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, 1995
----------------------------------------------
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 302-429-3359
------------
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, 1995
- ------------------------------ -----------------------------
Common Stock, $2.25 par value 60,447,418 Shares
DELMARVA POWER & LIGHT COMPANY
------------------------------
Table of Contents
-----------------
Page No.
--------
Part I. Financial Information:
Consolidated Balance Sheets as of June 30, 1995
and December 31, 1994................................. 2-3
Consolidated Statements of Income for the three, six,
and twelve months ended June 30, 1995 and 1994........ 4
Consolidated Statements of Cash Flows for the six
and twelve months ended June 30, 1995 and 1994........ 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................... 11-16
Part II. Other Information and Signature......................... 17-23
-1-
PART I. FINANCIAL INFORMATION
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
June 30, December 31,
1995 1994
----------- -----------
(Unaudited)
ASSETS
------
UTILITY PLANT, AT ORIGINAL COST:
Electric.......................................... $2,912,643 $2,676,871
Gas............................................... 203,016 196,188
Common............................................ 128,773 120,933
---------- -----------
3,244,432 2,993,992
Less: Accumulated depreciation................... 1,137,581 1,062,565
---------- -----------
Net utility plant in service...................... 2,106,851 1,931,427
Construction work-in-progress..................... 64,024 85,220
Leased nuclear fuel, at amortized cost............ 28,315 30,349
---------- -----------
2,199,190 2,046,996
---------- -----------
INVESTMENTS AND NONUTILITY PROPERTY:
Investment in leveraged leases.................... 48,691 49,595
Funds held by trustee............................. 29,920 32,824
Other investments and nonutility property, net.... 55,742 57,289
---------- -----------
134,353 139,708
---------- -----------
CURRENT ASSETS:
Cash and cash equivalents......................... 33,599 25,029
Accounts receivable:
Customers..................................... 93,350 93,739
Other......................................... 12,008 15,144
Inventories, at average cost:
Fuel (coal, oil, and gas)..................... 34,108 48,262
Materials and supplies........................ 39,077 37,055
Prepayments....................................... 3,909 9,014
Deferred income taxes, net........................ 13,311 9,276
---------- -----------
229,362 237,519
---------- -----------
DEFERRED CHARGES AND OTHER ASSETS:
Unamortized debt expense.......................... 12,246 11,387
Deferred debt refinancing costs................... 25,275 26,530
Deferred recoverable plant costs.................. 10,874 12,693
Deferred recoverable income taxes................. 150,227 149,206
Other............................................. 52,197 45,746
---------- -----------
250,819 245,562
---------- -----------
TOTAL ASSETS $2,813,724 $2,669,785
========== ===========
See accompanying Notes to Consolidated Financial Statements.
- 2 -
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
June 30, December 31,
1995 1994
----------- -----------
(Unaudited)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stock...................................... $135,422 $133,970
Additional paid-in capital........................ 495,517 484,377
Retained earnings................................. 270,739 267,002
Unearned compensation............................. (2,012) (1,180)
---------- -----------
Total common stockholders' equity............. 899,666 884,169
Preferred stock................................... 168,085 168,085
Long-term debt.................................... 879,523 774,558
---------- -----------
1,947,274 1,826,812
---------- -----------
CURRENT LIABILITIES:
Short-term debt................................... 22,201 10,000
Long-term debt due within one year................ 1,440 1,399
Variable rate demand bonds........................ 71,500 71,500
Accounts payable.................................. 47,138 59,596
Taxes accrued..................................... 7,046 7,264
Interest accrued.................................. 15,742 15,459
Dividends declared................................ 23,277 22,831
Current capital lease obligation.................. 12,601 12,571
Deferred energy costs............................. 25,317 12,241
Other............................................. 40,547 27,538
---------- -----------
266,809 240,399
---------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes, net........................ 507,323 505,435
Deferred investment tax credits................... 46,260 47,577
Long-term capital lease obligation................ 17,516 19,660
Other............................................. 28,542 29,902
---------- -----------
599,641 602,574
---------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $2,813,724 $2,669,785
========== ===========
See accompanying Notes to Consolidated Financial Statements.
- 3 -
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
(Unaudited)
-----------
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
------------------ --------------------- --------------------
1995 1994 1995 1994 1995 1994
-------- -------- -------- -------- -------- --------
OPERATING REVENUES $192,359 $197,934 $407,768 $440,687 $850,195 $909,825
Electric..............................................
Gas................................................... 20,869 20,531 63,060 70,172 100,794 108,996
-------- -------- -------- -------- -------- --------
213,228 218,465 470,828 510,859 950,989 1,018,821
-------- -------- -------- -------- -------- --------
OPERATING EXPENSES
Electric fuel and purchased power..................... 56,807 58,221 130,688 146,715 266,542 301,004
Gas purchased......................................... 12,679 13,022 35,766 42,721 56,859 65,203
Operation and maintenance............................. 61,092 65,201 114,730 123,084 258,853 255,911
Depreciation.......................................... 27,358 27,220 54,241 53,871 109,893 106,933
Taxes other than income taxes......................... 8,832 8,982 18,899 19,711 37,773 38,778
Income taxes.......................................... 12,282 11,825 34,074 36,993 63,247 76,606
-------- -------- -------- -------- -------- --------
179,050 184,471 388,398 423,095 793,167 844,435
-------- -------- -------- -------- -------- --------
OPERATING INCOME........................................ 34,178 33,994 82,430 87,764 157,822 174,386
-------- -------- -------- -------- -------- --------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains.................................. 13,025 10,801 25,456 20,790 47,809 42,027
Expenses including interest and income taxes........ (12,435) (10,199) (22,967) (18,896) (44,862) (40,287)
-------- -------- -------- -------- -------- --------
Net earnings of nonutility subsidiaries........ 590 602 2,489 1,894 2,947 1,740
Allowance for equity funds used during construction... 187 1,019 371 1,725 2,035 2,971
Other income, net of income taxes..................... 262 63 648 (1,027) 1,390 (170)
-------- -------- -------- -------- -------- --------
1,039 1,684 3,508 2,592 6,372 4,541
-------- -------- -------- -------- -------- --------
INCOME BEFORE UTILITY INTEREST CHARGES.................. 35,217 35,678 85,938 90,356 164,194 178,927
-------- -------- -------- -------- -------- --------
UTILITY INTEREST CHARGES
Interest expense...................................... 16,318 15,416 32,172 30,824 63,424 62,291
Allowance for borrowed funds used during
construction........................................ (545) (514) (1,086) (885) (1,975) (1,685)
-------- -------- -------- -------- -------- --------
15,773 14,902 31,086 29,939 61,449 60,606
-------- -------- -------- -------- -------- --------
NET INCOME.............................................. 19,444 20,776 54,852 60,417 102,745 118,321
DIVIDENDS ON PREFERRED STOCK............................ 2,482 2,323 5,001 4,587 9,784 9,607
-------- -------- -------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK..................... $16,962 $18,453 $49,851 $55,830 $92,961 $108,714
======== ======== ======== ======== ======== ========
COMMON STOCK
Average shares outstanding (000)...................... 60,109 59,402 59,923 59,212 59,733 58,871
Earnings per average share............................ $0.28 $0.31 $0.83 $0.94 $1.56 $1.85
Dividends declared per share.......................... $0.38 1/2 $0.38 1/2 $0.77 $0.77 $1.54 $1.54
See accompanying Notes to Consolidated Financial Statements.
- 4 -
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
-----------
Six Months Ended Twelve Months Ended
June 30 June 30
---------------------- ----------------------
1995 1994 1995 1994
-------- -------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $54,852 $60,417 $102,745 $118,321
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization.......................... 59,256 59,422 120,637 117,154
Allowance for equity funds used during construction.... (371) (1,725) (2,035) (2,971)
Investment tax credit adjustments, net................. (1,317) (1,257) (1,958) (2,515)
Deferred income taxes, net............................. (3,170) 1,749 (90) 12,065
Provision for early retirement offer................... - - 17,500 -
Net change in :
Accounts receivable.................................. 11,873 5,926 13,927 (8,431)
Inventories.......................................... 12,659 (4,130) (3,506) 7,713
Accounts payable..................................... (12,694) (13,879) 5,496 1,656
Other current assets & liabilities*.................. 19,350 299 8,330 (17,278)
Other,net.............................................. (2,330) (2,264) (3,348) (4,266)
-------- -------- -------- --------
Net cash provided by operating activities..................... 138,108 104,558 257,698 221,448
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures, excluding AFUDC................ (55,433) (64,519) (145,033) (144,597)
Allowance for borrowed funds used during construction..... (1,086) (885) (1,975) (1,685)
Acquisition of COPCO, net of cash acquired................ (148,837) - (148,837) -
Cash flows from leveraged leases:
Sale of interests in leveraged lease................... - - - 7,015
Other.................................................. 2,420 1,044 2,968 1,567
Proceeds from sale of subsidiary property................. - - 4,596 -
Investment in subsidiary projects and operations.......... (1,025) (2,399) (9,671) (3,155)
(Increase)/decrease in bond proceeds held in trust funds.. 4,971 7 (6,852) 25,529
Deposits to nuclear decommissioning trust funds........... (1,493) (1,260) (2,671) (2,356)
Other, net................................................ (802) (3,527) 389 (925)
-------- -------- -------- --------
Net cash used by investing activities......................... (201,285) (71,539) (307,086) (118,607)
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends: Common...................................... (45,870) (45,377) (91,668) (90,278)
Preferred................................... (4,800) (4,654) (9,610) (9,655)
Issuances: Long-term debt.............................. 125,800 - 130,440 90,000
Variable rate demand bonds.................. - - 30,000 15,500
Common stock................................ 12,624 14,974 12,624 30,235
Preferred stock............................. - - - 20,000
Redemptions: Long-term debt.............................. (566) (397) (26,265) (134,225)
Variable rate demand bonds.................. - - - (15,500)
Common stock................................ (1,253) (794) (1,253) (799)
Preferred stock............................. - - - (28,280)
Principal portion of capital lease payments............... (5,015) (5,551) (10,744) (10,221)
Net change in term loan................................... (20,226) 10,500 4,274 20,500
Net change in short-term debt ............................ 12,201 - 22,201 -
Cost of issuances and refinancings........................ (1,148) (137) (1,612) (5,787)
-------- -------- -------- --------
Net cash provided/(used) by financing activities.............. 71,747 (31,436) 58,387 (118,510)
-------- -------- -------- --------
Net change in cash and cash equivalents....................... 8,570 1,583 8,999 (15,669)
Cash and cash equivalents at beginning of period.............. 25,029 23,017 24,600 40,269
-------- -------- -------- --------
Cash and cash equivalents at end of period.................... $33,599 $24,600 $33,599 $24,600
======== ======== ======== ========
*Other than debt classified as current and current deferred income taxes.
See accompanying Notes to Consolidated Financial Statements.
-5-
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 1994 Annual
Report to Stockholders, the Company's Report on Form 10-Q for the first
quarter of 1995, and Part II of this Report on Form 10-Q for additional
relevant information.
2. BASE RATE MATTERS
-----------------
In 1994, the Company filed an application with the Maryland Public Service
Commission (MPSC) for a $3.9 million increase in electric base rates to
recover the costs of "limited issues." In April 1995, the MPSC denied the
Company's application to increase rates and subsequently instituted a new
proceeding to examine the reasonableness of the Company's existing base
rates. On May 30, 1995, the MPSC approved a settlement agreement between the
Company, MPSC Staff, and Maryland People's Council which terminated the base
rate inquiry.
3. COPCO ACQUISITION
-----------------
On June 19, 1995, the Company acquired Conowingo Power Company (COPCO), the
Maryland retail electric subsidiary of PECO Energy Company (PECO), for $150
million plus a final payment amount to be determined primarily based on
COPCO's actual working capital as of June 19, 1995. As disclosed in Note 5,
the Company financed the $150 million acquisition payment with $125.8 million
of long-term debt and $24.2 million of short-term debt which the Company
intends to refinance with long-term securities. The acquisition resulted in
approximately 35,000 new electric retail customers, which represents 9% of
the Company's current customer base.
The acquisition has been accounted for as a purchase. Immediately after the
acquisition, COPCO was merged into the Company and is now being operated as
the Conowingo District. Operating results of the Conowingo District have
been included in the Consolidated Statements of Income since June 19, 1995.
Pro forma results of the Company, assuming the acquisition had taken place at
the beginning of each period presented, would not be materially different
from the results reported.
Under FERC requirements, the COPCO assets have been recorded at their net
book value, primarily reflecting electric plant of $107.7 million and related
accumulated depreciation of $31.7 million. The difference between the amount
paid to PECO, including an estimate of the final payment amount, and the net
book value of the COPCO assets, or approximately $75 million, has been
recorded as goodwill and is included in electric utility plant. The MPSC has
approved recovery of this goodwill through Maryland retail rates in two
components. Approximately $49 million of the goodwill will be recovered as
an acquisition adjustment with a carrying charge over 20 years beginning at
the time of the Company's next Maryland base rate case. The remaining $26
million will be recovered with a carrying charge over approximately 10 years
via a pre-approved surcharge to the Company's existing Maryland Retail rates
which will be placed in effect for Conowingo District customers beginning
February 1, 1996. For financial statement purposes, the goodwill will be
amortized on a straight-line basis over 40 years beginning July 1995.
-6-
In conjunction with the acquisition, the Company signed a contract with PECO
to purchase electric capacity and energy from the PECO system beginning
February 1, 1996, and ending May 31, 2006. The base amount of the capacity
purchase, which is subject to certain possible adjustments, will start at 205
megawatts (MW) and will increase annually to 259 MW in 2006. Under another
contract, the Company agreed to purchase the Conowingo District's electric
power requirements from PECO from the acquisition date until February 1,
1996. Please refer to Note 13 to the Consolidated Financial Statements in
the 1994 Annual Report to Stockholders for information concerning commitments
related to these contracts.
4. COMMON STOCK
------------
During the first six months of 1995, the Company issued 644,283 shares of
common stock for $12,624,000 primarily through the Dividend Reinvestment and
Common Share Purchase Plan (DRIP). As of June 30, 1995, 60,186,289 shares of
common stock were outstanding.
5. DEBT
----
On June 19, 1995, the Company issued the following debt to finance the $150
million acquisition of COPCO:
- $100 million of First Mortgage Bonds, Series I, 7.71% Bonds due June 1,
2025;
- $25.8 million of First Mortgage Bonds, Series I, 6.95% Amortizing Bonds
due June 1, 2008, with principal installments payable each year beginning
June 1, 1997 and continuing through June 1, 2008; and
- $24.2 million of short-term debt classified as long-term due to the
Company's intention to refinance the entire amount on a long-term basis as
supported by $130 million in revolving/term loan credit agreements.
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 power industry to pay
such claims.
The co-owners of the Peach Bottom Atomic Power Station (Peach Bottom) and
Salem Nuclear Generating Station (Salem) maintain nuclear property damage
and decontamination insurance in the aggregate amount of $2.8 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 $4.7 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.
-7-
Environmental Matters
- ---------------------
As previously disclosed under "Hazardous Substances" on page I-20 of the
Company's 1994 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 at two federal
superfund sites and is alleged to be a third-party contributor at two other
federal superfund sites. The Company also has three former coal
gasification sites which are state superfund sites. The Company is
currently participating with the State of Delaware in evaluating two of the
three sites to assess the extent of contamination and risk to the
environment. In 1994, the Company accrued a liability of $2 million
representing its estimate of site study and cleanup costs for all of its
federal and state superfund sites.
Other
- -----
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
----------------------------------
Six Months Ended Twelve Months Ended
June 30, June 30,
------------------ -------------------
(Dollars in Thousands) 1995 1994 1995 1994
-------- -------- -------- --------
Cash paid for
Interest, net of amounts
capitalized $29,363 $28,231 $58,969 $57,137
Income taxes, net of refunds $41,472 $37,925 $71,379 $76,364
-8-
8. NONUTILITY SUBSIDIARIES
-----------------------
The following presents condensed financial information of the Company's
nonregulated wholly-owned subsidiaries: Delmarva Capital Investments, Inc.;
Delmarva Energy Company; and Delmarva Industries, 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.
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
------------------ ---------------- -------------------
(Dollars in Thousands) 1995 1994 1995 1994 1995 1994
------- ------- ------- ------- ------- -------
Revenues and Gains
Landfill and waste hauling $ 3,593 $ 3,661 $ 6,775 $ 6,442 $14,519 $13,149
Operating services 7,414 5,875 13,179 10,599 25,048 22,607
Other revenues 345 1,021 710 2,699 2,934 4,318
Leveraged leases 1,422 63 1,516 116 1,673 298
Other investment income 251 181 3,276 934 3,635 1,655
------- ------- ------- ------- ------- -------
13,025 10,801 25,456 20,790 47,809 42,027
------- ------- ------- ------- ------- -------
Cost and Expenses
Operating expenses 12,012 9,784 21,423 17,625 42,284 37,769
Interest expense, net 71 6 145 20 496 -
Income taxes 352 409 1,399 1,251 2,082 2,518
------- ------- ------- ------- ------- -------
12,435 10,199 22,967 18,896 44,862 40,287
------- ------- ------- ------- ------- -------
Net income $ 590 $ 602 $ 2,489 $ 1,894 $ 2,947 $ 1,740
======= ======= ======= ======= ======= =======
Earnings per share of common
stock attributed to subsidiaries $0.01 $0.01 $0.04 $0.03 $0.05 $0.03
-9-
SELECTED FINANCIAL AND OPERATING DATA
-------------------------------------
(Dollars in Thousands)
3 Months Ended 6 Months Ended 12 Months Ended
June 30 June 30 June 30
----------------------- ----------------------- -----------------------
1995 1994 1995 1994 1995 1994
---------- ---------- ---------- ---------- ---------- ----------
Electric Revenues
- -----------------
Residential $65,320 $63,216 $149,911 $155,964 $306,170 $319,337
Commercial 59,947 56,620 118,748 116,119 245,135 244,026
Industrial 36,847 35,586 72,911 70,372 148,133 148,796
Resale 10,572 22,887 26,670 52,436 79,584 107,513
Other Sales Revenues (1) 5,767 7,798 3,942 5,076 5,682 8,390
---------- ---------- ---------- ---------- ---------- ----------
Sales Revenues 178,453 186,107 372,182 399,967 784,704 828,062
Interchange Deliveries 10,929 9,804 29,802 36,764 55,426 73,189
Miscellaneous Revenues 2,977 2,023 5,784 3,956 10,065 8,574
---------- ---------- ---------- ---------- ---------- ----------
Total Electric Revenues $192,359 $197,934 $407,768 $440,687 $850,195 $909,825
========== ========== ========== ========== ========== ==========
Electric Sales
- --------------
(1000 kWh)
Residential 710,698 699,328 1,750,702 1,876,145 3,453,300 3,649,096
Commercial 832,249 796,587 1,709,908 1,688,736 3,482,230 3,435,815
Industrial 801,694 801,563 1,602,739 1,572,630 3,278,240 3,247,472
Resale 215,755 475,237 535,997 1,071,758 1,630,393 2,198,839
Other sales (2) 30,272 69,867 (16,915) 4,513 29,568 74,867
---------- ---------- ---------- ---------- ---------- ----------
Total Electric Sales 2,590,668 2,842,582 5,582,431 6,213,782 11,873,731 12,606,089
========== ========== ========== ========== ========== ==========
Gas Revenues
- ------------
Sales (1) $20,369 $20,136 $61,959 $69,498 $98,727 $107,851
Gas Transportation Revenues 401 276 883 448 1,626 698
Miscellaneous Revenues 99 119 218 226 441 447
---------- ---------- ---------- ---------- ---------- ----------
Total Gas Revenues $20,869 $20,531 $63,060 $70,172 $100,794 $108,996
========== ========== ========== ========== ========== ==========
Gas Sales and Gas Transported
- -----------------------------
(1000 mcf)
Sales (2) 3,603 3,096 10,804 10,976 17,915 18,734
Gas Transported 587 532 1,324 860 2,719 1,399
---------- ---------- ---------- ---------- ---------- ----------
Total 4,190 3,628 12,128 11,836 20,634 20,133
========== ========== ========== ========== ========== ==========
June 30, 1995 December 31, 1994 June 30, 1994
$ % $ % $ %
---------- ---------- ---------- ---------- ---------- ----------
Capitalization
- --------------
Variable Rate Demand Bonds (3) $71,500 3.5 $71,500 3.8 $41,500 2.3
Long-Term Debt 879,523 43.6 774,558 40.8 746,566 40.5
Preferred Stock 168,085 8.3 168,085 8.8 168,085 9.1
Common Stockholders' Equity 899,666 44.6 884,169 46.6 886,785 48.1
---------- ---------- ---------- ---------- ---------- ----------
Total $2,018,774 100.0 $1,898,312 100.0 $1,842,936 100.0
========== ========== ========== ========== ========== ==========
(1) Includes unbilled revenues.
(2) Includes unbilled sales.
(3) The Company intends to use the bonds as a source of long-term financing
as discussed in Note 12 to the Consolidated Financial Statements of the
1994 Annual Report.
- 10 -
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
------------------------------------------------
EARNINGS
- --------
The earnings per average share of common stock attributed to the core utility
business and non-utility subsidiaries are shown below.
Three Months Six Months Twelve Months
Ended Ended Ended
---------------- ---------------- ----------------
6/30/95 6/30/94 6/30/95 6/30/94 6/30/95 6/30/94
------- ------- ------- ------- ------- -------
Core Utility
Operations $0.27 $0.30 $0.79 $0.91 $1.69 $1.82
Early Retirement Offer - - - - (0.18) -
------- ------- ------- ------- ------- -------
0.27 0.30 0.79 0.91 1.51 1.82
Nonutility Subsidiaries 0.01 0.01 0.04 0.03 0.05 0.03
------- ------- ------- ------- ------- -------
$0.28 $0.31 $0.83 $0.94 $1.56 $1.85
======= ======= ======= ======= ======= =======
The components of change from the prior year in core utility earnings are
shown below:
Increase (Decrease) in Earnings Per Share
------------------------------------------------
Three Months Six Months Twelve Months
Ended Ended Ended
June 30 June 30 June 30
1995 vs 1994 1995 vs 1994 1995 vs 1994
------------ ------------ -------------
Operations
Revenues, net of fuel expense
Rate increases $0.01 $0.03 $0.04
Portion of electric resale business
supplied by another utility (0.06) (0.13) (0.13)
Sales volume and other 0.01 (0.08) (0.17)
Operation and maintenance expense 0.04 0.09 0.15
Other (0.03) (0.03) (0.02)
------ ------ ------
(0.03) (0.12) (0.13)
Early Retirement Offer - - (0.18)
------ ------ ------
($0.03) ($0.12) ($0.31)
====== ====== ======
CORE UTILITY EARNINGS
- ---------------------
Earnings per share from core utility operations decreased by $0.03, $0.12,
and $0.13 for the three-, six-, and twelve-month periods ended June 30, 1995,
respectively, compared to the same periods last year. These decreases in all
three periods were primarily due to lower electric sales resulting from
moderate weather conditions. Decreased net electric revenues in all three
periods related to a resale customer's purchase of about one-half of its
power from another utility beginning January 1995 were offset through cost
reduction efforts and modest price increases pursuant to the Company's
"Three-Legged Stool" strategy, as described further under "Outlook" on page
12. In addition to these factors, the twelve-month period earnings per share
comparison also reflects an $0.18 decrease due to an early retirement offer
(ERO) which was recorded in the third quarter of 1994.
As discussed in Note 3 to the Consolidated Financial Statements, the Company
purchased COPCO on June 19, 1995, and, accordingly, operating results from
the new Conowingo District have been included in the Company's Consolidated
Statements of Income since June 19, 1995. Conowingo District operating
results are expected to have a minimal effect on total 1995 consolidated
earnings. The Company expects Conowingo District operations will add to
earnings over time.
-11-
OUTLOOK
- -------
As further discussed in Part II, Item 5(E) on Page 18, Salem Units 1 and 2
were taken out of service on May 16, 1995 and June 7, 1995, respectively, due
to operational problems and maintenance concerns. Public Service Electric
and Gas Company (PSE&G) expects Units 1 and 2 will return to service in the
first and second quarters of 1996, respectively. Based on information
provided by PSE&G, the Company estimates that its share of additional costs
related to the outage will consist of operation and maintenance costs of
approximately $3 million (to be incurred primarily in 1995) and replacement
power costs while the units are out of service of approximately $800,000 per
month per unit. Replacement power costs for 1995 are estimated to range from
$7 million to $12 million. The Company cannot determine at this time whether
the additional costs will be recoverable.
As previously disclosed under "Strategic Plans for Competition" in Part I of
the Company's 1994 Annual Report on Form 10-K, the Company has a "Three-Legged
Stool" strategy which includes three initiatives to aid the Company in
achieving its financial goals of maintaining the current dividend level,
growing earnings, and earning a return on equity of at least 11.5%, while
keeping prices competitive. Through the first six months of 1995, the
Company is on target to meet its year-end goal of at least an 11.5% return on
equity. Continued achievement of this goal is dependent, in part, on the
recoverability of the additional costs related to the Salem outage. However,
the Company believes that it can manage the financial impact of the Salem
outage in order to keep its financial goals on track.
A recent example of the Company's efforts to increase sales involves the
Company's intensified economic development activities. Through
public/private partnerships with state agencies, the Company has been a major
player in the effort to bring Scott Paper Company, Ionics Inc., and Zenith
Products to the Delmarva peninsula. These companies will add 1,000 new jobs
in the Company's service territory and $1.5 million in annual electric and
natural gas revenues. In addition, on August 4, 1995, the Company filed an
Economic Development Rate and a Negotiated Contract Rate with the Delaware
Public Service Commission (DPSC) as further discussed on page 18.
ELECTRIC REVENUES AND SALES
- ---------------------------
Details of the changes in the various components of electric revenues are
shown below:
Increase (Decrease) in Electric Revenues
From Comparable Period in Prior Year
----------------------------------------
(Dollars in Millions)
Three Six Twelve
Months Months Months
------ ------ ------
Non-fuel (Base Rate) Revenues
Increased Rates $0.7 $ 0.7 $ 0.9
Portion of Resale Business
Supplied by Another Utility (6.2) (12.3) (12.3)
Conowingo District 3.6 3.6 3.6
Sales Volume and Other (1.7) (8.7) (16.3)
Fuel Revenues (3.1) (9.3) (17.8)
Interchange Delivery Revenues 1.1 (7.0) (17.7)
------ ------ ------
Total ($5.6) ($33.0) ($59.6)
====== ====== ======
Electric Non-Fuel (Base Rate) Revenues
- --------------------------------------
The electric non-fuel (base rate) revenue increases shown above as "Increased
Rates" reflect a $4.5 million annual increase in Delaware effective May 1,
1995.
-12-
Electric non-fuel revenues decreased $6.2 million for the three-month period
and $12.3 million for the six- and twelve-month periods because one of the
Company's resale customers, Old Dominion Electric Cooperative (ODEC), began
purchasing about one-half of its electricity from another utility on January
1, 1995.
Electric non-fuel revenues increased $3.6 million in all three periods from
Conowingo District electric sales beginning June 19, 1995. The Conowingo
District electric non-fuel revenues were offset by operating and financing
costs resulting in little effect on earnings in the current year periods.
Excluding the lost sales to ODEC and the additional Conowingo District sales,
electric non-fuel revenues from "Sales Volume and Other" variances decreased
$1.7 million, $8.7 million, and $16.3 million for the three-, six-, and
twelve-month periods primarily due to decreased sales in the weather-
sensitive residential and resale classes. Weather conditions in the
Company's service territory included milder winter heating and summer cooling
seasons than in the previous year. Partially offsetting the effect of
weather on current period sales were higher commercial sales, reflecting a
stronger economy, and annual customer growth of 1.6%.
Electric Fuel Revenues
- ----------------------
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- and six-month periods, fuel revenues decreased
$3.1 million and $9.3 million, respectively, primarily due to lower
kilowatthour (kWh) sales. Fuel revenues decreased $17.8 million for the
twelve-month period due to lower kWh sales as well as lower fuel rates which
reflect lower fuel costs.
Interchange Delivery Revenues
- -----------------------------
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 increased $1.1 million primarily
from higher sales to the City of Dover, Delaware (Dover) as a result of
decreased generation from units Dover operates. For the six- and twelve-
month periods, interchange delivery revenues decreased $7.0 million and $17.7
million, respectively, mainly due to lower sales and billing rates to the
Pennsylvania-New Jersey-Maryland Interconnection Association (PJM
Interconnection), partially offset by higher sales to Dover.
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)
Three Six Twelve
Months Months Months
------ ------ ------
Non-fuel (Base Rate) Revenues
Rate Increase $ 0.6 $ 2.2 $ 2.8
Sales Volume and Other 0.6 (1.1) (1.1)
Fuel Revenues (0.9) (8.2) (9.9)
------ ------ ------
Total $ 0.3 ($7.1) ($8.2)
====== ====== ======
-13-
The gas non-fuel (base rate) revenue increases for all periods shown as "Rate
Increase" are due to a $3.1 million annual increase effective November 1,
1994.
Gas non-fuel revenues from "Sales Volume and Other" variances were caused
primarily by weather conditions. The three-month increase of $0.6 million
resulted from a 12.5% increase in firm sales due mainly to cooler spring
weather than in the prior year. The six- and twelve-month decreases of $1.1
million resulted from decreases in firm sales of 5.9% and 8.0%, respectively,
due mainly to a milder heating season than in the prior year. The impact of
weather on sales for the six- and twelve-month periods was mitigated by 3.0%
annual customer growth. Due to increased non-firm sales and gas transported,
which are billed at lower rates than sales to firm customers, total gas sold
and transported increased 2.5% for the six- and twelve-month periods.
Gas fuel revenues decreased in all periods primarily due to lower average
fuel rates charged to customers due to lower costs for purchased gas.
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)
Three Six Twelve
Months Months Months
------ ------ ------
Average Cost of Electric Fuel
and Purchased Power ($5.9) ($17.0) ($26.6)
Decreased kWh Output (2.6) (11.6) (18.3)
Deferral of Fuel Costs 7.1 12.6 10.4
------ ------ ------
Total ($1.4) ($16.0) ($34.5)
====== ====== ======
For the three-, six-, and twelve-month periods, the average cost of electric
fuel and purchased power expenses decreased $5.9 million, $17.0 million, and
$26.6 million, respectively, primarily due to lower priced purchased power.
Greater output from lower priced gas generation also contributed to the lower
average cost per kWh of output for the six- and twelve-month periods.
Expenses decreased $2.6 million, $11.6 million, and $18.3 million for the
three-, six-, and twelve-month periods, respectively, due to lower kWh output
which was attributed to lower demand within the Company's service territory
and the region served by the PJM Interconnection.
Expenses increased in all three periods due to variances in fuel costs
deferred and subsequently amortized under the Company's fuel adjustment
clauses.
The kWh output required to serve load within the Company's service territory
is basically equivalent to total output less interchange deliveries. For
the twelve months ended June 30, 1995, the Company's output for load within
its service territory was provided by 42% coal generation, 31% oil and gas
generation, 16% nuclear generation, and 11% net purchased power.
-14-
OPERATION AND MAINTENANCE EXPENSE
- ---------------------------------
Operation and maintenance expense decreased $4.1 million for the three months
ended June 30, 1995, primarily due to lower plant maintenance expenses and
lower salaries and wages as a result of the 1994 ERO. For the six-month
period, operation and maintenance expense decreased $8.4 million mainly due
to salary and wage expense savings from the ERO and lower storm damage
expenses. For the twelve months ended June 30, 1995, operation and
maintenance expense increased $3.2 million. Increased costs, primarily due
to the $17.5 million ERO charge recorded in the third quarter of 1994, were
largely offset by a reduction in pension expense, salary and wage expense
savings from the ERO, and lower storm damage expenses.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
For the six months ended June 30, 1995, utility construction expenditures
were $55 million compared to $65 million for the same period last year.
Internally generated funds (net cash provided by operating activities less
common and preferred dividends) provided 158% of the cash required for
construction for the six months ended June 30, 1995, compared to 85% for the
same period last year. For the twelve months ended June 30, 1995, and June
30, 1994, utility construction expenditures were $145 million. Internally
generated funds provided 108% and 84% of the cash required for construction
during the twelve months ended June 30, 1995, and June 30, 1994,
respectively.
On June 19, 1995, the Company acquired COPCO for $150 million ($148.8
million net of cash acquired). The Company financed the acquisition with
the issuance of the following debt: $100 million of 7.71% First Mortgage
Bonds due in 2025, $25.8 million of 6.95% First Mortgage Bonds (Amortizing
Bonds) with annual principal installments payable each year beginning in
1997 and continuing through 2008, and $24.2 million of short-term debt which
the Company intends to refinance with long-term securities and has
classified under its term loan.
During the six months ended June 30, 1995, the Company's term loan balance
decreased $20.2 million as a result of repayment of the $45 million balance
at December 31, 1994 and the subsequent increase related to the COPCO
acquisition.
Mainly due to the long-term debt issued to acquire COPCO, long-term debt and
variable rate demand bonds as a percent of capitalization increased from
44.6% as of December 31, 1994 to 47.1% as of June 30, 1995. Also, common
stockholders' equity decreased from 46.6% as of December 31, 1994 to 44.6%
as of June 30, 1995. Through its DRIP, the Company will raise approximately
$25 million of common equity per year in order to manage its capital
structure and, thereby, maintain its capital structure at a level that
supports its A/A2 senior debt rating.
-15-
RATIO OF EARNINGS TO FIXED CHARGES
- ----------------------------------
The Company's ratios of earnings to fixed charges under the Securities and
Exchange Commission (SEC) Method are shown below:
12 Months
Ended Year Ended December 31,
June 30, ------------------------------------------
1995 1994 1993 1992 1991 1990
--------- ----- ---- ---- ---- ----
Ratio of Earnings to Fixed Charges
(SEC Method).......................... 3.32X 3.49X 3.47X 3.03X 2.58X 3.03X
Ratio of Earnings to Fixed Charges
(SEC Method) as Adjusted.............. 3.56X 3.74X 3.47X 2.78X 2.58X 2.89X
Adjusted ratios reflect the following pre-tax amounts: for the twelve
months ended June 30, 1995 and for 1994, the exclusion of a $17.5 million
early retirement offer charge; for 1992, the exclusion of an $18.5 million
gain from the Company's share of a settlement reached in the lawsuit against
PECO in connection with the shutdown of Peach Bottom; and for 1990, the
exclusion of a $62.5 million write-off of an investment in certain non-
regulated subsidiary projects.
Under the SEC Method, earnings, including Allowance for Funds Used During
Construction (AFUDC), have been computed by adding income taxes and fixed
charges to net income. Fixed charges include gross interest expense and the
estimated interest component of rentals. Net income and income taxes
related to the cumulative effect of a change in accounting for unbilled
revenues recorded in 1991 are excluded from the computation of these ratios.
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.
Earnings per share of nonutility subsidiaries were $0.01 for both the second
quarter of 1995 and 1994. The current year period included a gain on the
sale of a leveraged lease interest. This gain was offset by gains from the
sale of real estate and better operating results of the solid waste group in
the prior year period.
For the six-month periods ended June 30, 1995 and 1994, earnings per share
of non-utility subsidiaries were $0.04 and $0.03, respectively. The $0.01
increase was primarily due to higher recoveries of previously written-off
joint venture assets and the gain on the sale of a leveraged lease interest.
These earnings increases were largely offset by gains from the sale of real
estate and better operating results of the solid waste group in the prior
year period.
Nonutility subsidiaries earned $0.05 and $0.03 for the twelve-month periods
ended June 30, 1995 and 1994, respectively. The $0.02 increase was
primarily due to higher recoveries of previously written-off joint venture
assets and the gain on the sale of a leveraged lease interest. These
earnings increases were partially offset by an adjustment in the current
period to the realizable value of oil and gas wells and gains from the sale
of real estate in the prior period.
-16-
PART II. OTHER INFORMATION
--------------------------
Item 5. Other Information
- -------------------------
A) Integrated Resource Plan
------------------------
The Company recently completed the annual update of its integrated
resource plan. This plan identifies resources expected to be used to
meet customers' energy needs. Highlights of the plan through the year
2000 are as follows:
- In recognition of the changing nature of the electric utility
industry, the plan continues to stress flexibility;
- The plan does not require significant capital commitments over the
next two years; and
- Beginning in 1998, it appears the Company will need additional
resources to meet its customer needs. Because of the current excess
generating capacity that exists in the region, and the level of
uncertainty in the industry, the Company plans to use short-term market
purchases to potentially meet all of its needs through 2000.
B) Record System Peak Load
-----------------------
On August 4, 1995, during a period of abnormally hot weather, the
Company's electrical system reached an all-time record peak load of
2,774 MW. The Company's previous record peak of 2,551 MW occurred on
July 8, 1994. On a preliminary basis, it appears that the new record
peak load varied only slightly from the Company's current year forecast,
considering normal weather conditions and load management
implementation.
C) Regulatory Reform
-----------------
As previously reported in Part I of the Company's 1994 Annual Report on
Form 10-K, in 1993, the Governor of Delaware convened a Public Utility
Regulatory Task Force. On June 12, 1995, the Governor signed
legislation implementing certain changes to the regulation process that
had been recommended by the task force.
The key elements of the legislation are as follows:
(1) The DPSC is authorized to (a) deregulate utility businesses
when a competitive market exists and (b) implement alternative
forms of regulation which depart from traditional rate base, rate
of return regulation;
(2) The DPSC can authorize special rates for economic development
purposes such as attracting new customers and preventing the loss
of existing customers;
(3) The process through which the DPSC approves a public utility's
proposed issuances of debt and equity securities has been
streamlined;
(4) The DPSC is authorized to conduct rate proceedings in which
the number or type of issues are limited; and
(5) The DPSC is encouraged to resolve issues through the use of
settlements.
-17-
D) Economic Development Rate
-------------------------
On August 4, 1995, the Company filed an Economic Development Rate (EDR)
with the DPSC. The Company's proposed EDR reflects the guidelines
promulgated by the above-described regulatory reform legislation. The
EDR provides a discount which is set at a level such that revenues are
sufficient to recover all variable costs and contribute towards fixed
costs. In conjunction with the EDR, the Company also filed a Negotiated
Contract Rate which will meet special needs and opportunities for
businesses which cannot otherwise be accommodated by the Company's
standard tariffs or the EDR.
E) Salem Nuclear Generating Station
--------------------------------
As previously reported, due to operational problems and maintenance
concerns, PSE&G removed Salem Unit 1 and Unit 2 from service on May 16,
1995 and June 7, 1995, respectively. PSE&G subsequently informed the
Nuclear Regulatory Commission (NRC) that it had determined to keep the
Salem units shut down pending review and resolution of certain equipment
and management issues, and NRC agreement that each unit is sufficiently
prepared to restart. On June 9, 1995, the NRC issued a Confirmatory
Action Letter documenting these commitments by PSE&G.
Also on June 9, 1995, the NRC reported the results of a NRC Special
Inspection Team (SIT) it formed to assess how effectively Salem is
currently performing from a safety perspective in the areas of problem
identification, prioritizing and conducting work on plant equipment, and
management oversight of plant performance. While the SIT identified
some areas of strength at Salem as well as areas where improvements are
being made, including equipment problem identification systems and some
aspects of work control and root cause analysis, the team also
identified a number of findings that reveal that the day-to-day focus on
priority issues and trends were not managed well from a safety
perspective. In the report the NRC noted its concern that the SIT found
that historically poor performance in the areas of configuration
control, operator work-arounds and equipment operability determinations,
have not substantially improved and constitute a burden on the plant
operators to safely operate the Salem units, especially during plant
events.
As previously reported, PSE&G is engaged in a thorough assessment of
equipment issues that have affected Salem's operation and the related
management systems and will keep the units off line until it is
satisfied that they are ready to return to service and operate reliably
over the long term. While PSE&G has not yet finalized its analysis and
assessment activities, it currently estimates that Unit 1 will be ready
to return to service in the first quarter of 1996 and Unit 2 during the
second quarter of 1996, although no assurances can be given. During the
outage, Unit 1 will undergo a previously scheduled refueling and Unit 2
will undergo a partial refueling which will allow PSE&G to eliminate a
full refueling outage for Unit 2 scheduled for 1996. The restart plan
is focused on improving equipment reliability over the plant operations.
PSE&G has developed and is implementing a number of detailed action
plans designed to improve performance in a number of key areas. Before
restarting the units, PSE&G will complete a thorough review of station
systems and gain concurrence from the NRC that management action has
positioned the plant for reliable and safe operation.
-18-
PSE&G has recently undertaken a number of senior nuclear management
changes, including the hiring from outside of PSE&G of a Senior Vice
President - Nuclear Operations, a Senior Vice President - Nuclear
Engineering, a General Manager - Salem Operations, and a Director -
Quality Assurance and Nuclear Safety Review. PSE&G is committed to
achieving high standards of safety and operational performance for its
nuclear program. PSE&G's objective is to restart and run the Salem
plants in accord with these standards so as to assure long-term
reliability and reduce overall production costs in order to provide
customers serviced by Salem with reliable and economic energy.
As part of PSE&G's ongoing coordination with the NRC regarding the
restart of the Salem units, on August 10, 1995, PSE&G met with
representatives of the NRC concerning the Salem restart plan.
PSE&G presented an overview of the restart plan and discussed
independent oversight and engineering performance issues to gain
alignment with the NRC's expectations for improvement at Salem.
Based on information provided by PSE&G, the Company estimates that its
share of additional costs related to the outage will consist of
operation and maintenance costs of approximately $3 million (to be
incurred primarily in 1995) and replacement power costs while the units
are out of service of approximately $800,000 per month per unit.
Replacement power costs for 1995 are estimated to range from $7 million
to $12 million. The Company cannot determine at this time whether the
additional costs will be recoverable.
A Salem NRC enforcement conference, originally scheduled for June 1,
1995, was held on July 28, 1995. Apparent violations discussed included
valves that were incorrectly positioned following a plant modification
in May 1993, nonconservatisms in setpoints for a pressurizer
overpressure protection system, and several examples of inadequate root
cause determination of events leading to insufficient corrective actions
at Salem. The Company cannot predict what action, if any, the NRC may
take as a result of the enforcement conference.
F) Peach Bottom Atomic Power Station
---------------------------------
On August 2, 1995, the NRC held an enforcement conference regarding
three alleged violations identified by the NRC at Peach Bottom. The
NRC's findings include alleged violations in control and design
activities and technical specification requirements regarding
operability of the emergency diesel generators. The Company cannot
predict what action, if any, the NRC may take as a result of the
enforcement conference.
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
A) Exhibits
--------
Exhibit 12, Computation of Ratio of Earnings to Fixed Charges.
Exhibit 27, Financial Data Schedule.
B) Reports on Form 8-K
-------------------
A Report on Form 8-K dated June 14, 1995, announcing the shutdown of Salem
Units 1 and 2 and PSE&G's decision to keep the units shut down pending the
resolution of certain issues was filed with the Commission.
A Report on Form 8-K dated July 20, 1995, updating matters related to Salem
Units 1 and 2 previously reported was filed with the Commission.
-19-
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 11, 1995 /s/ B. S. Graham
--------------------------------------
B. S. Graham, Senior Vice President,
Treasurer, and Chief Financial Officer
-20-
EXHIBIT INDEX
Exhibit Page
Number Number
------- ------
Computation of ratio of earnings to fixed charges 12 22
Financial Data Schedule 27 23
-21-