<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1994
------------------------------------------------
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 1-1405
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 302-429-3011
------------
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.
Class Outstanding at July 31, 1994
- ----------------------------- ----------------------------
Common Stock, $2.25 par value 59,542,006 Shares
<PAGE>
DELMARVA POWER & LIGHT COMPANY
------------------------------
Table of Contents
-----------------
Page No.
--------
Part I. Financial Information:
Consolidated Balance Sheets as of June 30, 1994
and December 31, 1993.................................. 2-3
Consolidated Statements of Income for the three, six,
and twelve months ended June 30, 1994 and 1993......... 4
Consolidated Statements of Cash Flows for the six and
twelve months ended June 30, 1994 and 1993............. 5
Notes to Consolidated Financial Statements............. 6-9
Selected Financial and Operating Data.................. 10
Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 11-20
Part II. Other Information and Signature.......................... 21-27
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<PAGE>
PART I. FINANCIAL INFORMATION
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
<TABLE>
<CAPTION>
June 30, December 31,
1994 1993
---------- ----------
(Unaudited)
ASSETS
------
<S> <C> <C>
UTILITY PLANT, AT ORIGINAL COST:
Electric......................................... $2,595,605 $2,561,507
Gas.............................................. 182,498 176,167
Common........................................... 127,358 122,182
---------- ----------
2,905,461 2,859,856
Less: Accumulated depreciation.................. 1,027,748 989,351
---------- ----------
Net utility plant in service..................... 1,877,713 1,870,505
Construction work-in-progress.................... 99,468 91,001
Leased nuclear fuel, at amortized cost........... 29,467 33,905
---------- ----------
2,006,648 1,995,411
---------- ----------
INVESTMENTS AND NONUTILITY PROPERTY:
Investment in leveraged leases................... 49,986 50,914
Funds held by trustee............................ 22,419 17,577
Other investments and nonutility property, net... 53,675 55,248
---------- ----------
126,080 123,739
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents........................ 24,600 23,017
Accounts receivable:
Customers.................................... 97,576 98,472
Other........................................ 13,361 18,405
Inventories, at average cost:
Fuel (coal, oil, and gas).................... 31,368 27,335
Materials and supplies....................... 37,784 37,687
Prepayments...................................... 4,356 9,534
Deferred income taxes, net....................... 9,202 10,713
---------- ----------
218,247 225,163
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS:
Unamortized debt expense......................... 11,077 11,222
Deferred debt refinancing costs.................. 27,666 28,794
Deferred recoverable plant costs................. 14,748 15,613
Deferred recoverable income taxes................ 130,367 144,463
Other............................................ 57,371 49,124
---------- ----------
241,229 249,216
---------- ----------
TOTAL ASSETS $2,592,204 $2,593,529
========== ==========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
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<PAGE>
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
<TABLE>
<CAPTION>
June 30, December 31,
1994 1993
----------- ------------
(Unaudited)
CAPITALIZATION AND LIABILITIES
------------------------------
<S> <C> <C>
CAPITALIZATION:
Common stock............................... $133,970 $132,366
Additional paid-in capital................. 484,377 470,997
Retained earnings.......................... 269,678 259,507
Unearned compensation...................... (1,240) (675)
---------- ----------
Total common stockholders' equity...... 886,785 862,195
Preferred stock............................ 168,085 168,085
Long-term debt............................. 746,566 736,368
---------- ----------
1,801,436 1,766,648
---------- ----------
CURRENT LIABILITIES:
Long-term debt due within one year......... 25,931 25,986
Variable rate demand bonds................. 41,500 41,500
Accounts payable........................... 41,307 55,175
Taxes accrued.............................. 8,925 10,987
Interest accrued........................... 15,815 15,522
Dividends declared......................... 22,871 22,664
Current capital lease obligation........... 12,444 12,684
Deferred energy costs...................... 15,139 14,229
Other...................................... 29,022 32,681
---------- ----------
212,954 231,428
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes, net................. 483,442 497,457
Deferred investment tax credits............ 48,218 49,475
Long-term capital lease obligation......... 18,874 23,335
Other...................................... 27,280 25,186
---------- ----------
577,814 595,453
---------- ----------
TOTAL CAPITALIZATION AND LIABILITIES $2,592,204 $2,593,529
========== ==========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
-3-
<PAGE>
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED STATEMENTS OF INCOME
(DOLLARS IN THOUSANDS)
(Unaudited)
-----------
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
-------------------- -------------------- --------------------
1994 1993 1994 1993 1994 1993
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES
Electric.............................................. $197,934 $196,236 $440,687 $406,525 $909,825 $816,398
Gas................................................... 20,531 18,402 70,172 56,120 108,996 91,364
--------- --------- --------- --------- --------- ---------
218,465 214,638 510,859 462,645 1,018,821 907,762
--------- --------- --------- --------- --------- ---------
OPERATING EXPENSES
Electric fuel and purchased power..................... 58,221 68,496 146,715 144,018 301,004 281,435
Gas purchased......................................... 13,022 10,895 42,721 31,149 65,203 48,382
Operation and maintenance............................. 65,201 62,344 123,084 115,223 255,911 234,884
Depreciation.......................................... 27,220 23,315 53,871 47,867 106,933 96,098
Taxes other than income taxes......................... 8,982 8,706 19,711 18,353 38,778 37,022
Income taxes.......................................... 11,825 9,643 36,993 28,518 76,606 56,050
--------- --------- --------- --------- --------- ---------
184,471 183,399 423,095 385,128 844,435 753,871
--------- --------- --------- --------- --------- ---------
OPERATING INCOME........................................ 33,994 31,239 87,764 77,517 174,386 153,891
--------- --------- --------- --------- --------- ---------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains.................................. 10,814 8,827 20,785 16,399 42,024 24,199
Expenses including interest and income taxes........ (10,212) (7,554) (18,891) (14,437) (40,284) (22,074)
--------- --------- --------- --------- --------- ---------
Net earnings of nonutility subsidiaries........ 602 1,273 1,894 1,962 1,740 2,125
Allowance for equity funds used during construction... 1,019 1,747 1,725 4,062 2,971 7,587
Other income, net of income taxes..................... 63 (390) (1,027) (346) (170) 340
--------- --------- --------- --------- --------- ---------
1,684 2,630 2,592 5,678 4,541 10,052
--------- --------- --------- --------- --------- ---------
INCOME BEFORE UTILITY INTEREST CHARGES.................. 35,678 33,869 90,356 83,195 178,927 163,943
--------- --------- --------- --------- --------- ---------
UTILITY INTEREST CHARGES
Debt.................................................. 14,243 15,465 28,445 31,241 57,634 63,660
Other................................................. 1,173 766 2,379 1,386 4,657 2,790
Allowance for borrowed funds used during
construction........................................ (514) (1,120) (885) (2,604) (1,685) (5,156)
--------- --------- --------- --------- --------- ---------
14,902 15,111 29,939 30,023 60,606 61,294
--------- --------- --------- --------- --------- ---------
NET INCOME.............................................. 20,776 18,758 60,417 53,172 118,321 102,649
DIVIDENDS ON PREFERRED STOCK............................ 2,323 2,479 4,587 4,982 9,607 9,735
--------- --------- --------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK..................... $18,453 $16,279 $55,830 $48,190 $108,714 $92,914
========= ========= ========= ========= ========= =========
COMMON STOCK
Average shares outstanding (000)...................... 59,402 58,036 59,212 56,585 58,871 55,209
Earnings per average share............................ $0.31 $0.27 $0.94 $0.85 $1.85 $1.68
Dividends declared per share.......................... $0.38 1/2 $0.38 1/2 $0.77 $0.77 $1.54 $1.54
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
-4-
<PAGE>
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
-----------
<TABLE>
<CAPTION>
Six Months Ended Twelve Months Ended
June 30 June 30
---------------------- ----------------------
1994 1993 1994 1993
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................. $ 60,417 $ 53,172 $118,321 $102,649
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization............................ 59,422 55,194 117,154 109,102
Allowance for equity funds used during construction...... (1,725) (4,062) (2,971) (7,587)
Investment tax credit adjustments, net................... (1,257) (1,257) (2,515) (2,410)
Deferred income taxes, net............................... 1,749 (11,487) 12,065 (7,448)
Net change in :
Receivable for Peach Bottom lawsuit settlement........ - - - 18,538
Accounts receivable................................... 5,926 (1,494) (8,431) (15,979)
Inventories........................................... (4,130) (5,575) 7,713 (1,351)
Accounts payable...................................... (13,879) (16,723) 1,656 (1,896)
Other current assets & liabilities*................... 299 28,626 (17,278) 10,284
Other,net................................................ (2,264) (3,437) (4,266) (2,697)
-------- -------- -------- --------
Net cash provided by operating activities...................... 104,558 92,957 221,448 201,205
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures, excluding AFUDC................. (64,519) (79,913) (144,597) (192,076)
Allowance for borrowed funds used during construction...... (885) (2,604) (1,685) (5,156)
Cash flows from leveraged leases:
Insurance proceeds from casualty loss.................... - - - 4,115
Sale of interests in leveraged leases.................... - 14,527 7,015 14,527
Other.................................................... 1,044 988 1,567 2,388
Investment in subsidiary projects and operations........... (2,399) (2,071) (3,155) (2,665)
(Increase)/decrease in bond proceeds held in trust funds... 7 (24,370) 25,529 (13,973)
Deposits to nuclear decommissioning trust funds............ (1,260) (1,561) (2,356) (2,437)
Other, net................................................. (3,527) (2,991) (925) 1,915
-------- -------- -------- --------
Net cash used by investing activities.......................... (71,539) (97,995) (118,607) (193,362)
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends: Common...................................... (45,377) (43,088) (90,278) (84,368)
Preferred................................... (4,654) (5,041) (9,655) (9,834)
Issuances: Long-term debt.............................. - 58,200 90,000 155,535
Variable rate demand bonds.................. - - 15,500 -
Common stock................................ 14,974 94,202 30,235 109,895
Preferred stock............................. - - 20,000 40,000
Redemptions: Long-term debt.............................. (397) (50,378) (134,225) (147,726)
Variable rate demand bonds.................. - - (15,500) -
Common stock................................ (794) (743) (799) (743)
Preferred stock............................. - - (28,280) -
Principal portion of capital lease payments................ (5,551) (5,286) (10,221) (10,963)
Net change in term loan.................................... 10,500 - 20,500 -
Net change in short-term debt ............................. - (17,000) - (22,989)
Cost of issuances and refinancings......................... (137) (7,447) (5,787) (13,898)
-------- -------- -------- --------
Net cash provided/(used) by financing activities............... (31,436) 23,419 (118,510) 14,909
-------- -------- -------- --------
Net change in cash and cash equivalents........................ 1,583 18,381 (15,669) 22,752
Cash and cash equivalents at beginning of period............... 23,017 21,888 40,269 17,517
-------- -------- -------- --------
Cash and cash equivalents at end of period..................... $ 24,600 $ 40,269 $ 24,600 $ 40,269
======== ======== ======== ========
</TABLE>
*Other than debt classified as current and current deferred income taxes.
See accompanying Notes to Consolidated Financial Statements.
-5-
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
1. INTERIM FINANCIAL STATEMENTS
----------------------------
The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries. The statements reflect all adjustments necessary
in the opinion of the Company for a fair presentation of interim results. They
should be read in conjunction with the Company's 1993 Annual Report to
Stockholders, the Company's Report on Form 10-Q for the first quarter of 1994,
and Part II of this Report on Form 10-Q for additional relevant information.
2. ACCOUNTING PRINCIPLE ADOPTED IN THE FIRST QUARTER OF 1994
---------------------------------------------------------
For information concerning the Company's adoption of Statement of Financial
Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt
and Equity Securities," refer to Note 3, to the Consolidated Financial
Statements included in the Company's Report on Form 10-Q for the first quarter
of 1994.
3. BASE RATE MATTERS
-----------------
Below is an update to matters previously reported on under "Regulatory and Rate
Matters--Base Rate Proceedings" in Part I of the Company's 1993 Annual Report on
Form 10-K and the notes to the Consolidated Financial Statements of the
Company's Report on Form 10-Q for the first quarter of 1994.
RESALE ELECTRIC RATES
- ---------------------
On October 30, 1992, the Company filed an application with the Federal Energy
Regulatory Commission (FERC) for an increase in electric base rates. The
Company subsequently reached settlement agreements (in principle) with all of
its resale customers allowing for an increase of $1.5 million or 1.5%. The FERC
approved the Company's settlement agreements with Old Dominion Electric
Cooperative (ODEC) in June 1994 and the Town of Berlin, Maryland on August 2,
1994. A settlement agreement with the Company's remaining resale customers is
expected to be filed with the FERC in the third quarter of 1994.
On May 16, 1994, the Company filed a proposed partial requirements rate and a
transmission wheeling rate to serve ODEC starting January 1, 1995. On August 8,
1994, a verbal agreement in principle was tentatively reached with ODEC on these
rate filings.
DELAWARE GAS BASE RATES
- -----------------------
On May 6, 1994, the Company filed an application with the Delaware Public
Service Commission (DPSC) for a $4.2 million or 4.1% increase in gas base rates.
On July 5, 1994, an interim $1 million rate increase became effective, subject
to refund. Hearings currently are scheduled for September 1994.
LIMITED ISSUE RATE CASES
- ------------------------
During the second quarter of 1994, the Company notified the DPSC and Maryland
Public Service Commission (MPSC) of its intent to request targeted or limited
issue price increases
-6-
<PAGE>
totaling $10 to $15 million, or approximately 2% of current rates, to be
effective in 1995. The Company plans to seek recovery of certain costs such as
costs imposed by law related to the 1993 one-percent increase in the federal
income tax rate, compliance with the Clean Air Act Amendments of 1990, and
nuclear decommissioning. The Company does not plan to seek an increase in its
allowed return on equity. The Company expects to file for these limited issue
rate increases in Delaware and Maryland during the third quarter of 1994.
MARYLAND CONSERVATION SURCHARGE
- -------------------------------
During the second quarter of 1994, the Company also filed with the MPSC for
approval of a surcharge which would recover the cost of customer conservation
programs, $1.6 million of which has been deferred by the Company as of June 30,
1994. In June 1994, the MPSC approved the surcharge.
4. COMMON STOCK
------------
During the first six months of 1994, the Company issued 712,723 shares of common
stock for $14,973,335 primarily through the Dividend Reinvestment and Common
Share Purchase Plan (DRIP). As of June 30, 1994, 59,542,006 shares of Common
Stock were outstanding. Effective June 1, 1994, the shares acquired for the
DRIP began to be purchased on the open market rather than through the issuance
of new shares.
5. PURCHASE OF CONOWINGO POWER COMPANY
-----------------------------------
On May 24, 1994, the Company entered into an agreement with PECO Energy Company
(PECO) to buy its Maryland retail electric subsidiary, Conowingo Power Company
(COPCO), for $150 million. The Company ultimately plans to finance the
acquisition of COPCO with approximately 50% long-term debt and 50% common stock.
On May 24, 1994, the Company also entered into an agreement with PECO to
purchase electric capacity and energy from the PECO system. Under the terms of
this agreement, the Company will buy capacity and energy from PECO beginning on
the later of the closing date of the COPCO acquisition or February 1, 1996, and
ending May 31, 2006. The base amount of purchased capacity will start at 205
megawatts (MW) and will increase annually to 259 MW in the final year of the
contract, subject to certain provisions that allow PECO to increase the capacity
by up to 20 MW or decrease the capacity by up to 50 MW after June 1, 1998. The
Company also has agreed to continue the present COPCO power supply agreement
with PECO on an interim basis until February 1, 1996, if the closing date of the
COPCO acquisition occurs prior to February 1, 1996.
The acquisition of COPCO by the Company and the related power supply agreements
are subject to certain state and federal regulatory approvals. The Company
expects to complete this process in 1995.
6. CONTINGENCIES
-------------
NUCLEAR INSURANCE
- -----------------
In the event of an incident at any commercial nuclear power plant in the United
States, the Company could be assessed for a portion of any third-party claims
associated with the incident. 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), the Company could be assessed up to $23.7 million
for third-party claims. In addition, Congress could impose a revenue-raising
measure on the nuclear industry to pay such claims.
-7-
<PAGE>
The co-owners of the Peach Bottom Atomic Power Station (Peach Bottom) and Salem
Generating Station (Salem) maintain nuclear property damage and decontamination
insurance in the aggregate amount of $2.7 billion for each station. The Company
is self-insured, to the extent of its ownership interest, for its share of
property losses in excess of insurance coverages. Under the terms of the
various insurance agreements, the Company could be assessed up to $3.5 million
in any policy year for losses incurred at nuclear plants insured by the
insurance companies.
The Company 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. The premium for this coverage is subject to retrospective
assessment for adverse loss experience. The Company's present maximum share of
any assessment is $1.4 million per year.
ENVIRONMENTAL MATTERS
- ---------------------
As previously disclosed under "Hazardous Substances" on page I-17 of the
Company's 1993 Annual Report on Form 10-K, the disposal of Company-generated
hazardous substances can result in costs to clean up facilities found to be
contaminated due to past disposal practices. The Company is currently a
potentially responsible party (PRP) at two federal superfund sites and is
alleged to be a third-party contributor at two other such sites. The Company
also has three former coal gasification sites and is currently participating
with the State of Delaware in conducting studies at two of the three sites to
assess the extent of contamination and risk to the environment. The Company
does not expect clean-up and other potential costs related to the PRP and coal
gasification sites, either separately or cumulatively, to have a material effect
on the Company's financial position or results of operations.
OTHER
- -----
On December 14, 1993, Star Enterprise (Star) filed a complaint against the
Company in Delaware Chancery Court alleging that the Company overcharged it for
pension and tax-related costs under a contract entered into by the parties'
predecessors in 1955. The complaint asks for a refund and damages totaling $9.3
million. On May 25, 1994, Star and the Company reached a settlement in principle
concerning Star's claims. While the final details of such settlement have not
yet been determined, the Company expects that the settlement will not have a
material effect on the Company's financial position or results of operations.
The Company is involved in certain other legal and administrative proceedings
before various courts and governmental agencies concerning rates, fuel
contracts, tax filings and other matters. The Company expects that the ultimate
disposition of these proceedings will not have a material effect on the
Company's financial position or results of operations.
7. SUPPLEMENTAL CASH FLOW INFORMATION
----------------------------------
<TABLE>
<CAPTION>
Six Months Ended Twelve Months Ended
June 30, June 30,
---------------- -------------------
(Dollars in Thousands) 1994 1993 1994 1993
------- ------- -------- --------
<S> <C> <C> <C> <C>
CASH PAID FOR
Interest, net of amounts
capitalized $28,231 $29,248 $57,137 $59,720
Income taxes, net of refunds $37,925 $33,930 $76,364 $61,840
</TABLE>
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<PAGE>
8. NONUTILITY SUBSIDIARIES
-----------------------
The following presents consolidated condensed financial information of the
Company's nonregulated wholly-owned subsidiaries: Delmarva Energy Company;
Delmarva Industries, Inc.; and Delmarva Capital Investments, Inc. A subsidiary
which leases real estate to the Company's utility business, Delmarva Services
Company, is excluded from these statements since its income is derived from
intercompany transactions which are eliminated in consolidation.
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
------------------- ----------------- -------------------
(Dollars in Thousands) 1994 1993 1994 1993 1994 1993
--------- -------- -------- ------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
REVENUES AND GAINS
Landfill and waste hauling $ 3,674 $ 2,824 $ 6,437 $ 5,036 $13,146 $ 9,905
Operating services 5,875 5,806 10,599 10,110 22,607 11,583
Other revenues 1,021 217 3,272 505 4,884 1,061
Leveraged leases 63 (88) 116 653 298 476
Other investment income 181 68 361 95 1,089 1,174
------- ------- ------- ------- ------- -------
10,814 8,827 20,785 16,399 42,024 24,199
------- ------- ------- ------- ------- -------
COST AND EXPENSES
Operating expenses 9,797 9,002 17,620 16,243 37,803 25,634
Interest expense 52 60 110 122 234 406
Capitalized interest (46) (35) (90) (65) (271) (203)
Income taxes 409 (1,473) 1,251 (1,863) 2,518 (3,763)
------- ------- ------- ------- ------- -------
10,212 7,554 18,891 14,437 40,284 22,074
------- ------- ------- ------- ------- -------
NET INCOME $ 602 $ 1,273 $ 1,894 $ 1,962 $ 1,740 $ 2,125
======= ======= ======= ======= ======= =======
EARNINGS PER SHARE OF COMMON
STOCK ATTRIBUTED TO SUBSIDIARIES $0.01 $0.02 $0.03 $0.03 $0.03 $0.04
</TABLE>
-9-
<PAGE>
SELECTED FINANCIAL AND OPERATING DATA
-------------------------------------
(Dollars in Thousands)
<TABLE>
<CAPTION>
3 Months Ended 6 Months Ended 12 Months Ended
June 30 June 30 June 30
------------------------- ------------------------- --------------------------
1994 1993 1994 1993 1994 1993
---------- ---------- ---------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
ELECTRIC REVENUES
- -----------------
Residential $63,216 $62,092 $155,964 $142,073 $319,337 $281,225
Commercial 56,620 55,422 116,119 109,878 244,026 227,004
Industrial 35,586 36,374 70,372 71,754 148,796 147,242
Resale, etc. 24,673 24,576 55,952 53,253 114,480 106,629
Unbilled Sales Revenues 6,012 5,297 1,560 3,055 1,423 5,061
---------- ---------- ---------- ---------- ----------- ----------
Sales Revenues 186,107 183,761 399,967 380,013 828,062 767,161
Interchange Deliveries 9,804 12,751 36,764 25,012 73,189 43,565
Miscellaneous Revenues 2,023 (276) 3,956 1,500 8,574 5,672
---------- ---------- ---------- ---------- ----------- ----------
Total Electric Revenues $197,934 $196,236 $440,687 $406,525 $909,825 $816,398
========== ========== ========== ========== =========== ==========
ELECTRIC SALES
- --------------
(1000 kilowatthours)
Residential 699,328 700,977 1,876,145 1,726,436 3,649,096 3,308,088
Commercial 796,587 765,747 1,688,736 1,589,768 3,435,815 3,223,144
Industrial 801,563 785,681 1,572,630 1,557,391 3,247,472 3,183,709
Resale, etc. 490,602 476,849 1,100,039 1,031,877 2,253,168 2,088,063
Unbilled Sales, net 54,502 13,773 (23,768) (17,549) 20,538 79,384
---------- ---------- ---------- ---------- ----------- ----------
Total Electric Sales 2,842,582 2,743,027 6,213,782 5,887,923 12,606,089 11,882,388
========== ========== ========== ========== =========== ==========
Interchange Deliveries 354,136 487,603 1,156,143 922,679 2,458,848 1,501,920
========== ========== ========== ========== =========== ==========
GAS REVENUES
- ------------
Billed Sales Revenues $21,584 $19,882 $72,050 $57,788 $108,381 $89,245
Unbilled Sales Revenues (1,329) (1,648) (2,326) (1,980) (83) 1,307
Gas Transportation Revenues 276 168 448 312 698 812
---------- ---------- ---------- ---------- ----------- ----------
Total Gas Revenues $20,531 $18,402 $70,172 $56,120 $108,996 $91,364
========== ========== ========== ========== =========== ==========
GAS SALES AND GAS TRANSPORTED
- -----------------------------
(mcf 000)
Billed Sales 3,709 3,762 11,977 11,171 18,750 17,485
Unbilled Sales (613) (763) (1,001) (863) (16) 464
Gas Transported 532 501 860 1,000 1,399 2,519
---------- ---------- ---------- ---------- ----------- ----------
Total 3,628 3,500 11,836 11,308 20,133 20,468
========== ========== ========== ========== =========== ==========
<CAPTION>
June 30, 1994 December 31, 1993 June 30, 1993
------------------------- ------------------------- --------------------------
$ % $ % $ %
---------- ---------- ---------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
CAPITALIZATION
- --------------
Variable Rate Demand Bonds (1) $41,500 2.3 $41,500 2.3 $41,500 2.3
Long-Term Debt 746,566 40.5 736,368 40.7 752,294 41.6
Preferred Stock 168,085 9.1 168,085 9.3 176,365 9.7
Common Stockholders' Equity 886,785 48.1 862,195 47.7 840,304 46.4
---------- ---------- ---------- ---------- ----------- ----------
Total $1,842,936 100.0 $1,808,148 100.0 $1,810,463 100.0
========== ========== ========== ========== =========== ==========
</TABLE>
(1) The Company intends to use the bonds as a source of long-term financing as
discussed in Note 9 to the Consolidated Financial Statements of the 1993
Annual Report.
-10-
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EARNINGS
- --------
Earnings per average share of common stock outstanding for the three-, six-, and
twelve-month periods ended June 30, 1994, and June 30, 1993, were as follows:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
------------------ ------------------ ------------------
6/30/94 6/30/93 6/30/94 6/30/93 6/30/94 6/30/93
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Core Utility Operations $ 0.30 $ 0.25 $ 0.91 $ 0.82 $ 1.82 $ 1.64
Nonutility Subsidiaries 0.01 0.02 0.03 0.03 0.03 0.04
-------- -------- -------- -------- -------- --------
$ 0.31 $ 0.27 $ 0.94 $ 0.85 $ 1.85 $ 1.68
======== ======== ======== ======== ======== ========
</TABLE>
Major components of the change in earnings per share from the same period of the
previous year are shown below:
<TABLE>
<CAPTION>
INCREASE (DECREASE) IN EARNINGS PER SHARE
--------------------------------------------
Three Months Six Months Twelve Months
Ended Ended Ended
June 30 June 30 June 30
1994 vs 1993 1994 vs 1993 1994 vs 1993
------------- ------------- --------------
<S> <C> <C> <C>
Core Utility Operations
Revenues, net of fuel expense
Rate increases $ 0.05 $ 0.17 $ 0.41
Sales volume and other 0.08 0.20 0.42
Operation and maintenance expense (0.03) (0.09) (0.23)
Depreciation (0.04) (0.07) (0.12)
Allowance for funds used during
construction (AFUDC) (0.02) (0.06) (0.12)
Effect of increased number of
average common shares (0.01) (0.04) (0.12)
Other 0.02 (0.02) (0.06)
------ ------ ------
0.05 0.09 0.18
Nonutility Subsidiaries (0.01) - (0.01)
------ ------ ------
$ 0.04 $ 0.09 $ 0.17
====== ====== ======
</TABLE>
CORE UTILITY EARNINGS
- ---------------------
Earnings per share from core utility operations increased by $0.05, $0.09, and
$0.18 for the three-, six-, and twelve-month periods ended June 30, 1994,
respectively, compared to the same periods last year. The increases in core
utility operating earnings for all three reporting periods were primarily due to
higher base electric revenues which resulted from increases in customer rates
and higher kilowatt-hour (kWh) sales. Electric sales benefited from favorable
weather conditions in both the summer cooling and winter heating seasons and
growth in the number of customers. The increase in base electric revenues was
partly offset in all three periods by higher non-fuel operating expenses, lower
AFUDC, and the dilutive effect on earnings per share of more common shares
outstanding.
-11-
<PAGE>
STRATEGIC PLANS AND COMPETITION
- -------------------------------
As previously disclosed under the "Competition" section of the Company's 1993
Annual Report on Form 10-K, the Company has developed strategic plans to address
anticipated operating cost increases and the expected loss of up to $24 million
in non-fuel revenue beginning in 1995 when the Company's largest resale customer
(ODEC) will start to purchase about one-half of its electricity from another
utility. The strategies are as follows: (1) reduce costs by $15 to $20
million; (2) increase revenues through $10 to $15 million of targeted price
increases; and (3) increase revenues by an additional $10 to $20 million through
short-term energy and capacity sales to regional utilities and additional retail
sales. These strategies are designed to aid the Company in achieving its goal
of earning a return on equity of at least 11.5%, while keeping prices
competitive, growing earnings, and protecting the current dividend level. Below
are updates to the discussion of these strategies previously disclosed in the
1993 Annual Report on Form 10-K.
COSTS
- -----
In April 1994, the Company announced that through a voluntary early retirement
option (ERO), the work force will be reduced by 7% to 10%. At the same time,
the Company initiated a review of work activities performed by employees
throughout the Company to identify areas where work can be reduced or eliminated
in order to capture the savings of the workforce reduction. The initial result
of this review shows that a workforce reduction of 7% to 10% can be achieved
while focusing employees on work that adds the most value to stockholders and
customers. Also, the Company has committed resources to review key business
processes performed by the Company on an on-going basis. These key business
process reviews will enable the Company to continuously evaluate the
effectiveness of work performed by employees to enhance the Company's
competitive position. The ERO is not expected to result in a material charge to
earnings because the Company plans to record a regulatory asset for the ERO
costs in accordance with SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation," consistent with past decisions by the commissions having
jurisdiction over the Company where similar costs were recovered in rates. The
Company plans to amortize the ERO costs to expense over five years beginning
January 1, 1995. The Company expects the annual cost savings from the ERO to be
from $13 to $17 million.
For 1995, the Company has established spending targets for both capital
additions of utility plant and operation and maintenance expenses. These
spending targets are designed to achieve the remainder of the cost reduction
strategy. Detailed budgets for 1995 are in the process of being developed to
conform to the spending targets.
REVENUES
- --------
During the second quarter of 1994, the Company notified the DPSC and MPSC of its
intent to request targeted or limited issue price increases totaling $10 to $15
million, or approximately 2% of current rates, to be effective in 1995. The
Company plans to seek recovery of costs primarily imposed by law related to the
1993 one-percent increase in the federal income tax rate, compliance with the
Clean Air Act Amendments of 1990, and nuclear decommissioning. The Company does
not plan to seek an increase in its allowed return on equity. The Company
expects to file for these limited issue rate increases in Delaware and Maryland
during the third quarter of 1994.
Also in the second quarter of 1994, the Company filed with the MPSC for approval
of a surcharge which would recover the cost of customer conservation programs,
$1.6 million of which has been deferred by the Company as of June 30, 1994. In
June 1994, the MPSC approved the surcharge.
-12-
<PAGE>
SALES
- -----
As discussed in Note 5 to the Consolidated Financial Statements on Page 7 and
Part II on Page 21, the Company entered into an agreement to purchase Conowingo
Power Company.
The Company's offer to purchase the electric system from the City of Dover,
Delaware (Dover) for $103.5 million remains outstanding. As an alternative, the
Company has held discussions with Dover concerning a long-term energy supply
contract. It is the Company's understanding that other parties have also had
discussions with Dover regarding the generation segment of Dover's business, but
none have shown interest in purchasing Dover's entire electric system.
In addition to growing the retail market share, the Company's strategy is to add
value by retaining profitable wholesale and large industrial customers. This
can be achieved through long-term energy supply contracts with customers who
have the option (under the National Energy Policy Act) to buy power elsewhere.
On June 30, 1994, the Company entered into an agreement with the Town of Smyrna,
Delaware (Smyrna) to provide the town's wholesale full requirements electric
service for a 20-year period. The Company also will perform certain new
services for Smyrna. Under the terms of the agreement, the initial wholesale
rates to Smyrna will be modestly discounted with future increases or decreases
based on the percentage change in base rates approved by the DPSC for the
Company's Delaware retail customers. This agreement with Smyrna requires the
approval of the FERC.
Delaware Municipal Electric Corporation (DEMEC) represents the Company's
Delaware municipal customers and Dover. The Delaware municipal customers have a
combined load of about 140 MW, or 6% of the Company's estimated 1995 firm load
of 2,287 MW. On May 26, 1994, DEMEC, excluding Dover, issued a request for
proposal (RFP) for firm supply of capacity and energy for a minimum term of 10
years. Twenty MW of DEMEC's RFP represents load not currently supplied by the
Company. The amounts and dates of the capacity and energy requirements in the
RFP reflect the termination notice provisions included in the settlement
agreement between the Company and the DEMEC customers in the resale base rate
case filed with the FERC on October 30, 1992, i.e., a two-year notice for up to
30% load reduction and a five-year notice for more than 30% load reduction.
Therefore, full capacity and energy requirements are not reached until the year
2000. On July 14, 1994, in response to the RFP, the Company submitted its
proposal to DEMEC to serve the requirements of the DEMEC members, excluding
Dover. Also, the Company is engaged in preliminary discussions with certain
DEMEC members individually either to purchase their electric systems or enter
into separate long-term power supply contracts similar to the Smyrna contract.
-13-
<PAGE>
ELECTRIC REVENUES AND SALES
- ---------------------------
Details of the changes in the various components of electric revenues are shown
below:
<TABLE>
<CAPTION>
INCREASE (DECREASE) IN ELECTRIC REVENUES
FROM COMPARABLE PERIOD IN PRIOR YEAR
-------------------------------------------
(Dollars in Millions)
Three Six Twelve
Months Months Months
------ ------- -------
<S> <C> <C> <C>
Non-fuel (Base Rate) Revenue
Increased Rates $ 4.5 $15.7 $36.4
Sales Volume and Other 5.3 13.6 33.0
Fuel Revenue (5.2) (6.9) (5.6)
Interchange Delivery Revenue (2.9) 11.8 29.6
----- ----- -----
Total $ 1.7 $34.2 $93.4
===== ===== =====
</TABLE>
ELECTRIC NON-FUEL (BASE RATE) REVENUE - INCREASED RATES
- -------------------------------------------------------
The electric non-fuel (base rate) revenue increases shown above as "Increased
Rates" are due to the following:
<TABLE>
<CAPTION>
ELECTRIC BASE RATE INCREASES
--------------------------------------------------------------
Annualized Base Effective
Jurisdiction Revenue Increase Date
------------ ---------------- ---------
<S> <C> <C>
Retail Electric
Delaware $24.9 million 06/01/93
Maryland (1) $ 7.8 million 04/01/93
Virginia $ 1.3 million 10/05/93
Resale (FERC) (2) $ 1.5 million 06/03/93
</TABLE>
(1) On a comparative basis, this rate increase contributed to the six-
and twelve-month revenue increases but had no effect on the three-
month revenue variance because the rate increase was effective
throughout the entire three month period for both 1994 and 1993.
(2) This rate increase is based on settlement agreements reached between
the Company and its resale customers. See Note 3 to the Consolidated
Financial Statements for further details.
-14-
<PAGE>
ELECTRIC NON FUEL (BASE RATE) REVENUE - SALES VOLUME AND OTHER
- --------------------------------------------------------------
Percentage changes in kWh sales billed by customer class are shown below:
<TABLE>
<CAPTION>
PERCENTAGE INCREASE (DECREASE) IN KWH SALES
FROM COMPARABLE PERIOD IN PRIOR YEAR
-----------------------------------------------------
Three Six Twelve
Customer Class Months Months Months
-------------- ------ ------ ------
<S> <C> <C> <C>
Residential - % 8.7 % 10.3 %
Commercial 4.0 6.2 6.6
Industrial 2.0 1.0 2.0
Resale, etc. 2.9 6.6 7.9
Total Billed Sales 2.2 5.6 6.6
Total Sales, including
Unbilled Sales 3.6 % 5.5 % 6.1 %
</TABLE>
Electric non-fuel revenues from "Sales Volume and Other" variances increased
$5.3 million for the three-month period, $13.6 million for the six-month period,
and $33.0 million for the twelve-month period due to increases in total kWh
sales of 3.6%, 5.5%, and 6.1%, respectively. For all three periods, increases
in residential, commercial, and resale kWh sales were largely due to weather
conditions involving a summer cooling season that was significantly hotter than
normal and the previous year and a winter heating season that was colder than
the previous year. Customer growth also contributed to increased residential
and commercial kWh sales for all three periods. The total number of electric
customers increased 2.1% for the twelve months ended June 30, 1994. Industrial
sales increased 2.0%, 1.0%, and 2.0% for the three-, six-, and twelve-month
periods, respectively, due to increased production levels of certain large
customers.
ELECTRIC FUEL REVENUE
- ---------------------
Electric fuel costs billed to customers, or fuel revenues, generally do not
affect net income since the expense recognized as fuel costs is adjusted to
match the fuel revenues. The amount of under- or over-recovered fuel costs is
deferred until it is subsequently recovered from or returned to utility
customers. For the three-, six-, and twelve-month periods, fuel revenues
decreased $5.2, $6.9, and $5.6 million, respectively, due to lower average fuel
rates charged to customers partially offset by higher kWh sales.
INTERCHANGE DELIVERY REVENUE
- ----------------------------
Interchange delivery revenues are reflected in the calculation of rates charged
to customers under fuel adjustment clauses and, thus, do not generally affect
net income. Interchange delivery revenues benefit customers by reducing the
effective cost of fuel billed to customers. For the three-month period,
interchange delivery revenues decreased $2.9 million primarily due to lower
sales to the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM)
which resulted from maintenance outages of certain generating plants that
typically provide a significant amount of deliveries to PJM. For the six- and
twelve-month periods, interchange delivery revenues increased $11.8 and $29.6
million, respectively, mainly due to higher sales to PJM which resulted from
increased demand for electricity in the region and greater availability of the
Company's generating units.
-15-
<PAGE>
GAS REVENUES, SALES, AND TRANSPORTATION
- ---------------------------------------
Details of the changes in the various components of gas revenues are shown
below:
INCREASE (DECREASE) IN GAS REVENUES
FROM COMPARABLE PERIOD IN PRIOR YEAR
------------------------------------
(Dollars in Millions)
<TABLE>
<CAPTION>
Three Six Twelve
Months Months Months
------ ------ ------
<S> <C> <C> <C>
Non-fuel (Base Rate) Revenue $ - $ 2.5 $ 0.8
Fuel Revenue 2.1 11.6 16.8
----- ----- -----
Total $ 2.1 $14.1 $17.6
===== ===== =====
</TABLE>
As shown above, higher fuel revenues were the main factor for increased gas
revenues in all three periods. Higher fuel revenues resulted primarily from
higher average fuel rates charged to customers. Increased firm gas sales also
contributed to higher fuel revenues for the six- and twelve-month periods.
The changes in non-fuel (base rate) revenues shown above resulted from the
various factors affecting the different types of sales classes. Firm sales,
which are impacted by weather and customer growth, are billed at higher rates
than non-firm (interruptible) sales and transported gas, which are impacted by
the production schedules and alternate fuel supplies of large industrial
customers. For the three months ended June 30, 1994, compared to the same
period last year, lower firm sales of 6%, due primarily to mild weather in
April, and significantly higher non-firm sales combined to result in a 2%
increase in total gas sold and transported but with no change in base revenues.
For the six months ended June 30, 1994, compared to the same period last year,
higher firm sales of 7%, primarily due to colder winter weather and customer
growth, were the main contributor to a 5% increase in total gas sold and
transported and higher base revenues of $2.5 million. For the twelve months
ended June 30, 1994, compared to the same period last year, higher firm sales of
2%, reflecting colder winter weather and customer growth, and significantly
lower gas transported combined to result in a 2% decrease in total gas sold and
transported, while base revenues increased $0.8 million.
ELECTRIC FUEL AND PURCHASED POWER EXPENSES
- ------------------------------------------
The components of the changes in electric fuel and purchased power expenses are
shown in the table below:
INCREASE (DECREASE) IN ELECTRIC FUEL AND
PURCHASED POWER FROM COMPARABLE PERIOD IN PRIOR YEAR
----------------------------------------------------
(Dollars in Millions)
<TABLE>
<CAPTION>
Three Six Twelve
Months Months Months
-------- ------- --------
<S> <C> <C> <C>
Average Cost of Electric Fuel
and Purchased Power $ (0.5) $ 6.9 ($ 5.3)
Increased (Decreased) kWh Output (0.3) 11.1 34.5
Deferral of Energy Costs (9.5) (15.3) (9.6)
------- ------ -------
Total ($10.3) $ 2.7 $ 19.6
======= ====== =======
</TABLE>
For the three-month period, the total decrease in electric fuel and purchased
power of $10.3 million primarily was due to the deferral of energy costs as
described more fully at the end of this section.
-16-
<PAGE>
For the six-month period, the "Average Cost of Electric Fuel and Purchased
Power" increased $6.9 million primarily due to the increased output from oil and
gas generating units, which have higher fuel costs then the system average, and
interchange and power purchases at rates substantially higher than last year.
An additional $11.1 million increase in electric fuel and purchased power
expenses resulted from higher kWh output from electric generating units. Output
rose due to greater electric sales demand in the Company's service territory and
increased interchange deliveries.
For the twelve-month period, the "Average Cost of Electric Fuel and Purchase
Power" decreased $5.3 million primarily due to a significant decrease in
interchange and purchased power, which have higher costs than the system
average, and increased output from coal units, which have lower fuel costs than
the system average. These factors were largely offset by the increased output
of oil and gas generating units. The variance in electric fuel and purchased
power for the twelve-month period also reflects a $34.5 million increase due to
higher kWh output from electric generating units for the same reasons as stated
above for the six-month period.
The kWh output required to serve load within the Company's service territory is
equivalent to total output less interchange deliveries. For the twelve months
ended June 30, 1994, the Company's output for load within the service territory
was provided by 46% coal generation, 14% nuclear generation, 31% oil and gas
generation, and 9% net purchased power, which consisted primarily of purchases
under the Company's agreement with PECO.
In comparison to the same periods last year, the "Deferred Energy Costs"
decreased by $9.5, $15.3, and $9.6 million for the three, six, and twelve
months, respectively. These decreases were the net results of the accrual and
amortization of deferred fuel costs in the Company's various regulatory
jurisdictions.
OPERATION, MAINTENANCE, AND DEPRECIATION EXPENSES
- -------------------------------------------------
For the three-, six-, and twelve-month periods ended June 30, 1994, compared to
the same periods a year ago, operation and maintenance expenses increased $2.9,
$7.9, and $21.0 million, respectively. The increases for all three periods were
due primarily to increased maintenance costs due to storm-related damage during
the first quarter of 1994, higher salaries and wages, and increased
postretirement benefits other than pensions due to the Company's adoption of
SFAS No. 106 beginning in 1993. The Company deferred the additional expense
attributed to SFAS No. 106 until the costs were reflected in rates on the dates
shown on page 14 for the electric business. The Company is continuing to defer
the additional expenses attributed to SFAS No. 106 related to the gas business
pending the effective date of the rates in the current gas base rate case.
Depreciation increased $3.9, $6.0, and $10.8 million for the three-, six-, and
twelve-month periods, respectively, mainly due to additions to the electric
system including Hay Road Unit No. 4 on June 1, 1993.
UTILITY FINANCING COSTS
- -----------------------
In comparison to the same periods last year, interest charges on debt of the
core utility decreased $1.2, $2.8, and $6.0 million for the three-, six-, and
twelve-month periods, respectively, mainly due to the redemption on June 1,
1993, of $50 million of 10% First Mortgage Bonds with a portion of the proceeds
from the March 1993 public offering of common stock. Interest savings from
refinancings of other long-term debt issues also contributed to the decreases.
-17-
<PAGE>
AFUDC decreased $1.3, $4.1, and $8.1 million for the three-, six-, and twelve-
month periods, respectively. The decreases were due to lower average
construction work-in-progress balances as a result of the completion of Hay Road
Unit No. 4 on June 1, 1993. For the twelve months ended June 30, 1994, AFUDC
was 3.4% of net income.
Due to increased common equity financing, the average number of shares of common
stock outstanding increased for the three-, six-, and twelve-month periods. The
additional shares outstanding decreased earnings per share by $0.01, $0.04, and
$0.12 for the three, six, and twelve month periods, respectively. Rates charged
to customers are designed to result in sufficient revenues to offset the
dilution of earnings per share due to increased common equity financing. This
result is reflected in operating results for all three periods ended June 30,
1994.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
The net cash provided by operating activities increased $11.6 million for the
six months ended June 30, 1994, compared to the same period last year mainly due
to higher sales to utility customers.
For the six months ended June 30, 1994, utility construction expenditures were
$64.5 million compared to $79.9 million for the same period last year.
Internally generated funds (net cash provided by operating activities less
common and preferred dividends) provided 85% of the cash required for
construction for the six months ended June 30, 1994, compared to 56% for the
same period last year. For the twelve months ended June 30, 1994, and June 30,
1993, utility construction expenditures were $144.6 and $192.1 million,
respectively. Internally generated funds provided 84% and 56% of the cash
required for construction during the twelve months ended June 30, 1994, and June
30, 1993, respectively. Lower construction expenditures for the six- and
twelve-month periods ended June 30, 1994, as compared to the prior year periods
reflect lower budgeted capital expenditures.
During the six months ended June 30, 1994, the Company's term loan balance
increased by $10.5 million. Also during this period, $15.0 million of common
stock was issued primarily through the Company's DRIP. As of June 1, 1994, cash
was no longer being provided through the DRIP because the plan began acquiring
shares through purchase on the open market rather than through the issuance of
new shares.
RATIO OF EARNINGS TO FIXED CHARGES
- ----------------------------------
<TABLE>
<CAPTION>
12 Months
Ended Year Ended December 31,
June 30, ----------------------------------------
1994 1993 1992 1991 1990 1989
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed Charges
(SEC Method)....................... 3.81X 3.47X 3.03X 2.58X 2.03X 3.01X
</TABLE>
Under the SEC Method, earnings, including AFUDC, have been computed by adding
the amount of income taxes and fixed charges to net income. Fixed charges
include gross interest expense and the estimated interest component of rentals.
Excluding the write-off of an investment in certain non-regulated subsidiary
projects, the ratio of earnings to fixed charges for the year ended December 31,
1990, would be 2.89X. Net income and income
-18-
<PAGE>
taxes related to the cumulative effect of a change in accounting for unbilled
revenues recorded in 1991 are excluded from the computation of this ratio.
Excluding the gain from the Company's share of a settlement reached in the
lawsuit against PECO in connection with the shutdown of Peach Bottom, the ratio
of earnings to fixed charges for the year ended December 31, 1992, would be
2.78X.
CHALLENGE 2000 UPDATE
- ---------------------
Each year, the Company updates its Challenge 2000 plan to identify the best way
to meet its customers' energy needs in the next 10 years. While the updated
plan features the balance and flexibility of previous plans, it concludes that
the Company can serve customers reliably and economically without making
commitments to large investments in new power plants and new demand-side
programs during the next two years. The Company's ability to limit long-term
commitments will keep cash flow in balance with construction expenditures and
hold capital requirements down.
Under this updated plan, in the next 10 years, the Company expects to:
. Expand its existing demand-side management (conservation and load
management) programs
. Consider improving its transmission system to allow more short-term power
purchases from other utilities
. Repower two generating units at the Indian River power plant
. Scale down the Delaware Clean Energy Project (DCEP) and defer the project
until the year 2000
. Build a combustion turbine in 2002 in the southern part of our service area
. Build a pulverized coal-fueled unit in 2004
If the short-term power purchases are not available in the next few years, the
Company may need to bring the combustion turbine and coal unit on line sooner
than anticipated.
ENERGY SUPPLY
- -------------
A peak load of 2,551 MW was reached on July 8, 1994, that exceeded the Company's
historical peak load of 2,544 MW, which occurred on July 9, 1993. Both of these
peaks were established under weather conditions which were more severe than
normal. In addition, neither peak reflects the full implementation of the
Company's demand-side management programs. When the 1994 load is adjusted for
abnormal weather conditions, expected seasonal variations, and the full
implementation of the Company's demand-side management programs (which total
approximately 237 MW), it is expected to closely approximate the projected peak
of 2,381 MW. The Company's peak load is adjusted to reflect normal weather
conditions and full implementation of demand-side management programs to
determine the Company's capacity obligations with PJM.
-19-
<PAGE>
NONUTILITY SUBSIDIARIES
- -----------------------
Information on the Company's nonutility subsidiaries, in addition to the
following discussion, can be found in Note 8 to the Consolidated Financial
Statements.
For the three-month periods ended June 30, 1994, and 1993, nonutility subsidiary
earnings per share were $0.01 and $0.02, respectively. Nonutility subsidiary
earnings per share were $0.03 in both the six-month periods ended June 30, 1994,
and 1993. For the twelve-month periods ended June 30, 1994, and 1993,
nonutility subsidiary earnings were $0.03 and $0.04, respectively.
All three prior year reporting periods (three, six, and twelve months ended June
30, 1993) included gains on the sale of interests in leveraged leases, which had
the effect of lowering normal operating leveraged lease income in all three
current year reporting periods (three, six, and twelve months ended June 30,
1994). All three current year reporting periods reflect gains on the sale of
real estate, improved operating results from the waste hauling and landfill
business, and lower administrative and general costs. The six- and twelve-month
current year reporting periods also reflect the recovery of previously written-
off joint venture assets.
-20-
<PAGE>
PART II. OTHER INFORMATION
--------------------------
ITEM 1. LEGAL PROCEEDINGS
- --------------------------
Refer to Note 6 to the Consolidated Financial Statements for updated information
concerning the complaint filed by Star against the Company in December 1993.
As previously reported on page I-23 of the Company's 1993 Annual Report on Form
10-K, the Company has been involved in two cases involving the Delaware Coastal
Zone Industrial Control Board (the "Board") regarding regulations (the
"Regulations") the Board adopted in June 1993 under Delaware's Coastal Zone Act.
In one case, the Company and certain other parties filed a complaint in the
Delaware Superior Court seeking to have the Regulations declared null and void.
In the other case, the Company joined with other affected parties in filing a
complaint in the Delaware Chancery Court. The Chancery Court complaint alleged
procedural violations of the Freedom of Information Act by the Board in the
passage of the Regulations and requested that the Regulations be declared null
and void. The proceedings in the Superior Court were suspended pending the
outcome of the Chancery Court case. On May 19, 1994, the Chancery Court found
for the Company and the other plaintiffs by declaring the Regulations null and
void on procedural grounds. It is expected that the proceedings in the Superior
Court will be further suspended pending the issuance of new regulations by the
Board.
ITEM 5. OTHER INFORMATION
- --------------------------
A) Purchase of COPCO
-----------------
On May 24, 1994, the Company entered into an agreement with PECO to buy its
Maryland retail electric subsidiary, COPCO, for $150 million. The COPCO
purchase will result in approximately 35,000 new electric retail customers or 9%
of the Company's current customer base. This purchase reflects the Company's
focus on growing the Company's retail market share as previously disclosed under
the "Competition" section of the Company's 1993 Annual Report on Form 10-K.
On May 24, 1994, the Company also entered into an agreement with PECO to
purchase electric capacity and energy from the PECO system. Under the terms of
this agreement, the Company will buy capacity and energy from PECO beginning on
the later of the closing date of the COPCO acquisition or February 1, 1996, and
ending May 31, 2006. The base amount of purchased capacity will start at 205 MW
and will increase annually to 259 MW in the final year of the contract, subject
to certain provisions that allow PECO to increase the capacity by up to 20 MW or
decrease the capacity by up to 50 MW after June 1, 1998. Over the life of the
power purchase agreement, costs to buy power from PECO are expected to lower the
Company's average cost of electricity. The agreement will enable the Company to
serve the 165 to 220 MW needed for COPCO from 1996 through 2006 and use the
additional capacity and energy in the Company's total power supply mix. The
Company expects to use energy purchased from PECO in place of higher cost
energy. The power purchase agreement also helps the Company avoid having to
build higher cost capacity in the next few years. The Company also has agreed to
continue PECO's present COPCO power supply agreement on an interim basis until
February 1, 1996 if the closing date of the COPCO acquisition should occur prior
to that date.
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<PAGE>
The Company believes that, over the long term, the COPCO purchase will increase
earnings available for common stock. The Company expects some contribution to
earnings in 1996, rising to $0.04 to $0.06 per share in 1997. However, during
the first year of operations, revenues from former COPCO customers will be
offset by operating and financing costs as well as the effect of additional
common shares to be issued as part of the financing of the acquisition.
The acquisition of COPCO by the Company and the related power supply agreements
are subject to certain state and federal regulatory approvals. The Company
expects to receive these approvals in 1995. The Company has reached a
settlement in principle with the interested parties in Maryland. The
settlement, as proposed, would permit recovery of an acquisition premium over 20
years with an allowed return on equity of 11.5% starting in 1997. Additionally,
a deferred asset representing costs, to be collected pursuant to a rate phase-in
plan, of about $25 million on COPCO's balance sheet, would be collected over
about 10 years with a carrying charge starting in 1996.
The Company plans to ultimately finance the acquisition with approximately 50%
long-term debt and 50% common stock. Short-term/bridge financing may be used
until permanent financing is arranged. The Company also is considering using
the DRIP to issue the common stock financing the acquisition. Such issuances
would take approximately two years from the closing of the acquisition. The
acquisition of COPCO will not materially change the Company's capital structure.
B) Peach Bottom Atomic Power Station
---------------------------------
SALP Report
-----------
On June 29, 1994, the Nuclear Regulatory Commission (NRC) issued its initial
Systematic Assessment of Licensee Performance (SALP) Report on the performance
of activities of Peach Bottom for the period November 1, 1992, to April 30,
1994. This SALP was conducted under the revised process that was implemented by
the NRC in July 1993. The revised SALP process consolidates the seven
functional areas previously rated into four areas. The numeric rating criteria
remains unchanged with "1" being the highest rating and "3" the lowest rating,
although still acceptable. Under the recent SALP, Peach Bottom earned a rating
of "1" in Operations and a rating of "2" in each of the other three areas:
Engineering, Maintenance, and Plant Support. The NRC noted continued
improvement in performance at Peach Bottom as well as some areas that require
continued management attention.
Boiling Water Reactor Issue
---------------------------
PECO has informed the Company that in October 1990, General Electric Company
(GE) reported that crack indications were discovered near the seam welds of the
core shroud assembly in a GE Boiling Water Reactor (BWR) located outside the
United States. As a result, GE issued a letter requesting that the owners of GE
BWR plants take interim corrective actions, including a review of fabrication
records and visual examinations of accessible areas of the core shroud seam
welds. Peach Bottom Unit No. 3 was examined in October 1993 during the last
refueling outage and crack indications were identified at two locations. On
November 3, 1993, PECO presented its findings to the NRC and provided
justification for continued operation of Unit No. 3 for another two-year cycle
with crack indications. Initial examinations for Peach Bottom Unit No. 2 are
planned for its next scheduled refueling outage in September 1994. PECO is
participating in a GE BWR Owners Group to evaluate this issue and develop long-
term corrective actions.
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<PAGE>
C) Salem Nuclear Generating Station
--------------------------------
Unit No. 1 Outage
-----------------
As previously reported on page 16 of the Company's Report on Form 10-Q for the
first quarter of 1994, on April 7, 1994, a series of problems occurred at Salem
Unit No. 1 which resulted in a shutdown of the unit and declaration of an alert.
The unit returned to service on June 4, 1994. PSE&G has informed the Company
that PSE&G is continuing to address matters to improve Salem's operations
identified by itself, the NRC, and the Institute of Nuclear Power Operations
(INPO), an independent industry group consisting of utilities, including PSE&G,
that provides self-critical analysis of nuclear operations to member utilities.
Actions are being taken to improve the plant's material condition, to upgrade
procedures, and to enhance personnel performance, as well as other efforts.
However, satisfactory operating performance on Salem Unit No. 1 has not yet been
achieved, and the April 7, 1994, event indicates that to date, the corrective
actions taken by PSE&G to address these long-standing problems have not been
fully effective, and that material condition deficiencies continue to complicate
plant recovery from transients which place reliance on operator action to
mitigate the consequences of the events. On July 6, 1994, the NRC notified
PSE&G of six apparent violations associated with the event which were being
considered for escalated enforcement: control room command function; failure to
identify and correct pre-existing equipment deficiencies; communication of
specific information to the NRC at initial declaration; sufficiency of
procedural guidance for coping with transients and abnormal plant conditions;
adequate measures for identification and control of parts and components; and
technical specification time requirements for cooldown. An enforcement
conference to discuss PSE&G's view of the apparent violations was held on July
28, 1994, at NRC Region 1 headquarters, at which time the NRC staff expressed
its view that PSE&G had not made significant progress in correcting identified
deficiencies. The results of the enforcement conference and final determination
of the apparent violations are expected within two months. PSE&G cannot predict
what action, if any, may be taken by the NRC.
PSE&G's own assessments, as well as those by the NRC and INPO, indicate that
additional efforts are required to further improve operating performance, and
PSE&G is committed to taking the necessary actions to address Salem's
performance needs. However, no assurance can be given as to what, if any,
further or additional actions may be taken by PSE&G, or required by the NRC, to
improve Salem's performance.
Operating Permit
----------------
As previously reported on page I-18 of the Company's 1993 Annual Report on Form
10-K, in June 1993, the New Jersey Department of Environmental Protection and
Energy (NJDEPE) issued a revised draft permit that would permit Salem to
continue to operate with once-through cooling and would require PSE&G to make
certain plant modifications and to undertake various measures to protect and
enhance aquatic life in the Delaware Bay. PSE&G has informed the Company that
on July 20, 1994, the NJDEPE issued a final five-year permit, effective
September 1, 1994, with essentially the same provisions as the revised draft
permit. The revised draft permit had been opposed by various environmental
groups and PSE&G cannot predict whether any appeals of the final permit will be
filed. The EPA has authority to review the issuance of the final permit issued
by the NJDEPE. Additional permits from various agencies will be required for
implementation of certain of the measures required under the permit, as to which
no assurances can be given. The Company's share of the capital cost of
complying with the conditions of the final permit is not expected to be
material.
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<PAGE>
Reracking Project
-----------------
As previously reported on page I-9 of the Company's 1993 Form 10-K, the Company
has been informed by PSE&G that PSE&G has developed a strategy to meet the
longer-term, spent-fuel storage needs for Salem. In May 1994, PSE&G received a
license from the NRC to replace the existing high-density racks in the spent-
fuel storage pools of Salem Unit Nos. 1 and 2 with maximum-density racks. The
Salem reracking project is ongoing and is expected to extend the storage
capability of Salem Unit No. 1 through March 2008 and Salem Unit No. 2 through
March 2012, considering operational full core discharge requirements.
D) Delaware Task Force on Regulation
---------------------------------
As previously reported on page 17 of the Company's Form 10-Q for the first
quarter of 1994, in May 1994 a task force issued a preliminary report to the
Governor of Delaware recommending certain improvements to the existing
regulatory process in Delaware. In June 1994, the task force issued its final
report which maintained the same recommendations as the preliminary report. In
addition, the task force recommended that the DPSC Staff, Office of the Public
Advocate, utilities, and other interested parties submit annual progress reports
to the DPSC citing any advances and cost savings achieved and setbacks
experienced toward fully implementing the task force's recommendations. It is
anticipated that the Governor will support these recommendations and present
them to the General Assembly in the 1995 session.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
- -----------------------------------------
A) Exhibits
--------
Exhibit 12, Computation of Ratio of Earnings to Fixed Charges.
B) Reports on Form 8-K
-------------------
A copy of the Company's press release announcing that the Company had entered
into a stock purchase agreement to acquire COPCO was filed as a Report on Form
8-K dated May 25, 1994.
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<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: August 15, 1994 /s/ B. S. Graham
--------------- ----------------
B. S. Graham, Vice President and
Chief Financial Officer
-25-
<PAGE>
EXHIBIT INDEX
-------------
Exhibit Page
Number Number
------- ------
Computation of ratio of earnings to fixed charges 12 27
-26-
<PAGE>
Exhibit 12
Delmarva Power & Light Company
Ratio of Earnings to Fixed Charges
----------------------------------
(Dollars in Thousands)
<TABLE>
<CAPTION>
12 Months Ended
-------------------
6/30/94 12/31/93
-------- --------
<S> <C> <C>
Net income $118,321 $111,076
-------- --------
Income taxes 78,405 67,102
-------- --------
Fixed charges:
Interest on long-term debt including amor-
tization of discount, premium and expense 60,744 62,651
Other interest 9,074 9,245
-------- --------
Total fixed charges 69,818 71,896
-------- --------
Nonutility capitalized interest (271) (246)
-------- --------
Earnings before income taxes
and fixed charges $266,273 $249,828
======== ========
Ratio of earnings to fixed charges 3.81 3.47
</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, plus the interest factor associated with the Company's major
leases, and one-third of the remaining annual rentals.
-27-
