<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[Mark one]
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1999
--------------
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number 1-1405
Delmarva Power & Light Company
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Delaware and Virginia 51-0084283
------------------------- ------------------
(States of incorporation) (I.R.S. Employer
Identification No.)
800 King Street, P.O. Box 231, Wilmington, Delaware 19899
- --------------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 302-429-3114
------------
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 |_|
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
All 1,000 issued and outstanding shares of Delmarva Power & Light Company common
stock, $2.25 per share par value, are owned by Conectiv
<PAGE>
DELMARVA POWER & LIGHT COMPANY
Table of Contents
-----------------
Page No.
--------
Part I. Financial Information:
Consolidated Statements of Income for the three
months ended March 31, 1999 and 1998........................... 1
Consolidated Balance Sheets as of March 31, 1999
and December 31, 1998.......................................... 2-3
Consolidated Statements of Cash Flows for the
three months ended March 31, 1999 and 1998..................... 4
Notes to Consolidated Financial Statements..................... 5-9
Management's Discussion and Analysis of Financial
Condition and Results of Operations............................ 10-17
Part II. Other Information and Signature................................. 18-19
i
<PAGE>
Part I. FINANCIAL INFORMATION
DELMARVA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
------------------------
1999 1998
--------- ---------
<S> <C> <C>
OPERATING REVENUES
Electric $ 323,211 $ 278,376
Gas 290,991 115,743
Other services 5,505 21,991
--------- ---------
619,707 416,110
--------- ---------
OPERATING EXPENSES
Electric fuel and purchased energy 154,235 116,876
Gas purchased 271,613 98,628
Purchased electric capacity 9,473 8,812
Other services' cost of sales 5,747 15,871
Employee separation and other
merger-related costs -- 40,338
Operation and maintenance 60,302 79,322
Depreciation 32,802 33,731
Taxes other than income taxes 8,325 9,443
--------- ---------
542,497 403,021
--------- ---------
OPERATING INCOME 77,210 13,089
--------- ---------
OTHER INCOME
Allowance for equity funds used
during construction 590 307
Other income 2,722 858
--------- ---------
3,312 1,165
--------- ---------
INTEREST EXPENSE
Interest charges 20,520 20,818
Allowance for borrowed funds used during
construction and capitalized interest (492) (722)
--------- ---------
20,028 20,096
--------- ---------
DIVIDENDS ON PREFERRED SECURITIES
OF A SUBSIDIARY TRUST 1,422 1,422
--------- ---------
INCOME (LOSS) BEFORE INCOME TAXES 59,072 (7,264)
INCOME TAXES 23,458 (2,408)
--------- ---------
NET INCOME (LOSS) 35,614 (4,856)
DIVIDENDS ON PREFERRED STOCK 1,073 1,086
--------- ---------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 34,541 $ (5,942)
========= =========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
-1-
<PAGE>
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
---------- ------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 8,715 $ 1,761
Accounts receivable 297,898 273,531
Accounts receivable from
associated companies 2,262 2,325
Intercompany loan receivable 800 --
Inventories, at average cost
Fuel (coal, oil and gas) 26,561 44,212
Materials and supplies 39,443 39,323
Prepayments 7,684 10,735
Deferred income taxes, net 13,870 13,061
---------- ----------
397,233 384,948
---------- ----------
Investments
Funds held by trustee 61,491 60,208
Notes receivable 254 --
Other investments 1,103 1,103
---------- ----------
62,848 61,311
---------- ----------
Property, Plant and Equipment
Electric utility plant 3,065,830 3,049,099
Gas utility plant 251,670 249,383
Common utility plant 159,669 158,109
---------- ----------
3,477,169 3,456,591
Less: Accumulated depreciation 1,523,330 1,492,182
---------- ----------
Net utility plant in service 1,953,839 1,964,409
Utility construction work-in-progress 139,978 138,496
Leased nuclear fuel, at amortized cost 26,087 28,325
Nonutility property, net 3,825 4,560
Goodwill, net 71,422 71,914
---------- ----------
2,195,151 2,207,704
---------- ----------
Deferred Charges and Other Assets
Prepaid employee benefits costs 102,618 94,354
Unamortized debt expense 12,031 12,140
Deferred debt refinancing costs 15,549 16,180
Deferred recoverable income taxes 82,117 82,211
Other 44,376 46,003
---------- ----------
256,691 250,888
---------- ----------
Total Assets $2,911,923 $2,904,851
========== ==========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
-2-
<PAGE>
DELMARVA POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
---------- ------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Current Liabilities
Short-term debt $ -- $ 21,700
Long-term debt due within one year 31,287 31,287
Variable rate demand bonds 71,500 71,500
Accounts payable 153,910 177,859
Taxes accrued 36,886 16,257
Interest accrued 24,255 20,604
Dividends payable 23,865 23,615
Current capital lease obligation 12,484 12,481
Deferred energy costs 15,651 413
Accrued employee separation and
other merger-related costs 701 2,509
Other 22,086 27,586
---------- ----------
392,625 405,811
---------- ----------
Deferred Credits and Other Liabilities
Deferred income taxes, net 466,972 461,800
Deferred investment tax credits 36,743 37,382
Long-term capital lease obligation 14,742 17,003
Other 26,795 19,747
---------- ----------
545,252 535,932
---------- ----------
Capitalization
Common stock, $2.25 par value; shares
authorized: 1,000,000 ; shares
outstanding: 1,000 2 2
Additional paid-in capital 528,893 528,893
Retained earnings 333,491 322,599
---------- ----------
Total common stockholder's equity 862,386 851,494
Cumulative preferred stock 89,703 89,703
DPL obligated mandatorily redeemable
preferred securities of subsidiary
trust holding solely DPL debentures 70,000 70,000
Long-term debt 951,957 951,911
---------- ----------
1,974,046 1,963,108
---------- ----------
Total Capitalization and Liabilities $2,911,923 $2,904,851
========== ==========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
-3-
<PAGE>
DELMARVA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
-----------------------
1999 1998
-------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 35,614 ($ 4,856)
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization 35,602 35,500
Allowance for equity funds used
during construction (590) (307)
Deferred income taxes, net 4,457 (7,241)
Investment tax credit adjustments, net (639) (640)
Net change in:
Accounts receivable (23,572) (2,519)
Inventories 17,531 9,150
Accounts payable (23,949) (1,349)
Other current assets and
liabilities(1) 34,255 53,291
Other, net 2,648 (1,414)
-------- --------
Net cash provided by operating activities 81,357 79,615
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loan receivable (800) --
Acquisition of businesses, net of
cash acquired -- (8,970)
Capital expenditures (23,773) (21,253)
Net cash of nonutility subsidiaries
transferred to Conectiv -- (18,138)
Deposits to nuclear decommissioning
trust funds (1,068) (1,059)
Other, net 279 (387)
-------- --------
Net cash used by investing activities (25,362) (49,807)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (23,649) (23,652)
Preferred dividends paid (823) (525)
Issuances: Long-term debt -- 33,000
Common stock -- 63
Redemptions: Long-term debt -- (74)
Common stock -- (1,983)
Principal portion of capital
lease payments (2,800) (1,740)
Net change in short-term debt (21,700) (46,384)
Cost of issuances and refinancings (69) (11)
-------- --------
Net cash used by financing activities (49,041) (41,306)
-------- --------
Net change in cash and cash equivalents 6,954 (11,498)
Cash and cash equivalents at
beginning of period 1,761 35,339
-------- --------
Cash and cash equivalents at end of period $ 8,715 $ 23,841
======== ========
(1) Other than debt and deferred income taxes classified as current.
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
-4-
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. Financial Statement Presentation
The consolidated financial statements include the accounts of Delmarva Power &
Light Company (DPL) and its wholly-owned subsidiaries. On March 1, 1998, DPL
transferred its former nonutility subsidiaries to Conectiv in conjunction with
the Merger discussed in Note 4 to DPL's 1998 Consolidated Financial Statements
included in DPL's 1998 Report on Form 10-K. As a result of the transfer, the
Consolidated Statement of Income for the three months ended March 31, 1999 does
not include any operating results for the former DPL nonutility subsidiaries and
the Consolidated Statement of Income for the three months ended March 31, 1998
includes the former nonutility subsidiaries' operating results for the two
months ended February 28, 1998. As of March 1, 1998, DPL's only significant
remaining wholly-owned subsidiary was Delmarva Power Financing I.
Certain reclassifications, not affecting net income, have been made to conform
amounts previously reported to the current presentation. The financial
statements reflect all adjustments necessary in the opinion of DPL's management
for a fair presentation of interim results. In accordance with regulations of
the Securities and Exchange Commission, disclosures which would substantially
duplicate the disclosures in DPL's 1998 Report on Form 10-K have been omitted.
Accordingly, DPL's consolidated condensed interim financial statements contained
herein should be read in conjunction with DPL's 1998 Report on Form 10-K and
Part II of this Report on Form 10-Q for additional relevant information.
2. Employee Separation and Other Merger-Related Costs
In the first quarter of 1998, enhanced retirement offers and other employee
separation programs were utilized to reduce DPL's workforce. The costs for
separated DPL employees and other Merger related costs expensed in the first
quarter of 1998 were $40.3 million before taxes, reducing net income by $24.4
million. The $40.3 million charge to expense was net of a $32.5 million gain
from curtailments and settlements of pension and other postretirement benefits,
based on actual settlements through March 31, 1998.
3. Rate Matters
The following information updates the disclosures previously reported in Note 6,
"Rate Matters," to DPL's Consolidated 1998 Financial Statements included in
DPL's 1998 Report on Form 10-K.
Asset Impairments and Charges to Earnings
Management has made a preliminary estimate of the amount of stranded costs not
expected to be recovered through regulated electricity delivery rates after the
restructuring of the electric utility industry in the states in which DPL
operates. The Delaware and Maryland public utility regulatory commissions are
expected to issue restructuring orders which specify the amount and timing of
stranded cost recovery by August 31, 1999, and October 1, 1999, respectively.
After the orders are received, the financial impact of the restructurings,
including charges to earnings, will be finalized and recorded. When the
restructuring orders become effective, the electricity supply business of DPL
will no longer be subject to the requirements of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." The discussion below describes the primary immediate expected
effect on the results of operations of discontinuing the application of SFAS No.
71 to the electricity supply business.
-5-
<PAGE>
To estimate the impairment of electric generating plants of DPL in accordance
with generally accepted accounting principles (GAAP), the book value of each
generating plant is first compared to the estimated future net operating cash
flows of each generating plant. Any electric generating plant with undiscounted
future net cash flows less than book value is considered impaired, and the
plant's net future cash flows are discounted. The amount by which the book value
of the impaired electric generating plants exceeds their discounted cash flows
(or other estimate of fair value) is the estimated impairment amount.
DPL has purchased power contracts expected to be uneconomic when customer choice
begins, and the stranded cost amount is estimated to be the net present value of
the contracts' costs less the forecasted revenues from sales of the related
purchased power.
The total amount that could be charged to earnings, on a consolidated basis,
includes (a) the impairment amount for the electric generating plants of DPL,
(b) the stranded cost amount for DPL's purchased power contracts, and (c)
regulatory assets of DPL related to its electric generation business. The charge
to earnings is reduced by the estimated cost recovery through regulated
electricity delivery rates. Based on this methodology (giving effect to
estimated cost recoveries), management currently estimates future charges to
earnings, after taxes, as a result of electric utility industry restructuring
could be approximately $300 million to $425 million.
Expected Sales of Electric Generating Plants
Management also expects to sell some or all of the electric generating plants of
DPL. After electric generating plants that are impaired as a result of electric
utility industry restructuring are written down to fair value, any sales of the
impaired electric generating plants are not expected to result in significant
gains or losses. Some of the electric generating plants which are not impaired
may be sold at a gain. Under GAAP, the write-down of impaired assets is not
reduced by expected future gains on sales of assets which are not impaired by
electric utility industry restructuring; the gain on the sale of an asset is
recognized when the sale occurs.
DPL's agreements with some of the participants in restructuring proceedings
expected to be conducted by the Delaware Public Service Commission (DPSC) and
with some of the participants in the proceedings being conducted by the Maryland
Public Service Commission (MPSC) provide that electric rates will not be changed
in the event DPL sells or transfers assets. Accordingly, subject to DPSC and
MPSC approval of these agreements, the Delaware and Maryland portions of any
gains, or losses, realized on the sale of DPL electric generating plants would
affect future earnings. There can be no assurances, however, that DPL will elect
or be able to sell any such electric generating plants, or that any gains will
be realized from such sales of electric generating plants.
Delaware Electric Utility Restructuring Legislation
As previously reported, the Delaware General Assembly passed the Electric
Utility Restructuring Act of 1999 (the Delaware Act) on March 25, 1999. On March
31, 1999, the Governor of Delaware signed the Delaware Act. Assuming that a 7.5%
rate reduction, as required by the Delaware Act, had been effective as of
January 1, 1998, management estimates that the impact on revenue of DPL would
have been to decrease revenue during the fiscal year ended December 31, 1998 by
approximately $17 million. The Delaware Act makes DPL the provider of default
service to customers who do not choose an alternative supplier for a period of 3
or 4 years for non-residential and residential customers, respectively.
Thereafter, the DPSC may conduct a bidding process to select the default
supplier(s) for such customers. The DPSC also has the authority under the
Delaware Act to order DPL to divest its generating assets, as a last resort, to
remedy any adverse effects of electricity supply market power. The DPSC also is
authorized to establish licensing standards for electricity suppliers. Unless
DPL asks the DPSC to make these functions competitive earlier, and the DPSC so
orders, metering functions will be performed by
-6-
<PAGE>
DPL for 3 or 4 years after they may choose their electricity suppliers, for
non-residential customers and residential customers, respectively.
Among other matters, unbundled rates to be charged by DPL during the "rate
freeze" periods prescribed by the Delaware Act have been agreed upon by a number
of the participants in the restructuring proceeding contemplated by the Delaware
Act. Included within the agreement on unbundled rates, which is subject to DPSC
approval, DPL would recover $16 million (Delaware retail basis) of stranded
costs, and electric rates would not be changed in the event DPL sells or
transfers generating assets.
Maryland Electric Utility Restructuring Legislation
On April 2, 1999, the Maryland General Assembly passed the Electric Utility
Industry Restructuring Act of 1999 (the Maryland Act). On April 8, 1999, the
Governor of Maryland signed the Maryland Act. The major elements of the Maryland
Act include the following:
(A) Phase-in of retail choice beginning in July 2000, with full choice for all
customers by July 2003;
(B) Rate reductions of 3% to 7.5% for residential customers, with rates then
held constant for four years;
(C) The deregulation of generating assets sold to a non-affiliate or transferred
to an affiliate prior to January 1, 2001;
(D) Recovery of stranded costs and other costs associated with the transition to
retail choice through a method to be determined by the MPSC;
(E) Imposition by the MPSC of an environmental surcharge on each kilowatt-hour
distributed in Maryland.
(F) The creation of a statewide fund for low-income assistance.
On May 5, 1999, DPL filed a proposed settlement with the MPSC in DPL's pending
restructuring proceeding. The proposed settlement is with some parties,
including the MPSC Staff and the Office of People's Counsel, but not all parties
to the proceeding. Included in the proposed settlement are the following
provisions: (i) effective July 1, 2000, all of DPL's Maryland-retail customers
will be eligible to select an alternative electricity supplier; (ii) for a
period of at least 3 years thereafter, DPL will remain the supplier of "standard
offer service" for customers who do not select an alternative electricity
supplier; (iii) agreed-upon unbundled rates (including nuclear decommissioning
costs and funding for low income energy assistance programs at an estimated
level of between $2 and $3 million per year); (iv) the deregulation of DPL's
generating facilities, such that electric rates would not be changed in the
event DPL sells or transfers generating assets (v) authorization to transfer DPL
generating assets to one or more affiliates at net book value; (vi) the recovery
of an estimated $8 million (Maryland retail basis) in stranded costs from
non-residential customers; (vii) a 7.5% reduction in residential rates effective
July 1, 2000 (representing a revenue reduction of approximately $12.5 million;
assuming fiscal year 1998 sales and revenues) and (viii) effective July 1, 2000,
"rate freezes" for 4 years for residential customers and 3 years for
non-residential customers, subject to certain adjustments. In addition, under
the proposed settlement, effective July 1, 2000, DPL customers with loads in
excess of 300 kilowatts (kW) may elect to have meters installed and read by an
alternative supplier. Prior to that date, another MPSC proceeding will be
initiated to determine the level of and recovery mechanism for any DPL stranded
metering costs. Other DPL customers will be eligible for competitive metering on
April 1, 2002 as set forth in the Maryland Act.
The MPSC is expected to issue an order with respect to the proposed settlement
by October 1, 1999.
-7-
<PAGE>
Virginia Electric Utility Industry Restructuring Legislation
As previously reported, electric utility restructuring legislation was
introduced in the Virginia General Assembly on January 21, 1999. The Virginia
General Assembly passed the Virginia Electric Utility Restructuring Act (the
Virginia Act) on March 25, 1999. On March 29, 1999, the Governor of Virginia
signed the Virginia Act.
4. Contingencies
Environmental Matters
DPL is subject to regulation with respect to the environmental effect of its
operations, including air and water quality control, solid and hazardous waste
disposal, and limitation on land use by various federal, regional, state, and
local authorities. Costs may be incurred to clean up facilities found to be
contaminated due to past disposal practices. Federal and state statutes
authorize governmental agencies to compel responsible parties to clean up
certain abandoned or uncontrolled hazardous waste sites. DPL is currently a
potentially responsible party at three federal superfund sites and is alleged to
be a third-party contributor at three other federal superfund sites. DPL also
has two former coal gasification sites in Delaware and one former coal
gasification site in Maryland, each of which is a state superfund site. Also, in
August 1998, the Delaware Department of Natural Resources and Environmental
Control notified DPL that it is a potentially responsible party liable for
clean-up of the Wilmington Public Works Yard as a former owner of the property.
There is $2 million included in DPL's current liabilities as of December 31,
1998, and March 31, 1999, for clean-up and other potential costs related to
these sites. DPL does not expect such future costs to have a material effect on
DPL's financial position or results of operations.
Nuclear Insurance
In conjunction with DPL's ownership interests in the Peach Bottom Atomic Power
Station (Peach Bottom) and Salem Nuclear Generating Station (Salem), DPL could
be assessed for a portion of any third-party claims associated with an incident
at any commercial nuclear power plant in the United States. Under the provisions
of the Price Anderson Act, if third-party claims relating to such an incident
exceed $200 million (the amount of primary insurance), DPL could be assessed up
to $26.3 million on an aggregate basis for such third-party claims. In addition,
Congress could impose a revenue-raising measure on the nuclear industry to pay
such claims.
The co-owners of Peach Bottom and Salem maintain property insurance coverage of
approximately $2.8 billion for each unit for loss or damage to the units,
including coverage for decontamination expense and premature decommissioning. In
addition, DPL is a member of an industry mutual insurance company, which
provides replacement power cost coverage in the event of a major accidental
outage at a nuclear power plant. Under these coverages, DPL is subject to
potential retrospective loss experience assessments of up to $4.0 million on an
aggregate basis.
-8-
<PAGE>
5. Supplemental Cash Flow Information
<TABLE>
<CAPTION>
Three Months Ended
March 31,
------------------
1999 1998
------- -------
<S> <C> <C>
Cash paid for
(Dollars in thousands)
Interest, net of amounts capitalized $15,522 $15,247
Income taxes, net of refunds $ 83 $ 774
</TABLE>
6. Segments
Conectiv's organizational structure and management reporting information is
aligned with Conectiv's business segments, irrespective of the subsidiary, or
subsidiaries, through which a business is conducted. Businesses are managed
based on lines of business, not legal entity. Business segment information is
not produced, or reported, on a subsidiary by subsidiary basis. Thus, as a
Conectiv subsidiary, no business segment information (as defined by SFAS No.
131, "Disclosures about Segments of an Enterprise and Related Information") is
available for DPL on a stand-alone basis.
-9-
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Earnings Summary
DPL's consolidated operating results for the first quarter of 1998 include
operating results for the two months ended February 28, 1998 for DPL's
nonutility businesses that were transferred to Conectiv on March 1, 1998. The
first quarter of 1998 includes $19.5 million of revenues and a net loss of $3.5
million for the two months of operations of DPL's former nonutility
subsidiaries.
DPL had earnings applicable to common stock of $34.5 million for the first
quarter of 1999, compared to a loss of $5.9 million in the first quarter of
1998. First quarter 1998 earnings include an after-tax charge of $24.4 million
for DPL employee separation costs and other Merger-related costs. Excluding this
$24.4 million earnings charge and the $3.5 million operating loss of the
nonutility subsidiaries, earnings applicable to common stock were $22.0 million
for the first quarter of 1998, compared to $34.5 million for the first quarter
of 1999. The $12.5 million earnings increase (after reflecting the
aforementioned adjustments to the first quarter of 1998) was primarily
attributed to (a) higher regulated retail electric and gas sales, which
increased mainly due to colder winter weather than last year, and (b) lower
utility operating and maintenance expenses, which decreased mainly due to
Merger-related employee separations.
Electric Utility Industry Restructuring
Effect on Revenues
As previously reported, provisions for customer rate reductions included in
electric utility industry restructuring legislation become effective when
customer choice begins this year in Delaware and next year in Maryland. Without
reflecting other factors, the initial reduction in DPL's annual electric
revenues due to the restructuring legislation rate reductions implemented in
1999 and 2000 is estimated to be up to $30 million in total. Management expects
to offset substantially all of the revenue reductions with, among other things,
a productivity improvement and cost reduction program. There can be no
assurances, however, that DPL will be able to achieve its productivity
improvement and cost reduction goals under the program, or that such
productivity improvements and cost reductions as are achieved, will be
sufficient to offset these estimated revenue reductions.
Asset Impairments and Charges to Earnings
Management has made a preliminary estimate of the amount of stranded costs not
expected to be recovered through regulated electricity delivery rates after the
restructuring of the electric utility industry in the states in which DPL
operates. The Delaware and Maryland public utility regulatory commissions are
expected to issue restructuring orders for DPL which specify the amount and
timing of stranded cost recovery by August 31, 1999, and October 1, 1999,
respectively. After the orders are received, the financial impact of the
restructurings, including charges to earnings, will be finalized and recorded.
When the restructuring orders become effective, the electricity supply business
of DPL will no longer be subject to the requirements of SFAS No. 71. The
discussion below describes the primary immediate expected effect on the results
of operations of discontinuing the application of SFAS No. 71 to the electricity
supply business.
To estimate the impairment of the electric generating plants of DPL in
accordance with GAAP, the book value of each generating plant is first compared
to the estimated future net operating cash flows of each generating plant. Any
electric generating plant with undiscounted future net cash flows less than book
value is considered impaired, and the plant's net future cash flows are
discounted. The amount by which
-10-
<PAGE>
the book value of the impaired electric generating plants exceeds their
discounted cash flows (or other estimate of fair value) is the estimated
impairment amount.
DPL has purchased power contracts expected to be uneconomic when customer choice
begins, and the stranded cost amount is estimated to be the net present value of
the contracts' costs less the forecasted revenues from sales of the related
purchased power.
The total amount that could be charged to earnings, on a consolidated basis,
includes (a) the impairment amount for the electric generating plants of DPL,
(b) the stranded cost amount for DPL's purchased power contracts, and (c)
regulatory assets of DPL related to its electric generation business. The charge
to earnings is reduced by the estimated cost recovery through regulated
electricity delivery rates. Based on this methodology (giving effect to
estimated cost recoveries), management currently estimates future charges to
earnings, after taxes, as a result of electric utility industry restructuring
could be approximately $300 million to $425 million.
Expected Sales of Electric Generating Plants
Management also expects to sell some or all of the electric generating plants of
DPL. After electric generating plants that are impaired as a result of electric
utility industry restructuring are written down to fair value, any sales of the
impaired electric generating plants are not expected to result in significant
gains or losses. Some of the electric generating plants which are not impaired
may be sold at a gain. Under GAAP, the write-down of impaired assets is not
reduced by expected future gains on sales of assets which are not impaired by
electric utility industry restructuring; the gain on the sale of an asset is
recognized when the sale occurs.
DPL's agreements with some of the participants in restructuring proceedings
expected to be conducted by the DPSC and with some of the participants in the
proceedings being conducted by the MPSC provide that electric rates will not be
changed in the event DPL sells or transfers assets. Accordingly, subject to DPSC
and MPSC approval of these agreements, the Delaware and Maryland portions of any
gains, or losses, realized on the sale of DPL electric generating plants would
affect future earnings. There can be no assurances, however, that DPL will elect
or be able to sell any such electric generating plants, or that any gains will
be realized from such sales of electric generating plants.
Delaware Electric Utility Industry Restructuring Legislation
As previously reported, the Delaware General Assembly passed the Electric
Utility Restructuring Act of 1999 (the Delaware Act) on March 25, 1999. On March
31, 1999, the Governor of Delaware signed the Delaware Act. Assuming that a 7.5%
rate reduction, as required by the Delaware Act, had been effective as of
January 1, 1998, management estimates that the impact on revenue of DPL would
have been to decrease revenue during the fiscal year ended December 31, 1998 by
approximately $17 million. The Delaware Act makes DPL the provider of default
service to customers who do not choose an alternative supplier for a period of 3
or 4 years for non-residential and residential customers, respectively.
Thereafter, the DPSC may conduct a bidding process to select the default
supplier(s) for such customers. The DPSC also has the authority under the
Delaware Act to order DPL to divest its generating assets, as a last resort, to
remedy any adverse effects of electricity supply market power. The DPSC also is
authorized to establish licensing standards for electricity suppliers. Unless
DPL asks the DPSC to make these functions competitive earlier, and the DPSC so
orders, metering functions will be performed by DPL for 3 or 4 years after they
may choose their electricity suppliers, for non-residential customers and
residential customers, respectively. Among other matters, unbundled rates to be
charged by DPL during the "rate freeze" periods prescribed by the Delaware Act
have been agreed upon by a number of the participants in the restructuring
proceeding contemplated by the Delaware Act. Included within the agreement on
unbundled rates, which is subject to DPSC approval, DPL would recover $16
million
-11-
<PAGE>
(Delaware retail basis) of stranded costs, and electric rates would not be
changed in the event DPL sells or transfers generating assets.
Maryland Electric Utility Industry Restructuring Legislation
On April 2, 1999, the Maryland General Assembly passed legislation to
restructure the electric utility industry (the Maryland Act). On April 8, 1999,
the Governor of Maryland signed the Maryland Act. The major elements of the
Maryland Act include the following:
(A) Phase-in of retail choice beginning in July 2000, with full choice for all
customers by July 2003;
(B) Rate reductions of 3% to 7.5% for residential customers, with rates then
held constant for four years;
(C) The deregulation of generating assets sold to a non-affiliate or transferred
to an affiliate prior to January 1, 2001;
(D) Recovery of stranded costs and other costs associated with the transition to
retail choice through a method to be determined by the MPSC;
(E) Imposition by the MPSC of an environmental surcharge on each kilowatt-hour
distributed in Maryland;
(F) The creation of a statewide fund for low-income assistance.
On May 5, 1999, DPL filed a proposed settlement with the MPSC in DPL's pending
restructuring proceeding. The proposed settlement is with some parties,
including the MPSC Staff and the Office of People's Counsel, but not all parties
to the proceeding. Included in the proposed settlement are the following
provisions: (i) effective July 1, 2000, all of DPL's Maryland-retail customers
will be eligible to select an alternative electricity supplier; (ii) for a
period of at least 3 years thereafter, DPL will remain the supplier of "standard
offer service" for customers who do not select an alternative electricity
supplier; (iii) agreed-upon unbundled rates (including nuclear decommissioning
costs and funding for low income energy assistance programs at an estimated
level of between $2 and $3 million per year); (iv) the deregulation of DPL's
generating facilities, such that electric rates would not be changed in the
event DPL sells or transfers generating assets (v) authorization to transfer DPL
generating assets to one or more affiliates at net book value; (vi) the recovery
of an estimated $8 million (Maryland retail basis) in stranded costs from
non-residential customers; (vii) a 7.5% reduction in residential rates effective
July 1, 2000 (representing a revenue reduction of approximately $12.5 million;
assuming fiscal year 1998 sales and revenue levels) and (viii) effective July 1,
2000, "rate freezes" for 4 years for residential customers and 3 years for
non-residential customers, subject to certain adjustments. In addition, under
the proposed settlement, effective July 1, 2000, DPL customers with loads in
excess of 300 kilowatts (kW) may elect to have meters installed and read by an
alternative supplier. Prior to that date, another MPSC proceeding will be
initiated to determine the level of and recovery mechanism for any DPL stranded
metering costs. Other DPL customers will be eligible for competitive metering on
April 1, 2002 as set forth in the Maryland Act. The MPSC is expected to issue an
order with respect to the proposed settlement by October 1, 1999.
Virginia Electric Utility Industry Restructuring Legislation
As previously reported, electric utility restructuring legislation was
introduced in the Virginia General Assembly on January 21, 1999. The Virginia
General Assembly passed the Virginia Electric Utility Restructuring Act (the
Virginia Act) on March 25, 1999. On March 29, 1999, the Governor of Virginia
signed the Virginia Act.
-12-
<PAGE>
Delaware Retail Gas Pilot Program
On April 27, 1999, the DPSC approved DPL's plan for a natural gas choice
program. Beginning on July 15, 1999, 15,000 current DPL residential natural gas
customers and 1,500 current DPL commercial natural gas customers will be able to
choose a natural gas supplier other than DPL. DPL's large commercial and
industrial customers already have the ability to choose their natural gas
suppliers.
Electric Revenues
Details of the changes in the various components of electric revenues for the
first quarter of 1999 compared to the first quarter of 1998 are shown below
(dollars in millions):
<TABLE>
<CAPTION>
<S> <C>
Non-energy (base rate) revenues $5.6
Energy revenues (1.8)
Interchange delivery revenues 17.3
Revenues from sales not subject
to price regulation 23.7
-----
Total $44.8
=====
</TABLE>
DPL electric revenues increased by $44.8 million, from $278.4 million for the
first quarter of 1998 to $323.2 million for the first quarter of 1999.
Merger-related customer base rate decreases reduced DPL's $5.6 million increase
in non-energy (or base rate) revenues by approximately $2.3 million. Excluding
the effect of the Merger-related customer base rate decreases, non-energy
revenues increased $7.9 million primarily due to a 7.2% increase in regulated
electric retail kilowatt-hour (kWh) sales. The kWh sales increase was primarily
attributed to colder winter weather, which caused greater kWh usage than last
year for heating. A 1.7% increase in the number of customers also contributed to
the kWh sales increase.
Currently, energy and interchange delivery revenues generally do not affect net
income due to energy adjustment clauses as discussed under "Electric Energy
Adjustment Clauses" on page I-7 of DPL's 1998 Report on Form 10-K. After
restructuring becomes effective, gross margins from supplying electricity
(energy supply revenues less energy costs) to current DPL customers are expected
to affect DPL's earnings.
Revenues from electric sales not subject to price regulation increased $23.7
million, mainly due to more output sold off-system through the Merchant
business. Gross margin percentages earned in markets not subject to price
regulation are generally lower than the gross margin percentages earned in
regulated retail markets due to product differences, greater volume per
customer, and unregulated pricing.
Gas Revenues
Total gas revenues increased by $175.2 million, from $115.8 million to $291.0
million. Details of the changes in the various components of gas revenues for
the first quarter of 1999 compared to the first quarter of 1998 are shown below
(dollars in millions):
<TABLE>
<CAPTION>
<S> <C>
Non-energy (base rate) revenues $ 2.3
Energy revenues 5.3
Revenues from sales not subject
to price regulation 167.6
------
Total $175.2
======
</TABLE>
-13-
<PAGE>
The increases shown above for non-energy and energy gas revenues were primarily
due to a 15.1% increase in residential gas sales (based on cubic feet sold) due
to colder winter weather which caused more cubic feet of gas to be used to
operate heating systems. Gas energy revenues generally do not affect net income
due to the energy adjustment clause, as discussed in DPL's 1998 report on Form
10-K, under "Gas Regulatory Matters" on page I-8.
Gas revenues from sales not subject to price regulation increased $167.6 million
mainly due to higher volumes of bulk gas sales. The margin earned from non-price
regulated gas sales in excess of related purchased gas costs is relatively small
mainly due to the competitive nature of bulk commodity sales.
Other Services Revenues
Total revenues from "Other services" decreased from $22.0 million to $5.5
million. The $16.5 million revenue decrease was primarily due to the transfer of
DPL's nonutility subsidiaries to Conectiv on March 1, 1998.
Operating Expenses
Electric Fuel and Purchased Energy Expenses
Electric fuel and purchased energy expenses increased $37.4 million for the
three-month period mainly due to more energy supplied for greater volumes of
electricity sold off-system and within DPL's service territory.
Gas Purchased
Gas purchased increased from $98.6 million to $271.6 million mainly due to
larger volumes of gas purchased for resale off-system and to satisfy higher
on-system sales demand due to the colder winter weather.
Other Services' Cost of Sales
Other services' cost of sales decreased by $10.1 million primarily due to the
transfer of DPL's nonutility subsidiaries to Conectiv on March 1, 1998.
Employee Separation and Other Merger-Related Costs
The costs for separated employees and other Merger related costs expensed in the
first quarter of 1998 were $40.3 million before taxes ($24.4 million after
taxes).
Operation and Maintenance Expenses
Operation and maintenance expenses decreased to $60.3 million in the first
quarter of 1999 from $79.3 million in the first quarter of 1998. Excluding a
$10.6 million decrease due to the transfer of the nonutility subsidiaries to
Conectiv on March 1, 1998, operation and maintenance expenses decreased $8.4
million primarily due to fewer employees, cost control measures, and lower
pension costs.
Depreciation Expense
Depreciation expense decreased $0.9 million primarily due to the transfer of the
nonutility subsidiaries to Conectiv on March 1, 1998.
-14-
<PAGE>
Financing Costs
Financing costs reflected in the consolidated income statement include interest
charges, allowance for funds used during construction (AFUDC), dividends on
preferred securities of a subsidiary trust, and dividends on preferred stock.
Financing costs decreased $0.4 million for the three-month period mainly due to
a lower average amount of debt.
Year 2000
The Year 2000 issue is the result of computer programs and embedded systems
using a two-digit format, as opposed to four digits, to indicate the year.
Computer and embedded systems with this characteristic may be unable to
interpret dates during and beyond the year 1999, which could cause a system
failure or other computer errors, leading to disruption of operations. A project
team, originally started in 1996 by ACE, is managing Conectiv's response to this
situation. A Conectiv corporate officer, reporting directly to the Chief
Executive Officer, is coordinating all Year 2000 activities. There are
substantial challenges in identifying and correcting the computer and embedded
systems critical to generating and delivering power, delivering natural gas and
providing other services to customers.
The project team is using a phased approach to managing its activities. The
first phase is inventory and assessment of all systems, equipment, and
processes. Each identified item was given a criticality rating of high, medium
or low. Those items rated as high or medium are then subject to the second phase
of the project. The second phase is determining and implementing corrective
action for the systems, equipment and processes, and concludes with a test of
the unit being remediated. The third phase is system testing and compliance
certification. Additionally, the project team is updating existing outage
contingency plans to address Year 2000 issues.
Overall, Conectiv's Year 2000 Project covers approximately 140 different systems
(some with numerous components) that had been originally identified as high or
medium in criticality. However, only 21 of those 140 systems are essential for
Conectiv to provide electric and gas service to its customers. The Year 2000
Project team is focusing on these 21 systems, with additional work on the other
systems continuing based on their relative importance to Conectiv's businesses.
The following chart sets forth the current estimated completion percentage of
the 140 different systems in the Year 2000 Project by major business group, and
for the information technology systems used in managing Conectiv's business.
Conectiv expects to continue to see significant progress in remediation and
testing over the next quarter based on work that is in process and material that
has been ordered or already received.
<TABLE>
<CAPTION>
Inventory and Corrective Action/ System Testing/
Business Group Assessment Unit Testing Compliance
- --------------------- ------------- ------------------ ---------------
<S> <C> <C> <C>
Business systems 100% 95% 75%
Power production 100% 55% 40%
Electricity distribution 100% 55% 15%
Gas delivery 100% 90% 90%
Competitive services 100% 100% 50%-90%
</TABLE>
Conectiv is also contacting vendors and service providers to review remediation
of their Year 2000 issues. Many aspects of Conectiv's businesses are dependent
on third parties. For example, fuel suppliers must be able to provide coal or
gas to allow DPL to generate electricity.
-15-
<PAGE>
Distribution of electricity is dependent on the overall reliability of the
electric grid. DPL is cooperating with the North American Electric Reliability
Council (NERC) and the PJM Interconnection in Year 2000 remediation and
contingency planning efforts. Recent reports issued by NERC indicate a
diminished risk of disruption to the electric grid caused by Year 2000 issues.
Conectiv's Year 2000 Project timeline is generally in-line with the
recommendations of those groups. Two small DPL generating units for which
remediation will be complete by June, 1999, are scheduled for testing in
September to coincide with a previously scheduled outage. These units represent
about 6% of DPL's generating capacity and will be tested earlier if an
appropriate outage occurs. Testing that has already taken place at similar units
that have been remediated indicated no year 2000 problems.
In addition, DPL participated in the first of two NERC drills on April 9, 1999;
a small number of manageable issues were identified and are being addressed. DPL
will also participate in the second NERC drill set scheduled for September 9,
1999 and will conduct its own drill.
Conectiv has incurred approximately $5.7 million in costs for the Year 2000
Project. Current estimates of the costs for the Year 2000 Project range from $10
million to $15 million. These estimates could change significantly as the Year
2000 Project progresses. The costs set forth above do not include several
significant expenditures covering new systems, such as Conectiv's SAP business,
financial and human resources management system and an Energy Control System.
While these new systems effectively remediated Year 2000 problems in the systems
they replaced, Conectiv is not reporting the expenditures on these systems in
its costs for the Year 2000 Project, because the new systems were installed
principally for other reasons.
Since the project team is still in the process of assessing and correcting
impacted systems, equipment and processes, DPL cannot with certainty determine
whether the Year 2000 issue might cause disruptions to its operations and impact
related costs and revenues. DPL assesses the status of the Year 2000 Project on
at least a monthly basis to determine the likelihood of disruption. Based on its
own Year 2000 program, as well as reports from NERC and other utilities,
management believes it is unlikely that significant Year 2000 related disruption
will occur. However, any substantial disruption to DPL's operations could
negatively impact DPL's revenues, significantly impact its customers and could
generate legal claims against DPL. DPL's results of operations and financial
position would likely suffer an adverse impact if other entities, such as
suppliers, customers and service providers do not effectively address their Year
2000 issues.
Liquidity and Capital Resources
Net cash provided by operating activities was $81.4 million for the three months
ended March 31, 1999 compared to $79.6 million for the three months ended March
31, 1998, a $1.8 million increase.
Net cash provided by operating activities for the three months ended March 31,
1999 was used primarily for $23.8 million of capital expenditures and to repay
$21.7 million of short-term debt.
Primarily due to over-collections of energy costs from utility customers, DPL's
liability for deferred energy costs was $15.7 million as of March 31, 1999.
These over-collections of energy costs will be returned to customers via lower
energy rates, which will reduce net cash provided by operating activities as the
energy business of DPL is restructured.
-16-
<PAGE>
DPL's ratios of earnings to fixed charges and earnings to fixed charges and
preferred stock dividends under the SEC Method are shown below:
<TABLE>
<CAPTION>
12 Months Year Ended December 31,
Ended --------------------------------
March 31, 1999 1998 1997 1996 1995 1994
-------------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Ratio of Earnings to:
Fixed Charges (SEC Method) 3.66 2.92 2.83 3.33 3.54 3.49
Fixed Charges and
Preferred Stock
Dividends (SEC Method) 3.40 2.72 2.63 2.83 2.92 2.85
</TABLE>
Under the SEC Method, earnings, including AFUDC, have been computed by adding
income taxes and fixed charges to net income. Fixed charges include gross
interest expense, the estimated interest component of rentals, and dividends on
preferred securities of a subsidiary trust. For the ratio of earnings to fixed
charges and preferred stock dividends, preferred stock dividends represent
annualized preferred stock dividend requirements multiplied by the ratio that
pre-tax income bears to net income.
Forward-Looking Statements
The Private Securities Litigation Reform Act of 1995 (Litigation Reform Act)
provides a "safe harbor" for forward-looking statements to encourage such
disclosures without the threat of litigation, provided those statements are
identified as forward-looking and are accompanied by meaningful, cautionary
statements identifying important factors that could cause the actual results to
differ materially from those projected in the statement. Forward-looking
statements have been made in this report. Such statements are based on
management's beliefs as well as assumptions made by and information currently
available to management. When used herein, the words "will," "anticipate,"
"estimate," "expect," "objective," and similar expressions are intended to
identify forward-looking statements. In addition to any assumptions and other
factors referred to specifically in connection with such forward-looking
statements, factors that could cause actual results to differ materially from
those contemplated in any forward-looking statements include, among others, the
following: deregulation of energy supply and the unbundling of delivery
services; an increasingly competitive marketplace; results of any asset
dispositions; sales retention and growth; federal and state regulatory actions;
future litigation results; costs of construction; operating restrictions;
increased costs and construction delays attributable to environmental
regulations; nuclear decommissioning and the availability of reprocessing and
storage facilities for spent nuclear fuel; and credit market concerns. DPL
undertakes no obligation to publicly update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
The foregoing list of factors pursuant to the Litigation Reform Act should not
be construed as exhaustive or as any admission regarding the adequacy of
disclosures made by DPL prior to the effective date of the Litigation Reform
Act.
-17-
<PAGE>
PART II. OTHER INFORMATION
Item 5. Other Information
The following information updates the disclosure regarding Air Quality
Regulations on page I-10 of DPL's 1998 Report on Form 10-K.
On March 1, 1999, the State of Delaware Department of Natural Resources and
Environmental Control (DNREC) re-issued final "post-RACT" NOx control
regulations requiring attainment of summer seasonal emission reductions of up to
65% below 1990 levels by May 1999 through reduced emissions or the procurement
of NOx emission allowances. DPL is working toward compliance with the
regulations by installing control technology and trying to secure NOx
allowances. The short time period between initial proposal of the regulations in
October 1997 and the May 1999 compliance date, uncertainty regarding the
successful implementation of control technologies in the short term, inadequate
time for development of an allowance trading market and the regulations'
stringent penalties for non-compliance, have prompted DPL to challenge the
regulations before the Environmental Appeals Board and in Delaware Superior
Court. Management cannot predict the outcome of this litigation.
Similar post-RACT regulations issued in Maryland were vacated in February 1999
by the Maryland Circuit Court for Baltimore City in response to a challenge by
other Maryland utilities. Accordingly, the Company's Maryland units are not
required to comply with post-RACT requirements during the 1999 summer ozone
season.
Item 6. Exhibits and Reports on Form 8-K
Exhibits
Exhibit 12-A, Computation of Ratio of Earnings to Fixed Charges
Exhibit 12-B, Computation of Ratio of Earnings to Fixed Charges and Preferred
Dividends
Exhibit 27, Financial Data Schedule
Reports on Form 8-K
On January 26, 1999, DPL filed a Report on Form 8-K under Item 5, Other Events,
concerning proposed legislation in Delaware to restructure the electric utility
industry.
On April 14, 1999, DPL filed a Report on Form 8-K under Item 5, Other Events,
concerning electric utility industry restructuring legislation in Delaware,
Maryland, and Virginia.
-18-
<PAGE>
SIGNATURE
Pursuant to the requirements 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.
Delmarva Power & Light Company
------------------------------
(Registrant)
Date: May 13, 1999 /s/ John C. van Roden
------------ -------------------------------------
John C. van Roden, Senior Vice
President and Chief Financial Officer
-19-
<PAGE>
Exhibit 12-A
Delmarva Power & Light Company
Ratio of Earnings to Fixed Charges
----------------------------------
(Dollars in Thousands)
----------------------
<TABLE>
<CAPTION>
12 Months
Ended Year Ended December 31,
March 31, --------------------------------------------------------------------
1999 1998 1997 1996 1995 1994
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Net income $ 152,880 $ 112,410 $ 105,709 $ 116,187 $ 117,488 $ 108,310
--------- --------- --------- --------- --------- ---------
Income taxes 98,142 72,276 72,155 78,340 75,540 67,613
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest on long-term debt
including amortization of
discount, premium and expense 80,729 81,132 78,350 69,329 65,572 61,128
Other interest 7,982 9,328 12,835 12,516 10,353 9,336
Preferred dividend requirements of a
subsidiary trust 5,688 5,688 5,687 1,390 -- --
--------- --------- --------- --------- --------- ---------
Total fixed charges 94,399 96,148 96,872 83,235 75,925 70,464
--------- --------- --------- --------- --------- ---------
Nonutility capitalized interest -- -- (208) (311) (304) (256)
--------- --------- --------- --------- --------- ---------
Earnings before income taxes
and fixed charges $ 345,421 $ 280,834 $ 274,528 $ 277,451 $ 268,649 $ 246,131
========= ========= ========= ========= ========= =========
Ratio of earnings to fixed charges 3.66 2.92 2.83 3.33 3.54 3.49
</TABLE>
For purposes of computing the ratio, earnings are net income plus income taxes
and fixed charges, less nonutility capitalized interest. Fixed charges consist
of interest on long- and short-term debt, amortization of debt discount,
premium, and expense, dividends on preferred securities of a subsidiary trust,
plus the interest factor associated with DPL's major leases, and one-third of
the remaining annual rentals.
<PAGE>
Exhibit 12-B
Delmarva Power & Light Company
Ratio of Earnings to Fixed Charges and Preferred Dividends
----------------------------------------------------------
(Dollars in Thousands)
----------------------
<TABLE>
<CAPTION>
12 Months
Ended Year Ended December 31,
March 31, --------------------------------------------------------------------
1999 1998 1997 1996 1995 1994
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Net income $ 152,880 $ 112,410 $ 105,709 $ 116,187 $ 117,488 $ 108,310
--------- --------- --------- --------- --------- ---------
Income taxes 98,142 72,276 72,155 78,340 75,540 67,613
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest on long-term debt
including amortization of
discount, premium and
expense 80,729 81,132 78,350 69,329 65,572 61,128
Other interest 7,982 9,328 12,835 12,516 10,353 9,336
Preferred dividend requirements
of a subsidiary trust 5,688 5,688 5,687 1,390 -- --
--------- --------- --------- --------- --------- ---------
Total fixed charges 94,399 96,148 96,872 83,235 75,925 70,464
--------- --------- --------- --------- --------- ---------
Nonutility capitalized interest -- -- (208) (311) (304) (256)
--------- --------- --------- --------- --------- ---------
Earnings before income taxes
and fixed charges $ 345,421 $ 280,834 $ 274,528 $ 277,451 $ 268,649 $ 246,131
========= ========= ========= ========= ========= =========
Fixed charges $ 94,399 $ 96,148 $ 96,872 $ 83,235 $ 75,925 $ 70,464
Preferred dividend requirements 7,124 7,150 7,556 14,961 16,185 15,948
--------- --------- --------- --------- --------- ---------
$ 101,523 $ 103,298 $ 104,428 $ 98,196 $ 92,110 $ 86,412
========= ========= ========= ========= ========= =========
Ratio of earnings to fixed charges
and preferred dividends 3.40 2.72 2.63 2.83 2.92 2.85
</TABLE>
For purposes of computing the ratio, earnings are net income plus income taxes
and fixed charges, less nonutility capitalized interest. Fixed charges consist
of interest on long- and short-term debt, amortization of debt discount,
premium, and expense, dividends on preferred securities of a subsidiary trust,
plus the interest factor associated with DPL's major leases, and one-third of
the remaining annual rentals. Preferred dividend requirements represent
annualized preferred dividend requirements multiplied by the ratio that pre-tax
income bears to income.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AND STATEMENT OF INCOME FROM DPL'S FIRST QUARTER 1999
10-Q AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,953,839
<OTHER-PROPERTY-AND-INVEST> 66,673
<TOTAL-CURRENT-ASSETS> 397,233
<TOTAL-DEFERRED-CHARGES> 256,691
<OTHER-ASSETS> 237,487
<TOTAL-ASSETS> 2,911,923
<COMMON> 2
<CAPITAL-SURPLUS-PAID-IN> 528,893
<RETAINED-EARNINGS> 333,491
<TOTAL-COMMON-STOCKHOLDERS-EQ> 862,386
70,000
89,703
<LONG-TERM-DEBT-NET> 951,957
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 31,287
0
<CAPITAL-LEASE-OBLIGATIONS> 14,742
<LEASES-CURRENT> 12,484
<OTHER-ITEMS-CAPITAL-AND-LIAB> 879,364
<TOT-CAPITALIZATION-AND-LIAB> 2,911,923
<GROSS-OPERATING-REVENUE> 619,707
<INCOME-TAX-EXPENSE> 23,458
<OTHER-OPERATING-EXPENSES> 542,497
<TOTAL-OPERATING-EXPENSES> 565,955
<OPERATING-INCOME-LOSS> 53,752
<OTHER-INCOME-NET> 3,312
<INCOME-BEFORE-INTEREST-EXPEN> 57,064
<TOTAL-INTEREST-EXPENSE> 21,450
<NET-INCOME> 35,614
1,073
<EARNINGS-AVAILABLE-FOR-COMM> 34,541
<COMMON-STOCK-DIVIDENDS> 23,649
<TOTAL-INTEREST-ON-BONDS> 20,520
<CASH-FLOW-OPERATIONS> 81,357
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
