. 87.1 89.6 107.0
Revenue ..................................... $ 497.15 $ 499.94 $ 585.63
Rate per MCF ................................ $ 5.71 $ 5.58 $ 5.47
* See Note 14 to Consolidated Financial Statements for additional information.
I-15
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-5 and I-6), ELECTRIC OPERATIONS AND FUEL SUPPLY (pages
I-7 and I-8) and Item 8 - Notes 4 and 7 of Notes to Consolidated Financial
Statements on pages II-17 and II-22, 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 and I-9) and Note 12 of Notes to Consolidated Financial Statements
(page II-24), which pages are incorporated herein by reference.
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), COMPETITION (Pages I-2
through I-4), ELECTRIC OPERATIONS AND FUEL SUPPLY (pages I-7 and I-8), GAS
OPERATIONS AND GAS SUPPLY (pages I-8 and I-9) and Note 12 of Notes to
Consolidated Financial Statements on page II-24, RATE REGULATION AND GOVERNMENT
LEGISLATION (pages I-9 through I-11), ENVIRONMENTAL CONSIDERATIONS (pages I-11
through I-13) and Item 8 - Note 4 of Notes to Consolidated Financial Statements
on page II-17, which pages are incorporated herein by reference.
Item 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- -------------------------------------------------------------------------------
None.
I-16
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-26 and the Financial and
Statistical Summary on page II-27, which pages are incorporated herein by
reference.
As 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 $1,200,000. As of year-end, all
earnings reinvested in the business of the Company were available for Common
Stock dividends.
Item 6 - SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
The information required by this item of Form 10-K is set forth in Item
8 - Financial and Statistical Summary on page II-27, which page is incorporated
herein by reference.
II-1
Item 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
- --------------------------------------------------------------------------------
The Dayton Power and Light Company
Performance Highlights 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
CAPITAL INVESTMENT PERFORMANCE:
Capital structure (millions)
Common shareholder's equity.............................$ 1,297.6 1,273.0 1,280.8
Preferred stock.........................................$ 22.9 22.9 22.9
Long-term debt..........................................$ 661.2 885.6 886.0
----- ----- -----
Total..............................................$ 1,981.7 2,181.5 2,189.7
OPERATING PERFORMANCE:
Electric--
Sales (millions of kWh)
Residential............................................. 4,725 4,790 4,788
Commercial.............................................. 3,390 3,518 3,408
Industrial.............................................. 4,876 4,655 4,749
Other................................................... 3,876 4,518 3,664
----- ----- -----
Total.............................................. 16,867 17,481 16,609
Revenues (millions)
Residential.............................................$ 412.8 419.9 409.9
Commercial..............................................$ 235.3 242.5 234.2
Industrial..............................................$ 242.4 228.7 225.8
Other...................................................$ 167.8 181.9 140.1
----- ----- -----
Total..............................................$ 1,058.3 1,073.0 1,010.0
Average price per kWh - retail and wholesale
customers (calendar year)...................................CENTS 6.19 6.03 6.01
Gas--
Sales (thousands of MCF)
Residential............................................. 24,450 24,877 29,277
Commercial.............................................. 7,647 7,433 9,567
Industrial.............................................. 2,246 1,916 2,520
Other................................................... 21,372 19,487 20,676
------ ------ ------
Total.............................................. 55,715 53,713 62,040
Revenues (millions)
Residential.............................................$ 139.6 138.8 160.3
Commercial..............................................$ 40.2 38.2 48.3
Industrial..............................................$ 11.0 9.3 11.9
Other...................................................$ 24.2 24.9 23.9
---- ---- ----
Total..............................................$ 215.0 211.2 244.4
Average price per MCF - total (calendar year)....................$ 3.86 3.93 3.93
II-2
Income Statement Highlights
$ in millions 1999 1998 1997
- -------------------------------------------------------------------------------------------------------
Electric utility:
Revenues.................................... $1,058 $1,073 $1,010
Fuel and purchased power.................... 262 257 227
--- --- ---
Net revenues............................ 796 816 783
Gas utility:
Revenues.................................... 215 211 244
Gas purchased for resale.................... 130 128 151
--- --- ---
Net revenues............................ 85 83 93
Operation and maintenance expense................ 206 244 252
Amortization of regulatory assets, net........... 26 33 21
Investment income................................ 22 17 15
Income taxes..................................... 121 113 100
Earnings on common stock......................... 192 169 171
RESULTS OF OPERATIONS
The 1999 earnings on common stock were $192 million compared to $169
million in 1998 and $171 million in 1997.
In 1999, electric revenues decreased 1% due to lower sales to other
public utilities and residential customers. Fuel and purchased power expense
increased 2% primarily related to higher purchased power costs. In 1998,
electric revenues increased 6% due to higher sales to other public utilities
and commercial business customers. Fuel and purchased power expense increased
13% primarily related to the higher sales.
Utility gas revenues and gas purchased for resale each increased 2% in
1999 due to higher sales to business customers. Utility gas revenues and gas
purchased for resale in 1998 decreased 13% and 15%, respectively, due to the
effects of milder weather.
Operation and maintenance expense decreased 16% in 1999 due to lower
costs for insurance, claims, labor, benefits and line clearance. The 3%
decrease in 1998 was due to lower insurance, claims and production maintenance
costs, which were partially offset by increased compensation and benefit
expense and higher electric distribution maintenance costs.
II-3
Investment income increased 31% in 1999 and 16% in 1998 due to
realized gains.
Regulatory assets recorded during the phase-in of electric rates have
been fully recovered. The 1992 Public Utilities Commission of Ohio
("PUCO")-approved agreement for the phase-in plan provided that after the end
of the deferral period, the Company would maintain a balance sheet reserve
account which shall operate to reduce the otherwise applicable jurisdictional
production plant valuation subject to recovery in rates. Deferred interest
charges on the William H. Zimmer Generating Station are being amortized at $3
million per year over the projected life of the asset.
A 1992 PUCO-approved settlement agreement and a subsequent stipulation
in 1995 provided for accelerated recovery of demand-side management costs and,
thereafter, production plant costs to the extent that the Company's return on
equity exceeds a baseline 13%. If the return exceeds the baseline return by one
to two percent, one-half of the excess is used to accelerate recovery of these
costs. If the return is greater than two percent over the baseline, the entire
excess is used for such purpose. In 1998, amortization of regulatory assets
included an additional $10 million of accelerated cost recovery. In 1999, the
return on equity cap for electric operations was eliminated pursuant to the
restructuring legislation discussed below.
Depreciation and amortization expense increased 7% in 1999 and 3% in
1998 primarily as a result of increased depreciable assets.
Interest expense decreased 10% in 1999 due primarily to decreased
long-term and short-term debt. Interest expense increased 3% in 1998 primarily
due to increased short-term debt.
Certain risks of the Company are insured through a captive insurance
company wholly owned by DPL Inc.
CONSTRUCTION PROGRAM AND FINANCING
Construction additions were $80 million, $111 million, and $109
million in 1999, 1998 and 1997, respectively. The Company recently completed
its Phase One peaking generation expansion with the addition of three GE
combustion turbines representing 250 MW. The capital program for 2000 consists
of construction costs of approximately $114 million.
During 1999, total cash provided by operating activities was $401
million. At year-end, cash and temporary cash investments were $96 million and
financial assets were $1 million.
On February 2, 2000, DPL Inc. entered into a series of
recapitalization transactions including the issuance to Kohlberg Kravis Roberts
& Co. ("KKR"), an investment company, of $550 million of a combination of
voting preferred and trust preferred securities and warrants. The trust
preferred securities sold to KKR have an
II-4
aggregate face amount of $550 million, were issued at an initial discounted
aggregate price of $500 million, have a maturity of 30 years (subject to
acceleration to six months after the exercise of warrants) and pay
distributions at a rate of 8.5% of the aggregate face amount per year. The 6.8
million shares of mandatorily redeemable voting preferred securities, par value
of $0.01 per share, were issued at an aggregate purchase price of $68,000 and
carry voting rights for up to 4.9% of DPL Inc.'s total voting rights and the
nomination of one Board seat. The 31.6 million warrants, representing
approximately 19.9% of DPL Inc.'s shares currently outstanding, have a term of
12 years, an exercise price of $21 per share and were sold for an aggregate
purchase price of $50 million. The $550 million KKR investment closed on March
13, 2000. DPL Inc. intends to recognize the trust preferred securities original
issue discount and issuance costs in 2000.
DPL Inc. intends to use the proceeds from this recapitalization,
combined with $425 million of new debt capital, to continue its planned
generation strategy, to retire short-term debt and to repurchase up to 31.6
million shares of common stock. The $425 million issuance of 8.25% Senior Notes
due 2007 closed on February 24, 2000. These transactions resulted in an
increase in the financial leverage of DPL Inc. in its capital structure.
On February 4, 2000, DPL Inc. initiated an Offer to Purchase for Cash
up to 25 million common shares, or approximately 16% of outstanding shares, at
a price of $20-$23, via a modified Dutch Auction process. This tender expired
on March 3, 2000. Under the Offer, approximately 28 million shares, or 18% of
outstanding shares, were properly tendered and not withdrawn at prices at or
below $23 per share. Therefore, the buyback was prorated with a final proration
factor of 91.3%. DPL accepted for purchase 25 million shares, or 16% of its
common stock, at a price of $23 per share. DPL Inc. currently intends to
purchase an additional 6.6 million shares after this offer is completed. The
method, timing and financing of such purchases have not yet been decided.
Issuance of additional amounts of first mortgage bonds by the Company
is limited by provisions of its mortgage. The amounts and timing of future
financings will depend upon market and other conditions, rate increases, levels
of sales and construction plans. The Company currently has sufficient capacity
to issue first mortgage bonds to satisfy its requirements in connection with
the financing of its construction and refinancing programs during the five-year
period 2000-2004.
At year-end 1999, the Company's senior debt credit ratings were as
follows:
Duff & Phelps, Inc. AA
Standard & Poor's Corporation AA-
Moody's Investors Service Aa3
II-5
Following DPL Inc.'s recapitalization announcement the rating agencies
confirmed new ratings as follows:
Duff & Phelps, Inc. AA
Standard & Poor's Corporation BBB+
Moody's Investors Service A2
The credit ratings for the Company are investment grade.
MARKET RISK
The carrying value of the Company's debt was $785 million at December
31, 1999, consisting of the Company's first mortgage bonds and guaranteed air
quality development obligations, notes and commercial paper. The fair value of
this debt was $776 million, based on current market prices or discounted cash
flows using current rates for similar issues with similar terms and remaining
maturities. The following table presents the principal cash repayments and
related weighted average interest rates by maturity date for long-term,
fixed-rate debt at December 31, 1999.
Long-term Debt
-------------------------------------------------------
Expected Maturity Amount
Date ($ in millions) Average Rate
- ----------------------------------------------------------------------------------------
2000 $0.4 6.4%
2001 0.4 6.4%
2002 0.4 6.4%
2003 0.4 6.4%
2004 0.4 6.4%
Thereafter 660.8 7.4%
-----
Total $662.8 7.4%
=====
Fair Value $651.4
Because the long-term debt is at a fixed rate, the primary market risk
to the Company is short-term interest rate risk. The carrying value and fair
value of short-term debt was $125 million with a weighted average interest rate
of 5.9% at December 31, 1999. The interest expense risk related to short-term
debt was estimated to be approximately an increase/decrease of $0.5 million if
the weighted average cost for each quarter increased/decreased 10%.
The fair value of available-for-sale securities was $62 million at
December 31, 1999. The equity price risk related to these securities was
estimated as the potential increase/decrease in fair value of $6 million at
December 31, 1999, resulting from a hypothetical 10% increase/decrease in the
market prices.
II-6
ISSUES AND FINANCIAL RISKS
This report contains certain forward-looking statements regarding
plans and expectations for the future. Investors are cautioned that actual
outcomes and results may vary materially from those projected due to various
factors beyond the Company's control, including abnormal weather, unusual
maintenance or repair requirements, changes in fuel costs, increased
competition, regulatory changes and decisions, changes in accounting rules and
adverse economic conditions.
ELECTRIC RESTRUCTURING LEGISLATION
In October 1999, legislation ("the Legislation") became effective in
Ohio giving electric utility customers a choice of energy providers starting
January 1, 2001. Under the Legislation, electric generation, aggregation, power
marketing and power brokerage services supplied to retail customers in Ohio will
be deemed competitive and will not be subject to supervision and regulation by
the PUCO. Existing limitations on an electric public utility's ownership rights
of a non-public utility were eliminated. All earnings obligations, restrictions
or caps imposed on an electric utility in a PUCO order became void as of the
effective date of the Legislation.
The Legislation includes provisions for unbundling of rates into
several service components, a period of transition to competitive pricing for
generation and certain related services (including discontinuance of the fuel
cost recovery clause), the separation of competitive and non-competitive
services, the transfer of control of transmission facilities from the utility
owners to separate qualifying transmission entities, a 5% rate reduction for
residential customers limited to the generation portion of their bill, an
employee assistance plan, consumer education and protection and changes in
utility taxation. Electric prices, including the 5% residential rate cut, are
capped through 2004. The estimated revenue impact of the 5% rate cut for the
Company's residential customers is approximately $45 million over five years.
Also included is a provision for utilities to request recovery of certain costs
relating to the transition.
As required by the Legislation, the Company filed its transition plan
with the PUCO in December 1999. The Company's plan included a request for $441
million in after-tax transition costs to be recovered through transition
charges during the market development period which ends December 31, 2004. Also
included in the filing is the Company's plan for corporate separation and for
joining a qualified transmission entity by January 1, 2001.
The PUCO is required to issue a final order not later than 275 days
after the plan is filed, or no later than October 31, 2000. The Company is
unable to predict the outcome of the regulatory process which could have an
impact on the Company's future financial position, earnings or cash flows.
Until the outcome is known, the Company will continue to account for its
generation business according to the Financial Accounting Standards Board
("FASB") Statement No. 71, "Accounting for the Effects of Certain Types of
Regulation".
II-7
In 1996 and 1997, the Federal Energy Regulatory Commission ("FERC")
issued orders requiring all electric utilities to file open-access transmission
service tariffs. The Company's resulting tariff case proceedings with FERC
staff and intervenors in 1997 and 1998 culminated in 1999 with FERC issuing an
Order approving the Company's settlement with no material adverse effect to the
Company.
BUSINESS UNIT EVALUATION
Responding to the new Ohio Legislation, the Company is separating its
various business units and evaluating each unit on a stand-alone basis. Business
units not complementing the Company's going-forward strategy may be divested.
The Company reached an agreement to sell its natural gas retail
distribution business unit for $425 million. This all-cash sale of assets (book
value approximating $250 million at December 31, 1999) is subject to regulatory
approvals and is expected to close by the end of the second quarter, 2000. The
after-tax proceeds from the sale will be used in the expansion of the electric
combustion turbine business, to finance in part other business unit capital
needs, to continue DPL Inc.'s stock buyback program and to reduce outstanding
short-term debt.
ENVIRONMENTAL
In November 1999, the United States Environmental Protection Agency
("EPA") filed civil complaints and Notices of Violations ("NOVs") against
operators and owners of certain generation facilities for alleged violations of
the Clean Air Act ("CAA"). Generation units operated by partners Cincinnati Gas
& Electric (Beckjord 6) and Columbus Southern Power (Conesville 4) and co-owned
by the Company were referenced in these actions. On March 1, 2000, the U.S. EPA
filed amended complaints in the civil actions that U.S. EPA had brought against
the partners in November 1999. The amended complaint against Cincinnati Gas &
Electric includes alleged violations pertaining to Beckjord 6. Numerous
northeast states have filed complaints or have indicated that they will be
joining the EPA's action against the partners. The Company was not identified in
the NOVs, civil complaints or state actions. The partners will vigorously
challenge the NOVs and complaints in court. At this time, it is not possible to
determine the outcome of these claims or the impact, if any, on the Company.
The United States and Ohio EPAs have notified numerous parties,
including the Company, that they are considered "Potentially Responsible
Parties" for clean up of two hazardous waste sites in Ohio. The United States
EPA has estimated total costs of under $10 million for its preferred clean-up
plans at one of these sites. The Ohio EPA has not provided an estimated cost
for the second site. During 1998, the Company settled its potential liability
for two other sites at a minimal cost. The final resolution of the remaining
investigations is not expected to have a material effect on the Company's
financial position, earnings or cash flow.
In September 1998, the United States EPA issued a final rule requiring
states to modify their State Implementation Plans ("SIPs") under the CAA. The
modified SIPs are likely to result in further nitrogen oxide ("NOx") reduction
requirements placed on coal-fired generating units by 2003. In order to meet
these NOx requirements, the
II-8
Company's total capital expenditures are estimated to be approximately $175
million over the next five years. Industry groups and others appealed the rules
in the United States District Court. The requirement for states to submit
revised implementation plans has been stayed until the outcome of the
litigation. In March 2000, the United States District Court upheld the rule.
Industry groups and others are considering an appeal of this decision. In late
December 1999, the EPA issued final rules granting various CAA Section 126
petitions filed by northeast states. The Company's facilities were identified,
among many others, in the rulemaking. The Company's current NOx reduction
strategy to meet the SIP call is expected to satisfy the rulemaking reduction
requirements.
OTHER ISSUES
The Compact Agreement between the Company and Local 175, Utility
Workers of America, AFL-CIO expired on October 31, 1999. Management and Union
Negotiations' Committees are discussing provisions of a new agreement that will
be responsive to the changes in business conditions resulting from the
Legislation.
The Company experienced no adverse Y2K effects.
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to Market Risk is contained in Item 7 -
Management's Discussion and Analysis (page 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, 1999..................... II-10
Consolidated Statement of Cash Flows for the three
years in the period ended December 31, 1999................................... II-11
Consolidated Balance Sheet as of December 31, 1999 and 1998................... II-12 - II-13
Consolidated Statement of Shareholder's Equity for the three years in
the period ended December 31, 1999............................................ II-14
Notes to Consolidated Financial Statements.................................... II-15 - II-25
Report of Independent Accountants............................................. II-28
Index to Supplemental Information Page No.
- --------------------------------- --------
Selected Quarterly Information................................................ II-26
Financial and Statistical Summary............................................. II-27
II-9
THE DAYTON POWER AND LIGHT COMPANY
CONSOLIDATED STATEMENT OF RESULTS OF OPERATIONS
- ---------------------------------------------------------------------- --------------------------------------------
For the years ended December 31,
$ in millions 1999 1998 1997
- ---------------------------------------------------------------------- -------------- -------------- --------------
REVENUES
Utility service revenues--
Electric................................................... $1,058.3 $1,073.0 $1,010.0
Gas........................................................ 215.0 211.2 244.4
----- ----- -----
Total utility service revenues......................... 1,273.3 1,284.2 1,254.4
------- ------- -------
EXPENSES
Fuel and purchased power........................................ 262.3 257.4 227.9
Gas purchased for resale........................................ 129.9 127.9 150.7
Operation and maintenance....................................... 206.0 244.3 251.9
Depreciation and amortization (Note 1).......................... 134.0 125.5 121.8
Amortization of regulatory assets, net (Note 4)................. 25.8 33.0 20.9
General taxes................................................... 136.4 136.2 133.5
----- ----- -----
Total expenses......................................... 894.4 924.3 906.7
----- ----- -----
INCOME
Operating Income................................................ 378.9 359.9 347.7
Investment income............................................... 22.3 17.0 14.6
Interest expense................................................ (79.8) (88.6) (86.0)
Other income (deductions)....................................... (7.8) (5.8) (4.7)
---- ---- ----
INCOME BEFORE INCOME TAXES 313.6 282.5 271.6
Income Taxes (Notes 1 and 5).................................... 121.1 113.0 99.6
----- ----- ----
NET INCOME...................................................... 192.5 169.5 172.0
Preferred Dividends (Note 10)................................... 0.9 0.9 0.9
--- --- ---
EARNINGS ON COMMON STOCK........................................ $191.6 $168.6 $171.1
===== ===== =====
See Notes to Consolidated Financial Statements.
II-10
THE DAYTON POWER AND LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
- ------------------------------------------------------------------------ ----------------------------------------------
For the years ended December 31,
$ in millions 1999 1998 1997
- ------------------------------------------------------------------------ --------------- -------------- ---------------
OPERATING ACTIVITIES
Cash received from utility customers......................... $1,280.1 $1,258.0 $1,230.3
Other operating cash receipts................................ 30.0 15.0 11.7
Cash paid for:
Fuel and purchased power................................. (263.8) (266.5) (235.9)
Purchased gas............................................ (135.9) (138.6) (167.2)
Operation and maintenance labor.......................... (72.8) (84.0) (81.4)
Nonlabor operating expenditures.......................... (113.8) (143.3) (155.7)
Interest................................................. (79.2) (86.0) (85.2)
Income taxes............................................. (106.6) (132.3) (89.0)
General taxes............................................ (136.7) (131.1) (130.5)
------ ------ ------
Net cash provided by operating activities
(Note 13).................................................. 401.3 291.2 297.1
----- ----- -----
INVESTING ACTIVITIES
Capital expenditures......................................... (80.3) (106.4) (110.9)
Purchases of available-for-sale financial assets............. (276.9) (147.7) (59.9)
Sales of available-for-sale financial assets................. 61.1 43.9 14.0
---- ---- ----
Net cash used for investing activities....................... (296.1) (210.2) (156.8)
------ ------ ------
FINANCING ACTIVITIES
Dividends paid on common stock............................... (130.3) (238.8) (118.5)
Issuance of short-term debt.................................. 112.2 100.2 69.8
Parent company capital contribution (Note 9)................. 245.0 49.0 -
Retirement of long-term debt (Note 9)........................ (237.6) (0.4) (81.0)
Dividends paid on preferred stock............................ (0.9) (0.9) (0.9)
---- ---- ----
Net cash used for financing activities....................... (11.6) (90.9) (130.6)
----- ----- ------
CASH AND TEMPORARY CASH INVESTMENTS--
Net change............................................... 93.6 (9.9) 9.7
Balance at beginning of period........................... 1.9 11.8 2.1
--- ---- ---
Balance at end of period................................. $95.5 $1.9 $11.8
==== === ====
NON-CASH INVESTING AND FINANCING ACTIVITIES - See Note 1 of the Consolidated
Financial Statements for additional information.
See Notes to Consolidated Financial Statements.
II-11
THE DAYTON POWER AND LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------- -----------------------------------------
At December 31,
$ in millions 1999 1998
- --------------------------------------------------------------------------- -------------------- --------------------
ASSETS
PROPERTY
Electric property...................................................... $3,424.1 $3,372.1
Gas property........................................................... 332.9 324.6
Other property......................................................... 16.6 17.8
---- ----
Total property................................................ 3,773.6 3,714.5
Accumulated depreciation and amortization.............................. (1,602.6) (1,484.9)
------- -------
Net property.................................................. 2,171.0 2,229.6
------- -------
CURRENT ASSETS
Cash and temporary cash investments.................................... 95.5 1.9
Accounts receivable, less provision for uncollectible
accounts of $4.3 and $4.7 respectively............................ 206.6 219.2
Inventories, at average cost........................................... 92.9 112.2
Taxes applicable to subsequent years................................... 94.6 93.4
Other.................................................................. 66.9 49.2
---- ----
Total current assets.............................................. 556.5 475.9
----- -----
OTHER ASSETS
Financial assets....................................................... 0.5 232.7
Income taxes recoverable through future
revenues (Notes 1 and 4).......................................... 168.5 195.5
Other regulatory assets (Note 4)....................................... 53.3 82.2
Other assets........................................................... 203.7 196.5
----- -----
Total other assets................................................ 426.0 706.9
----- -----
TOTAL ASSETS........................................................... $3,153.5 $3,412.4
======= =======
See Notes to Consolidated Financial Statements.
II-12
THE DAYTON POWER AND LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(continued)
- --------------------------------------------------------------------------- -----------------------------------------
At December 31,
$ in millions 1999 1998
- --------------------------------------------------------------------------- -------------------- --------------------
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common shareholder's equity
Common stock...................................................... $0.4 $0.4
Other paid-in capital............................................. 769.7 788.2
Accumulated other comprehensive income............................ 13.6 33.6
Earnings reinvested in the business............................... 513.9 450.8
----- -----
Total common shareholder's equity............................. 1,297.6 1,273.0
Preferred stock (Note 10).............................................. 22.9 22.9
Long-term debt (Note 9)................................................ 661.2 885.6
----- -----
Total capitalization.......................................... 1,981.7 2,181.5
------- -------
CURRENT LIABILITIES
Short-term debt (Note 8)............................................... 123.1 181.2
Accounts payable....................................................... 126.2 106.6
Accrued taxes.......................................................... 164.2 160.9
Accrued interest....................................................... 19.7 20.7
Other.................................................................. 60.9 50.2
---- ----
Total current liabilities..................................... 494.1 519.6
----- -----
DEFERRED CREDITS AND OTHER
Deferred taxes (Note 5)................................................ 453.9 488.2
Unamortized investment tax credit...................................... 66.3 69.3
Deferred compensation.................................................. 97.2 89.2
Other.................................................................. 60.3 64.6
---- ----
Total deferred credits and other.............................. 677.7 711.3
----- -----
TOTAL CAPITALIZATION AND LIABILITIES................................... $3,153.5 $3,412.4
======= =======
See Notes to Consolidated Financial Statements.
II-13
THE DAYTON POWER AND LIGHT COMPANY
CONSOLIDATED STATEMENT OF SHAREHOLDER'S EQUITY
Common Stock (a) Accumulated Earnings
------------------------ Other Reinvested
Outstanding Other Paid-In Comprehensive in the
$ in millions Shares Amount Capital Income Business Total
- -------------------------------------- ------------- ---------- ----------------- ---------------- ------------- ----------
1997:
Beginning Balance............. 41,172,173 $0.4 $738.9 $9.6 $468.6 $1,217.5
Comprehensive income:
Net income.................. 172.0
Unrealized gains, net of
reclassification adjustments,
after tax (b)............ 10.7
Total comprehensive income.... 182.7
Common stock dividends........ (118.5) (118.5)
Preferred stock dividends..... (0.9) (0.9)
Other......................... 0.2 (0.2) -
------------- ---------- ----------------- ---------------- ------------- ----------
Ending balance................ 41,172,173 $0.4 $739.1 $20.3 $521.0 $1,280.8
1998:
Comprehensive income:
Net income.................. 169.5
Unrealized gains, net of
reclassification adjustments,
after tax (b)............ 13.3
Total comprehensive income.... 182.8
Common stock dividends........ (238.8) (238.8)
Preferred stock dividends..... (0.9) (0.9)
Parent company capital
contribution................ 49.0 49.0
Other......................... 0.1 - 0.1
------------- ---------- ----------------- ---------------- ------------- ----------
Ending balance................ 41,172,173 $0.4 $788.2 $33.6 $450.8 $1,273.0
1999:
Comprehensive income:
Net income.................. 192.5
Unrealized gains, net of
reclassification adjustments,
after tax (b)............ 4.1
Total comprehensive income.... 196.6
Common stock dividends........ (129.7) (129.7)
Dividend-in-kind (c) (Note 1). (24.1) (24.1)
Dividend-in-kind (Note 1)..... (263.6) 1.4 (262.2)
Preferred stock dividends..... (0.9) (0.9)
Parent company capital
contribution................ 245.0 245.0
Other......................... 0.1 (0.2) (0.1)
------------- ---------- ----------------- ---------------- ------------- ----------
Ending balance................ 41,172,173 $0.4 $769.7 $13.6 $513.9 $1,297.6
============= ========== ================= ================ ============= ==========
(a) 50,000,000 shares authorized.
(b) Net of taxes of $5.8 million, $7.2 million and $2.2 million in 1997, 1998
and 1999 respectively.
(c) Net of taxes of $13.1 million in 1999.
See Notes to Consolidated Financial Statements.
II-14
THE DAYTON POWER AND LIGHT COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is a wholly-owned subsidiary of DPL Inc. The accounts of the Company
and its wholly-owned subsidiaries are included in the accompanying consolidated
financial statements. In 1999, the Company transferred its ownership interests
in the assets and liabilities of MacGregor Park, Inc. and DP&L Community Urban
Redevelopment Corporation to DPL Inc. and transferred its ownership interests in
the assets and liabilities of MVE, Inc. to Plaza Building Inc., which is another
wholly-owned subsidiary of DPL Inc., via dividends-in-kind and a repayment of
inter-company debt. Total assets and liabilities transferred totaled $470.1
million and $19.0 million, respectively.
These statements are presented in accordance with generally accepted accounting
principles in the United States, which require management to make estimates and
assumptions related to future events. Reclassifications have been made in
certain prior years' amounts to conform to the current reporting presentation.
The consolidated financial statements principally reflect the results of
operations and financial condition of the Company. DPL Inc. and its other wholly
owned subsidiaries provide certain administrative services to the Company. These
costs were $12.5 million in 1999, $20.1 million in 1998 and $53.5 million in
1997. The primary expense provided by the subsidiaries is insurance. The expense
is either specifically identified with the Company or allocated based upon the
relationships of payroll, revenue and/or property. Management considers the
allocation methods used as reasonable and that the expenses approximate what
would have been incurred on a stand-alone basis.
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. Beginning in February 2000, the
Company's Electric Fuel Component ("EFC") will be fixed at 1.30 CENTS for
the remainder of 2000. As competition begins on January 1, 2001 the EFC will
become part of the Standard Offer Generation Rate. 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 $76.2 million in 1999 and $99.5
million in 1998.
PROPERTY, MAINTENANCE AND DEPRECIATION
Property is shown at its original cost. Cost includes direct labor and material
and allocable overhead costs.
II-15
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 average
rate of 3.6%.
INCOME TAXES
Deferred income taxes are provided for all temporary 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. Investment tax credits,
previously deferred, are being amortized over the lives of the related
properties.
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.
FINANCIAL INSTRUMENTS
The Company accounts for its investments in debt and equity securities by
classifying the securities into different categories (held-to-maturity and
available-for-sale); available-for-sale securities are carried at fair market
value and unrealized gains and losses, net of deferred income taxes, are
presented as a separate component of shareholders' equity for those investments.
Investments classified as held-to-maturity are carried at amortized cost. The
value of equity security investments and fixed maturity investments is based
upon market quotations or investment cost which is believed to approximate
market. The cost basis for equity security and fixed maturity investments is
average cost and amortized cost, respectively.
2. RECENT ACCOUNTING STANDARD
In 1998, the Financial Accounting Standards Board ("FASB") issued Statement No.
133, "Accounting for Derivative Instruments and Hedging Activities," which will
be effective in 2001. This standard requires changes in the fair value of
derivative financial instruments to be recognized on the balance sheet and
recognized in net income or other comprehensive income depending upon the nature
of the derivative. Adoption of this statement is not expected to have a
significant effect on the Company's financial position or results of operations.
II-16
3. SUBSEQUENT EVENT
On February 2, 2000, DPL Inc. entered into a series of recapitalization
transactions including the issuance to KKR, an investment company, of $550
million of a combination of voting preferred and trust preferred securities and
warrants. The trust preferred securities sold to KKR have an aggregate face
amount of $550 million, were issued at an initial discounted aggregate price of
$500 million, have a maturity of 30 years (subject to acceleration to six months
after the exercise of warrants) and pay distributions at a rate of 8.5% of the
aggregate face amount per year. The 6.8 million shares of mandatory redeemable
voting preferred securities, par value of $0.01 per share, were issued at an
aggregate purchase price of $68,000 and carry voting rights for up to 4.9% of
DPL Inc.'s total voting rights and the nomination of one Board seat. The 31.6
million warrants, representing approximately 19.9% of DPL Inc.'s shares
currently outstanding, have a term of 12 years, an exercise price of $21 per
share and were sold for an aggregate purchase price of $50 million. The $550
million KKR investment closed on March 13, 2000. DPL Inc. intends to recognize
the trust preferred securities original issue discount and issuance costs in
2000.
DPL Inc. intends to use the proceeds from this recapitalization, combined with
$425 million of new debt capital, to continue its planned generation strategy,
retire short-term debt and repurchase up to 31.6 million common shares. The $425
million issuance of 8.25% Senior Notes due 2007 closed on February 24, 2000.
These transactions resulted in an increase in the financial leverage of DPL Inc.
in its capital structure.
On February 4, 2000, DPL Inc. initiated an Offer to Purchase for Cash up to 25
million common shares, or approximately 16% of outstanding shares, at a price of
$20-$23, via a modified Dutch Auction process. This tender expired on March 3,
2000. Under the Offer, approximately 28 million shares, or 18% of outstanding
shares, were properly tendered and not withdrawn at prices at or below $23 per
share. Therefore, the buyback was prorated with a final proration factor of
91.3%. DPL accepted for purchase 25 million shares, or 16% of its common stock,
at a price of $23 per share. DPL Inc. currently intends to purchase an
additional 6.6 million shares after this offer is completed. The method, timing
and financing of such purchases have not yet been decided.
4. REGULATORY MATTERS
The Company applies the provisions of the FASB Statement No. 71, "Accounting for
the Effects of Certain Types of Regulation." This accounting standard provides
for the deferral of costs authorized for future recovery by regulators. Based on
existing regulatory authorization, regulatory assets on the Consolidated Balance
Sheet include:
II-17
At December 31,
1999 1998
---- ----
--millions--
Income taxes recoverable through future revenues $168.5 $195.5
Deferred interest (a) 46.9 49.7
DSM (b) 13.2 19.6
Phase-in (c) (6.8) 12.9
------ ------
Total $221.8 $277.7
====== ======
During 1999, legislation was enacted in Ohio which will restructure the electric
utility industry ("the Legislation"). Beginning in 2001, electric generation,
aggregation, power marketing and power brokerage services supplied to Ohio
retail customers will not be subject to regulation by the PUCO. As required by
the Legislation, the Company filed a transition plan with the PUCO in 1999,
which included an application for the Company to receive transition revenues to
recover regulatory assets and other potentially stranded costs. The PUCO is
required to determine the total allowable amount of the Company's transition
costs, based on certain criteria, and the recovery period which may begin no
earlier than January 2001 and end no later than 2010. Any regulatory assets
which are not recoverable will be charged to expense.
(a) Interest charges related to the William H. Zimmer Generating Station
which were previously deferred pursuant to PUCO approval are being amortized at
$2.8 million per year over the projected life of the asset.
(b) Demand-side management ("DSM") costs (including carrying charges) from
the Company's cost-effective programs are deferred and are being recovered at
approximately $9 million per year. A 1992 PUCO-approved agreement for the DSM
programs, as updated in 1995, provides for accelerated recovery of DSM costs
and, thereafter, production plant costs to the extent that the Company's return
on equity exceeds a baseline 13% (subject to upward adjustment). If the return
exceeded the baseline return by one to two percent, one-half of the excess was
used to accelerate recovery of these costs. If the return was greater than two
percent over the baseline, the entire excess was used for such purpose. In 1998,
amortization of regulatory assets included an additional $10.4 million of
accelerated cost recovery. In 1999, the Legislation removed the return on equity
cap.
(c) Amounts deferred during a 1992-1994 electric rate increase phase-in
(including carrying charges) were recovered in revenues through 1999. The 1992
PUCO-approved agreement for the phase-in plan provided that after the end of the
deferral period, the Company would maintain a balance sheet reserve account
which shall operate to reduce the otherwise applicable jurisdictional production
plant valuation subject to recovery in rates.
II-18
5. INCOME TAXES
For the years ended December 31,
$ in millions 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
COMPUTATION OF TAX EXPENSE
Federal income tax (a)............................................... $109.7 $98.9 $95.0
Increases (decreases) in tax from --
Regulatory assets............................................... 4.4 4.0 3.6
Depreciation.................................................... 13.1 12.5 11.4
Investment tax credit amortized................................. (3.0) (3.0) (3.0)
Other, net...................................................... (3.1) 0.6 (7.4)
------ ------ ------
Total tax expense........................................... $121.1 $113.0 $99.6
====== ====== =====
COMPONENTS OF TAX EXPENSE
Taxes currently payable.............................................. $107.2 $129.2 $102.4
Deferred taxes--
Regulatory assets............................................... (5.8) (8.3) (4.0)
Liberalized depreciation and amortization....................... 5.8 5.9 5.3
Fuel and gas costs.............................................. 9.2 (5.8) 5.5
Other........................................................... 7.7 (5.0) (6.6)
Deferred investment tax credit, net.................................. (3.0) (3.0) (3.0)
------ ------ ------
Total tax expense........................................... $121.1 $113.0 $99.6
====== ====== =====
(a) The statutory rate of 35% was applied to pre-tax income.
COMPONENTS OF DEFERRED TAX ASSETS AND LIABILITIES
At December 31,
$ in millions 1999 1998
- --------------------------------------------------------------------------------------------
NON-CURRENT LIABILITIES
Depreciation/property basis....................... $(428.0) $(438.2)
Income taxes recoverable.......................... (59.0) (68.4)
Regulatory assets................................. (16.3) (28.0)
Investment tax credit............................. 23.2 24.2
Other............................................. 26.2 22.2
------- -------
Net non-current liability.................... $(453.9) $(488.2)
======= =======
Net Current Asset (Liability)..................... $(9.9) $3.7
======= =======
II-19
6. PENSIONS AND POSTRETIREMENT BENEFITS
PENSIONS
Substantially all Company employees participate in pension plans paid for by the
Company. Employee benefits are based on their years of service, age,
compensation and year of retirement. The plans are funded in amounts actuarially
determined to provide for these benefits.
The interest rate for discounting the obligation and expense was 6.25% and the
expected rate of return was 7.5%. Increases in compensation levels approximating
5.0% were used for all years.
The following table sets forth the components of pension expense (portions of
which were capitalized):
$ in millions 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
EXPENSE FOR YEAR
Service cost........................................................... $5.9 $5.9 $6.3
Interest cost.......................................................... 16.2 15.9 15.2
Expected return on plan assets......................................... (25.3) (23.3) (20.5)
Amortization of unrecognized:
Actuarial (gain) loss............................................. (0.5) 1.2 -
Prior service cost................................................ 2.1 2.1 2.1
Transition obligation............................................. (4.3) (4.2) (4.2)
----- ----- -----
Net pension cost....................................................... $(5.9) $(2.4) $(1.1)
===== ===== =====
The following tables set forth the plans' obligations, assets and amounts
recorded in Other assets on the Consolidated Balance sheet at December 31:
$ in millions 1999 1998
- -------------------------------------------------------------------------------------------------------------
CHANGE IN PROJECTED BENEFIT OBLIGATION
Benefit obligation, January 1............................................. $269.2 $259.1
Service cost.............................................................. 5.9 5.9
Interest cost............................................................. 16.2 15.9
Actuarial (gain) loss..................................................... (3.8) 0.8
Benefits paid............................................................. (14.7) (12.5)
------ ------
Benefit obligation, December 31........................................... 272.8 269.2
------ ------
CHANGE IN PLAN ASSETS
Fair value of plan assets, January 1...................................... 358.9 330.2
Actual return on plan assets.............................................. 77.0 41.2
Benefits paid............................................................. (14.6) (12.5)
------ ------
Fair value of plan assets, Decemb