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 September 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 October 31, 1995
- ----------------------------- -------------------------------
Common Stock, $2.25 par value 60,719,697 Shares
DELMARVA POWER & LIGHT COMPANY
------------------------------
Table of Contents
-----------------
Page No.
Part I. Financial Information:
Consolidated Balance Sheets as of September 30, 1995
and December 31, 1994.................................. 2-3
Consolidated Statements of Income for the three, nine,
and twelve months ended September 30, 1995 and 1994.... 4
Consolidated Statements of Cash Flows for the nine
and twelve months ended September 30, 1995 and 1994.... 5
Notes to Consolidated Financial Statements............. 6-8
Selected Financial and Operating Data.................. 9
Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 10-17
Part II. Other Information and Signature........................... 18-24
- 1 -
PART I. FINANCIAL INFORMATION
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
September 30, December 31,
1995 1994
------------- ------------
(Unaudited)
ASSETS
------
UTILITY PLANT, AT ORIGINAL COST:
Electric........................................... $2,928,153 $2,676,871
Gas................................................ 205,459 196,188
Common............................................. 129,756 120,933
------------- ------------
3,263,368 2,993,992
Less: Accumulated depreciation.................... 1,164,661 1,062,565
------------- ------------
Net utility plant in service....................... 2,098,707 1,931,427
Construction work-in-progress...................... 79,456 85,220
Leased nuclear fuel, at amortized cost............. 32,233 30,349
------------- ------------
2,210,396 2,046,996
------------- ------------
INVESTMENTS AND NONUTILITY PROPERTY:
Investment in leveraged leases..................... 48,647 49,595
Funds held by trustee.............................. 33,322 32,824
Other investments and nonutility property, net..... 55,549 57,289
------------- ------------
137,518 139,708
------------- ------------
CURRENT ASSETS:
Cash and cash equivalents.......................... 37,367 25,029
Accounts receivable:
Customers...................................... 110,031 93,739
Other.......................................... 12,967 15,144
Inventories, at average cost:
Fuel (coal, oil, and gas)...................... 27,514 48,262
Materials and supplies......................... 38,240 37,055
Prepayments........................................ 9,186 9,014
Deferred income taxes, net......................... 7,994 9,276
------------- ------------
243,299 237,519
------------- ------------
DEFERRED CHARGES AND OTHER ASSETS:
Unamortized debt expense........................... 12,406 11,387
Deferred debt refinancing costs.................... 24,624 26,530
Deferred recoverable plant costs................... 10,367 12,693
Deferred recoverable income taxes.................. 150,739 149,206
Other.............................................. 52,082 45,746
------------- ------------
250,218 245,562
------------- ------------
TOTAL ASSETS $2,841,431 $2,669,785
============= ============
See accompanying Notes to Consolidated Financial Statements.
- 2 -
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
September 30, December 31,
1995 1994
------------- ------------
(Unaudited)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stock....................................... $136,098 $133,970
Additional paid-in capital......................... 500,847 484,377
Retained earnings.................................. 287,744 267,002
Unearned compensation.............................. (1,697) (1,180)
------------- ------------
Total common stockholders' equity.............. 922,992 884,169
Preferred stock.................................... 168,085 168,085
Long-term debt..................................... 854,446 774,558
------------- ------------
1,945,523 1,826,812
------------- ------------
CURRENT LIABILITIES:
Short-term debt.................................... 30,353 10,000
Long-term debt due within one year................. 1,459 1,399
Variable rate demand bonds......................... 86,500 71,500
Accounts payable................................... 57,229 59,596
Taxes accrued...................................... 5,003 7,264
Interest accrued................................... 20,742 15,459
Dividends declared................................. 23,349 22,831
Current capital lease obligation................... 12,616 12,571
Deferred energy costs.............................. 14,450 12,241
Other.............................................. 35,999 27,538
------------- ------------
287,700 240,399
------------- ------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes, net......................... 512,351 505,435
Deferred investment tax credits.................... 45,627 47,577
Long-term capital lease obligation................. 21,378 19,660
Other.............................................. 28,852 29,902
------------- ------------
608,208 602,574
------------- ------------
TOTAL CAPITALIZATION AND LIABILITIES $2,841,431 $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 Nine Months Ended Twelve Months Ended
September 30 September 30 September 30
---------------------- ---------------------- ----------------------
1995 1994 1995 1994 1995 1994
--------- --------- --------- --------- --------- ---------
OPERATING REVENUES
Electric......................................... $278,123 $248,309 $685,891 $688,996 $880,008 $894,144
Gas.............................................. 4,942 12,292 68,002 82,464 93,445 109,893
--------- --------- --------- --------- --------- ---------
283,065 260,601 753,893 771,460 973,453 1,004,037
--------- --------- --------- --------- --------- ---------
OPERATING EXPENSES
Electric fuel and purchased power................ 77,122 70,610 207,810 217,325 273,055 291,127
Gas purchased.................................... 169 7,318 35,935 50,039 49,710 65,491
Operation and maintenance........................ 76,632 83,971 191,362 207,055 251,513 278,016
Depreciation..................................... 29,309 27,749 83,550 81,620 111,453 108,144
Taxes other than income taxes.................... 10,411 10,212 29,310 29,923 37,972 38,782
Income taxes..................................... 28,462 17,820 62,536 54,813 73,888 64,186
--------- --------- --------- --------- --------- ---------
222,105 217,680 610,503 640,775 797,591 845,746
--------- --------- --------- --------- --------- ---------
OPERATING INCOME.................................. 60,960 42,921 143,390 130,685 175,862 158,291
--------- --------- --------- --------- --------- ---------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains.............................. 9,329 11,027 34,785 31,783 46,147 43,993
Expenses including interest and income taxes.... (9,373) (10,576) (32,340) (29,438) (43,693) (41,610)
--------- --------- --------- --------- --------- ---------
Net earnings of nonutility subsidiaries.... (44) 451 2,445 2,345 2,454 2,383
Allowance for equity funds used during
construction................................... 91 852 462 2,577 1,275 3,211
Other income, net of income taxes................ (267) 143 381 (884) 978 (384)
--------- --------- --------- --------- --------- ---------
(220) 1,446 3,288 4,038 4,707 5,210
--------- --------- --------- --------- --------- ---------
INCOME BEFORE UTILITY INTEREST CHARGES............ 60,740 44,367 146,678 134,723 180,569 163,501
--------- --------- --------- --------- --------- ---------
UTILITY INTEREST CHARGES
Interest expense................................. 18,288 15,456 50,460 46,280 66,255 61,841
Allowance for borrowed funds used during
construction................................... (262) (455) (1,348) (1,340) (1,782) (1,747)
--------- --------- --------- --------- --------- ---------
18,026 15,001 49,112 44,940 64,473 60,094
--------- --------- --------- --------- --------- ---------
NET INCOME........................................ 42,714 29,366 97,566 89,783 116,096 103,407
DIVIDENDS ON PREFERRED STOCK...................... 2,476 2,358 7,477 6,945 9,902 9,475
--------- --------- --------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK............... $40,238 $27,008 $90,089 $82,838 $106,194 $93,932
========= ========= ========= ========= ========= =========
COMMON STOCK
Average shares outstanding (000)................. 60,372 59,542 60,073 59,322 59,940 59,164
Earnings per average share....................... $0.67 $0.46 $1.50 $1.40 $1.77 $1.59
Dividends declared per share..................... $0.38 1/2 $0.38 1/2 $1.15 1/2 $1.15 1/2 $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)
-----------
Nine Months Ended Twelve Months Ended
September 30 September 30
---------------------- ----------------------
1995 1994 1995 1994
-------- -------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................... $97,566 $89,783 $116,096 $103,407
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization............................. 89,872 90,321 120,354 118,542
Allowance for equity funds used during construction....... (462) (2,577) (1,275) (3,211)
Investment tax credit adjustments, net.................... (1,950) (1,885) (1,962) (2,514)
Deferred income taxes, net................................ 6,664 (1,925) 13,418 6,488
Provision for early retirement offer...................... -- 17,500 -- 17,500
Net change in :
Accounts receivable..................................... (5,768) 10,312 (8,100) 13,430
Inventories............................................. 20,090 (10,466) 10,261 (7,064)
Accounts payable........................................ (2,603) (9,180) 10,888 15,301
Other current assets & liabilities*..................... 9,859 (4,433) 3,571 (39,167)
Other, net................................................ (3,229) (450) (6,064) (1,131)
-------- -------- -------- --------
Net cash provided by operating activities........................ 210,039 177,000 257,187 221,581
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures, excluding AFUDC................... (87,961) (98,680) (143,400) (140,676)
Allowance for borrowed funds used during construction........ (1,348) (1,340) (1,782) (1,747)
Acquisition of COPCO, net of cash acquired................... (156,987) -- (156,987) --
Cash flows from leveraged leases............................. 2,585 1,201 2,976 1,512
Proceeds from sale of subsidiary property.................... -- 4,596 -- 4,596
Investment in subsidiary projects and operations............. (2,348) (10,512) (2,881) (10,063)
(Increase)/decrease in bond proceeds held in trust funds..... 2,626 7 (9,197) 4,343
Deposits to nuclear decommissioning trust funds.............. (2,199) (1,849) (2,788) (2,396)
Other, net................................................... (615) (4,358) 1,407 (3,249)
-------- -------- -------- --------
Net cash used by investing activities............................ (246,247) (110,935) (312,652) (147,680)
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends: Common.......................................... (68,988) (68,270) (91,893) (90,783)
Preferred....................................... (7,319) (7,030) (9,753) (9,686)
Issuances: Long-term debt.................................. 125,800 4,640 125,800 4,640
Variable rate demand bonds...................... 15,000 -- 45,000 15,500
Common stock.................................... 18,628 14,974 18,628 22,300
Preferred stock................................. -- -- -- 20,000
Redemptions: Long-term debt.................................. (862) (600) (26,358) (1,042)
Variable rate demand bonds...................... -- -- -- (15,500)
Common stock.................................... (1,253) (794) (1,253) (799)
Preferred stock................................. -- -- -- (28,280)
Principal portion of capital lease payments.................. (6,322) (8,701) (8,901) (10,398)
Net change in term loan...................................... (45,000) 6,500 (16,500) 16,500
Net change in short-term debt ............................... 20,353 -- 30,353 --
Cost of issuances and refinancings........................... (1,491) (210) (1,882) (2,115)
-------- -------- -------- --------
Net cash provided/(used) by financing activities................. 48,546 (59,491) 63,241 (79,663)
-------- -------- -------- --------
Net change in cash and cash equivalents.......................... 12,338 6,574 7,776 (5,762)
Cash and cash equivalents at beginning of period................. 25,029 23,017 29,591 35,353
-------- -------- -------- --------
Cash and cash equivalents at end of period....................... $37,367 $29,591 $37,367 $29,591
======== ======== ======== ========
*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 Reports on Form 10-Q for the first
and second quarters of 1995, and Part II of this Report on Form 10-Q for
additional relevant information.
2. COMMON STOCK
------------
During the first nine months of 1995, the Company issued 944,623 shares of
common stock for $18,628,000 primarily through the Dividend Reinvestment
and Common Share Purchase Plan (DRIP). As of September 30, 1995,
60,486,629 shares of common stock were outstanding.
3. DEBT
----
On August 30, 1995, the Schuylkill County Industrial Development
Authority, Commonwealth of Pennsylvania, issued on behalf of Pine Grove
Landfill, Inc. (Pine Grove), an indirect subsidiary of the Company, $15
million of Variable Rate Demand Revenue Bonds. The bonds are due on
demand or at maturity on October 1, 2019 and are secured by a bank letter
of credit. Proceeds from the bonds will be used to finance the past and
future expansion of a landfill which is owned and operated by Pine Grove.
The terms of the bonds and the use of the bonds as a source of long-term
financing are similar to the terms and use of the Company's other
outstanding Variable Rate Demand Bonds. For a description of the
Company's Variable Rate Demand Bonds, see Note 12 to the Consolidated
Financial Statements contained in the Company's 1994 Annual Report to
Stockholders.
As of September 30, 1995, the Company had repaid its term loan which had
a $45 million balance as of December 31, 1994.
4. 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.
- 6 -
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.
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 three federal
superfund sites and is alleged to be a third-party contributor at two
other federal superfund sites. The Company also has two former coal
gasification sites in Delaware and one former coal gasification site in
Maryland, each of which is a state superfund site. The Company is
currently participating with the States of Delaware and Maryland in
evaluating the coal gasification sites to assess the extent of
contamination and risk to the environment. The Company's current
liabilities include $2 million representing the estimated site study and
cleanup costs for 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.
5. SUPPLEMENTAL CASH FLOW INFORMATION
----------------------------------
Nine Months Ended Twelve Months Ended
September 30, September 30,
------------------- -------------------
(Dollars in Thousands) 1995 1994 1995 1994
-------- -------- -------- --------
Cash paid for
Interest, net of amounts
capitalized $41,673 $39,766 $59,744 $57,010
Income taxes, net of refunds $64,691 $61,095 $71,413 $82,470
- 7 -
6. 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 Nine Months Ended Twelve Months Ended
September 30, September 30, September 30,
------------------- ------------------- -------------------
(Dollars in Thousands) 1995 1994 1995 1994 1995 1994
-------- -------- -------- -------- -------- --------
Revenues and Gains
Landfill and waste hauling $ 3,502 $ 3,845 $ 10,277 $ 10,252 $14,211 $13,641
Operating services 5,084 5,073 18,262 15,672 25,059 22,543
Other revenues 343 1,845 1,054 4,546 1,432 5,898
Leveraged leases 121 74 1,638 191 1,719 232
Other investment income 279 190 3,554 1,122 3,726 1,679
-------- -------- -------- -------- -------- --------
9,329 11,027 34,785 31,783 46,147 43,993
-------- -------- -------- -------- -------- --------
Cost and Expenses
Operating expenses 9,322 10,112 30,745 27,704 41,527 39,317
Interest expense, net 124 42 269 61 579 --
Income taxes (73) 422 1,326 1,673 1,587 2,293
-------- -------- -------- -------- -------- --------
9,373 10,576 32,340 29,438 43,693 41,610
-------- -------- -------- -------- -------- --------
Net income $ (44) $ 451 $ 2,445 $ 2,345 $ 2,454 $ 2,383
======== ======== ======== ======== ======== ========
Earnings per share of common
stock attributed to subsidiaries $ -- $0.01 $0.04 $0.04 $0.04 $0.04
- 8 -
SELECTED FINANCIAL AND OPERATING DATA
-------------------------------------
(Dollars in Thousands)
3 Months Ended 9 Months Ended 12 Months Ended
September 30 September 30 September 30
------------------------- ------------------------- -------------------------
1995 1994 1995 1994 1995 1994
---------- ---------- ---------- ---------- ---------- ----------
ELECTRIC REVENUES
- -----------------
Residential $116,374 $95,193 $266,285 $251,157 $327,352 $314,931
Commercial 84,530 72,943 203,278 189,062 256,722 242,636
Industrial 43,538 40,038 116,449 110,410 151,633 147,188
Resale 19,380 29,262 46,050 81,698 69,702 105,817
Other Sales Revenues (1) 505 (1,625) 4,447 3,451 7,812 7,507
---------- ---------- ---------- ---------- ---------- ----------
Sales Revenues 264,327 235,811 636,509 635,778 813,221 818,079
Interchange Deliveries 10,640 10,393 40,442 47,157 55,673 67,677
Miscellaneous Revenues 3,156 2,105 8,940 6,061 11,114 8,388
---------- ---------- ---------- ---------- ---------- ----------
Total Electric Revenues $278,123 $248,309 $685,891 $688,996 $880,008 $894,144
========== ========== ========== ========== ========== ==========
ELECTRIC SALES
- --------------
(1000 kWh)
Residential 1,194,218 1,006,522 2,944,920 2,882,667 3,640,996 3,609,012
Commercial 1,114,054 982,682 2,823,962 2,671,418 3,613,602 3,441,538
Industrial 909,555 854,651 2,512,294 2,427,281 3,333,144 3,246,193
Resale 392,451 603,430 928,448 1,675,188 1,419,414 2,197,843
Other sales (2) (24,586) (42,947) (41,501) (38,434) 47,929 68,934
---------- ---------- ---------- ---------- ---------- ----------
Total Electric Sales 3,585,692 3,404,338 9,168,123 9,618,120 12,055,085 12,563,520
========== ========== ========== ========== ========== ==========
GAS REVENUES
- ------------
Sales (1) $4,290 $11,799 $66,249 $81,297 $91,218 $108,466
Gas Transportation Revenues 546 373 1,429 821 1,799 975
Miscellaneous Revenues 106 120 324 346 428 452
---------- ---------- ---------- ---------- ---------- ----------
Total Gas Revenues $4,942 $12,292 $68,002 $82,464 $93,445 $109,893
========== ========== ========== ========== ========== ==========
GAS SALES AND GAS TRANSPORTED
- -----------------------------
(1000 mcf)
Sales (2) 2,124 2,140 12,928 13,116 17,899 18,577
Gas Transported 793 684 2,117 1,544 2,828 1,838
---------- ---------- ---------- ---------- ---------- ----------
Total 2,917 2,824 15,045 14,660 20,727 20,415
========== ========== ========== ========== ========== ==========
September 30, 1995 December 31, 1994 September 30, 1994
------------------------- ------------------------- -------------------------
$ % $ % $ %
---------- ---------- ---------- ---------- ---------- ----------
CAPITALIZATION
Variable Rate Demand Bonds (3) $86,500 4.3 $71,500 3.8 $41,500 2.2
Long-Term Debt 854,446 42.0 774,558 40.8 746,732 40.4
Preferred Stock 168,085 8.3 168,085 8.8 168,085 9.1
Common Stockholders' Equity 922,992 45.4 884,169 46.6 891,015 48.3
---------- ---------- ---------- ---------- ---------- ----------
Total $2,032,023 100.0 $1,898,312 100.0 $1,847,332 100.0
========== ========== ========== ========== ========== ==========
(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.
- 9 -
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
------------------------------------------------
EARNINGS SUMMARY
- ----------------
The earnings per average share of common stock attributed to the core
utility business and non-utility subsidiaries are shown below.
Three Months Nine Months Twelve Months
Ended Ended Ended
---------------- ---------------- ----------------
9/30/95 9/30/94 9/30/95 9/30/94 9/30/95 9/30/94
------- ------- ------- ------- ------- -------
Core Utility
Operations $0.67 $0.63 $1.46 $1.54 $1.73 $1.73
Early Retirement Offer -- (0.18) -- (0.18) -- (0.18)
------- ------- ------- ------- ------- -------
0.67 0.45 1.46 1.36 1.73 1.55
Nonutility Subsidiaries -- 0.01 0.04 0.04 0.04 0.04
------- ------- ------- ------- ------- -------
Total $0.67 $0.46 $1.50 $1.40 $1.77 $1.59
======= ======= ======= ======= ======= =======
For the three-, nine-, and twelve-month periods ended September 30, 1995,
compared to the same periods a year ago, earnings per share from core
utility operations increased $0.04, decreased $0.08, and remained
unchanged, respectively. The $0.04 increase for the three-month period was
primarily due to increased electric sales resulting from hotter weather
than in the previous year. Earnings per share from core utility operations
decreased $0.08 for the nine-month period due to increased utility
financing costs and decreased sales from net year-over-year weather
variances mainly due to milder winter weather. These factors were partly
offset by additional customers and sales gained through economic growth in
the Company's service territory. The twelve-month period comparison of
earnings per share from core utility operations reflects the factors which
affected the nine-month period as well as lower operation and maintenance
expense. All three current year periods also reflect a $0.04 reserve for
Salem outage-related replacement power costs which may not be recoverable,
as described further under "Outlook" on page 11, "Electric Fuel and
Purchased Power Expenses" on page 14, and Part II on page 18.
For all three current year periods, decreased net electric revenues from a
resale customer's purchase of about one-half of its power from another
utility beginning January 1995 were offset through cost reduction efforts,
modest price increases, and sales growth pursuant to the Company's "Three-
Legged Stool" strategy, as described further under "Outlook" on page 11.
Also, since June 19, 1995, operating results from the new Conowingo
District had a minimal impact on earnings, as expected.
All three prior year periods include an $0.18 charge related to an early
retirement offer (ERO) which was recorded in the third quarter of 1994.
- 10 -
OUTLOOK
- -------
As previously reported, Salem Units 1 and 2 were taken out of service on
May 16, 1995 and June 7, 1995, respectively. Public Service Electric and
Gas Company (PSE&G) expects Units 1 and 2 will return to service in the
second quarter of 1996. Based on information provided by PSE&G, the
Company estimates that its share of additional costs related to the outage
in 1995 will consist of operation and maintenance costs of approximately $4
million, which will be expensed as incurred, and replacement power costs
while the units are out of service of approximately $800,000 per month, per
unit. In total, the Company estimates that its share of outage-related
costs will range from $10 million to $15 million in 1995. During the third
quarter, the Company recorded a $3.5 million reserve for outage-related
replacement power costs which may not be recoverable. The Company cannot
determine at this time the level of costs which 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 earning a return on equity of at least
11.5% in order to maintain the current dividend level while keeping prices
competitive. The Company's earnings through the first nine months of 1995
support the current dividend and have kept the Company on target to meet
its return on equity goal through year-end. The Company believes that it
can manage the financial impact of the Salem outage in order to keep its
financial goals on track.
Growth Opportunities
- --------------------
Over the last quarter, several electric utilities have announced merger
plans. These transactions represent one way to address competitive
pressures. The Company believes that, over the long term, the most value
for its stockholders can be created through above average earnings growth.
To achieve above average financial performance, the Company is building
upon the success of its "Three-Legged Stool" strategy by pursuing growth
opportunities through expanding its retail market and by controlling
expenses to maintain its competitive price position. In addition to the
purchase of the Conowingo Power Company (COPCO), the Company is looking for
other possible acquisitions to expand its retail business. The Company is
also working with state and local governments to attract new businesses to
the Delmarva Peninsula. During 1995, these efforts have resulted in more
than $2 million in added energy sales for the Company and nearly 1,400
additional jobs for the peninsula.
The Company continues to develop new products. For example, the Company
now offers a line of services to operate, maintain, and upgrade commercial
and industrial customers' electrical, steam, and natural gas systems.
These services build upon the Company's excellent service reputation as
well as its extensive engineering knowledge and experience. The Company
expects revenues from these services to grow during the next three years.
In addition, the Company recently introduced power quality consulting
services to companies outside its service area. The Company has already
established its ability to provide these specialized diagnostic and
protective services for its customers' electric and computer systems.
The Company has also entered into a fiber optics agreement with a major
competitive access provider. Under the terms of the agreement, the access
provider has contracted for the Company to build, own, and maintain fiber
optic lines for the access provider's business expansion efforts in New
Castle County, Delaware.
- 11 -
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 Nine Twelve
Months Months Months
------ ------ ------
Non-fuel (Base Rate) Revenues
Conowingo District $19.4 $22.5 $22.5
Portion of Resale Business
Supplied by Another Utility (6.1) (18.4) (18.4)
Sales Volume and Other 12.9 4.2 2.5
Rate Increase 1.4 2.1 2.1
Fuel Revenues 1.9 (6.8) (10.8)
Interchange Delivery Revenues 0.3 (6.7) (12.0)
------ ------ ------
Total $29.8 ($3.1) ($14.1)
====== ====== ======
Electric Non-Fuel (Base Rate) Revenues
- --------------------------------------
Electric non-fuel (base rate) revenues increased $19.4 million for the
three-month period and $22.5 million for the nine- and twelve-month periods
from Conowingo District electric sales beginning June 19, 1995.
Electric non-fuel revenues decreased $6.1 million for the three-month
period and $18.4 million for the nine- 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.
Excluding the lower sales to ODEC and the additional Conowingo District
sales, electric non-fuel revenues from "Sales Volume and Other" variances
increased $12.9 million, $4.2 million, and $2.5 million for the three-,
nine-, and twelve-month periods, respectively. The increase for the three-
month period was primarily due to increased sales in the weather-sensitive
residential and resale classes resulting from hotter weather than in the
previous year. The $4.2 million and $2.5 million increases for the nine- and
twelve-month periods, respectively, were due to sales gains from economic
growth, partly offset by an unfavorable net weather-related sales variance
attributed mainly to the effect of milder winter weather on electricity usage.
The number of residential and commercial customers increased 1.4% and 2.0%,
respectively, for the twelve-months ended September 30, 1995. Industrial
sales were slightly higher in all current year periods.
The electric non-fuel revenue increases shown above as "Rate
Increase" reflect a $4.5 million annual increase in Delaware effective May
1, 1995.
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-month period, fuel revenues increased
$1.9 million primarily due to higher kilowatthour (kWh) sales. Fuel
revenues decreased $6.8 million and $10.8 million for the nine- and twelve-
month periods, respectively, primarily due to lower kWh sales.
- 12 -
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 $0.3
million primarily from higher average billing rates to the Pennsylvania-New
Jersey-Maryland Interconnection Association (PJM Interconnection) and the
City of Dover, Delaware (Dover). For the nine- and twelve-month periods,
interchange delivery revenues decreased $6.7 million and $12.0 million,
respectively, mainly due to lower sales and billing rates to the 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 Nine Twelve
Months Months Months
------ ------ ------
Non-fuel (Base Rate) Revenues
Rate Increase $ 0.3 $ 2.5 $ 3.0
Sales Volume and Other (0.2) (1.3) (2.0)
Fuel Revenues (7.5) (15.7) (17.5)
------ ------ ------
Total $(7.4) ($14.5) ($16.5)
====== ====== ======
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 decreased
$1.3 million for the nine-month period and $2.0 million for the twelve-
month period due to decreases in firm sales of 5.2% and 7.3%, respectively,
mainly due to a milder heating season than in the prior year. The impact
of weather on sales for the nine- 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 2.6% and 1.5% for the nine- and
twelve-month periods, respectively.
Gas fuel revenues decreased in all periods primarily due to a $6.8 million
refund in July 1995 of over-recovered fuel costs and lower average fuel
rates charged to customers due to lower costs for purchased gas.
- 13 -
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 Nine Twelve
Months Months Months
------ ------ ------
Average Cost of Electric Fuel and
Purchased Power $4.7 ($12.7) ($20.1)
Increased/(Decreased) kWh Output 2.7 ( 8.5) (11.0)
Salem Reserve 3.5 3.5 3.5
Deferral of Fuel Costs (4.4) 8.2 9.5
------ ------ ------
Total $6.5 ($9.5) ($18.1)
====== ====== ======
For the three-month period, the average cost of electric fuel and purchased
power increased $4.7 million primarily due to increased use of higher priced
purchased power as a result of higher system loads. For the nine- and twelve-
month periods, the average cost of electric fuel and purchased power expenses
decreased $12.7 million and $20.1 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 nine- and twelve-month periods.
Expenses increased $2.7 million for the three-month period due to higher
kWh output which was attributed to higher demand within the Company's
service territory and the region served by the PJM Interconnection.
Expenses decreased $8.5 million and $11.0 million for the nine- 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 $3.5 million in all three periods due to the Company's
reserve for Salem outage-related replacement power costs which may not be
recoverable.
Expenses decreased in the three-month period and increased in the nine- and
twelve-month 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 September 30, 1995, the Company's
output for load within its service territory was provided by 42% coal
generation, 32% oil and gas generation, 14% nuclear generation, and 12%
net purchased power.
GAS PURCHASED
- -------------
The decreases in cost of gas purchased of $7.1 million, $14.1 million, and
$15.8 million for the three-, nine-, and twelve-month periods,
respectively, were primarily due to lower gas commodity prices and the
$6.8 million refund in July 1995 of over-recovered fuel costs. The $6.8
million refund of over-recovered fuel costs reduced the cost of gas
purchased in all three periods because gas purchased was adjusted
(reduced) to match fuel revenues.
- 14 -
OPERATION AND MAINTENANCE EXPENSE
- ---------------------------------
Operation and maintenance expense decreased $7.3 million for the three
months ended September 30, 1995, compared to the same period last year
primarily due to the $17.5 million ERO charge recorded in the third
quarter of 1994 and related salary and wage savings in 1995, partially
offset by capacity purchase charges under the Company's contract to
purchase the Conowingo District's electric power requirements from PECO
Energy Company (PECO) from June 19, 1995, through January 1996.
Operation and maintenance expense decreased $15.7 million and $26.5
million for the nine-and twelve-month periods, respectively, primarily due
to the third quarter 1994 ERO charge of $17.5 million and related salary and
wage savings in 1995, lower storm damage expenses, and lower pension expense,
partially offset by capacity purchase charges from PECO beginning June 19,
1995.
UTILITY FINANCING COSTS
- -----------------------
Interest charges on debt of the core utility increased $2.8 million, $4.2
million, and $4.4 million for the three-, nine-, and twelve-month periods,
respectively. The increase for all three periods was primarily due to the
debt issued to acquire COPCO, higher short-term debt balances and rates,
and higher rates on Variable Rate Demand Bonds.
Allowance for funds used during construction (AFUDC) decreased $1.0
million, $2.1 million, and $1.9 million for the three-, nine-, and twelve-
month periods, respectively, mainly due to a lower AFUDC rate and lower
average construction balances in 1995 than in 1994. For the twelve months
ended September 30, 1995, AFUDC was 2.0% of net income.
Due to increased common equity financing, primarily through the Company's
DRIP, the average number of common shares outstanding increased for the
three-, nine-, and twelve-month periods. The additional shares
outstanding decreased earnings per share by $0.01 for the three-month
period and $0.02 for the nine- and twelve-month periods.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
For the nine months ended September 30, 1995, utility construction
expenditures were $88 million compared to $99 million for the same period
last year. Internally generated funds (net cash provided by operating
activities less common and preferred dividends) provided 152% of the cash
required for construction for the nine months ended September 30, 1995,
compared to 103% for the same period last year. For the twelve months
ended September 30, 1995, and September 30, 1994, utility construction
expenditures were $143 million and $141 million, respectively. Internally
generated funds provided 108% and 86% of the cash required for
construction during the twelve months ended September 30, 1995, and
September 30, 1994, respectively.
On June 19, 1995, the Company acquired COPCO for $158.2 million ($157.0
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.
In the third quarter of 1995, the balance of the purchase price, related
to a true-up of working capital amounts, was paid by the Company to PECO
in cash.
- 15 -
On August 30, 1995, the Schuylkill County Industrial Development
Authority, Commonwealth of Pennsylvania, issued on behalf of Pine Grove
Landfill, Inc. (Pine Grove), an indirect subsidiary of the Company, $15
million of Variable Rate Demand Revenue Bonds due on demand or at maturity
on October 1, 2019. Proceeds from the bonds will be used to finance the past
and future expansion of a landfill which is owned and operated by Pine Grove.
As of September 30, 1995, the Company had repaid its term loan which had a
$45 million balance as of December 31, 1994.
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 46.3% as of September 30, 1995.
Also, common stockholders' equity decreased from 46.6% as of December 31,
1994 to 45.4% as of September 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.
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
September 30, Year Ended December 31,
1995 ------------------------------------------
------------ 1994 1993 1992 1991 1990
------ ------ ------ ------ ------
Ratio of Earnings to Fixed Charges
(SEC Method)..................... 3.59 3.49 3.47 3.03 2.58 2.03
Ratio of Earnings to Fixed Charges
(SEC Method) as Adjusted......... 3.59 3.74 3.47 2.78 2.58 2.89
Adjusted ratios reflect the following pre-tax amounts: 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 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.
- 16 -
NONUTILITY SUBSIDIARIES
- -----------------------
Information on the Company's nonutility subsidiaries, in addition to the
following discussion, can be found in Note 6 to the Consolidated Financial
Statements.
Earnings per share of nonutility subsidiaries decreased $0.01 for the third
quarter of 1995 as compared to the third quarter of 1994 primarily due to
lower earnings from solid waste group operations.
Earnings per share of nonutility subsidiaries were $0.04 for each of the
nine- and twelve-month periods ended September 30, 1995 and 1994. The
nine-and twelve-month periods ended September 30, 1995, as compared to the
same periods in 1994, reflect higher recoveries of previously written-off
joint venture assets, the gain on the sale of a leveraged lease interest,
lower gains from the sale of real estate, and lower earnings from solid
waste group operations.
- 17 -
PART II. OTHER INFORMATION
--------------------------
Item 5. Other Information
- -------------------------
A) Salem Nuclear Generating Station
--------------------------------
As previously reported, Salem Unit 1 and Unit 2 were taken out of
service on May 16, 1995 and June 7, 1995, respectively. PSE&G
subsequently informed the Nuclear Regulatory Commission (NRC) of its
determination 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.
PSE&G, as previously reported, is engaged in a thorough assessment of
Salem to identify the scope of work necessary to achieve safe,
sustained and reliable operation. PSE&G has stated that it 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.
PSE&G has completed its rigorous examination of Salem Unit 1 and its
assessment of Unit 2 is continuing. Work on the 46 systems critical
to Unit 1 is continuing, including those common with Unit 2, with more
than 25% of necessary work activities completed and many others
initiated. While PSE&G has previously estimated that Unit 1 would
return to service in the first quarter 1996, as a result of its
completed assessment, PSE&G now expects the unit to return in the
second quarter of 1996.
The work scope assessment for Unit 2 is currently scheduled for
completion in November 1995. PSE&G expects to present its final work
scope assessment of both units to the NRC in mid-December 1995.
Since, as previously indicated, some of the work being performed
relates to systems serving both units, the additional time needed for
Unit 1 does not necessarily mean that the current second quarter 1996
return estimate for Unit 2 will also be extended. As previously
disclosed, during the outages Unit 1 will undergo a previously
scheduled refueling outage 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.
While PSE&G expects to restart the units in the second quarter of
1996, the restarts are subject to NRC authorization. The Company
cannot predict when the NRC will approve the restart of the units or
when the restarts will actually occur.
Based on PSE&G's estimates, the Company estimates that its share of
additional costs related to the outage in 1995 will consist of
operation and maintenance costs of approximately $4 million, which
will be expensed as incurred, and replacement power costs while the
units are out of service of approximately $800,000 per month, per
unit. In total, the Company estimates that its share of outage-
related costs will range from $10 million to $15 million in 1995.
A firm estimate of additional operation and maintenance costs for 1996
will not be known by PSE&G until after the assessment of Unit 2 is
complete, and the restart plans are completed. However, PSE&G has
informed the Company that additional operation and maintenance costs
for 1996 may substantially exceed its initial estimate made at the
start of the work scope assessment. During the third quarter, the
Company recorded a $3.5 million reserve for outage-related replacement
power costs which may not be recoverable. The Company cannot determine
at this time the level of costs which will be recoverable.
- 18 -
As previously reported, PSE&G has recently undertaken a number of
nuclear senior management changes. PSE&G has reported that it is
committed to achieving high standards of safety and operational
performance for its nuclear program. PSE&G's stated 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.
On October 5, 1995 plant operators at Unit 1 declared an alert because
the overhead annunciator panels located in the control room stopped
functioning. On-site facilities and the emergency news center were
staffed and activated during the alert. Contractors on site at the
time were asked to leave the site. The panels were declared fully
operable after testing later that day, and the alert was terminated
and access to the site was fully restored. PSE&G and the NRC are
continuing to investigate this event. The Company cannot predict
what action, if any, the NRC may take on this matter.
As previously reported, a Salem NRC enforcement conference was held on
July 28, 1995, concerning certain violations of NRC requirements not
related to the present outage. The violations included valves that
were incorrectly positioned following a plant modification in May
1993, non-conservatisms 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. On October 16, 1995, the NRC proposed cumulative civil
penalties of $600,000 related to these violations. PSE&G has advised
the NRC that it will not contest the proposed penalties.
B) Peach Bottom Atomic Power Station
---------------------------------
As previously reported, on August 2, 1995, the NRC held an enforcement
conference regarding three alleged violations identified by the NRC at
Peach Bottom. In a letter dated August 17, 1995, the NRC stated that
the inadequate design control and testing which led to the degradation
of emergency diesel generator capabilities constituted a violation;
however, because PECO identified the issues, conducted a detailed
root-cause evaluation and took appropriate corrective actions, no
civil penalty was proposed.
C) Regulatory Reform
-----------------
In September 1994, the Maryland Public Service Commission (MPSC)
initiated an investigation into competition, alternative regulation,
and industry structure (Case 8678). On August 18, 1995, the MPSC
issued its final order in this case. The MPSC determined that retail
wheeling is not in the public interest at this time and that wholesale
competition in combination with competitive bidding for new supply-
side and demand-side resources, special contracts, and utility-
specific performance based regulation can achieve most of the benefits
expected from retail wheeling without harming reliability. The MPSC
also stated that it would provide broad guidelines to begin laying the
foundation for competition in Maryland, continue to monitor
restructuring developments in other states, and participate in the
Federal Energy Regulatory Commission's (FERC) proposed rulemaking on
open access transmission service. The MPSC also stated it would
exercise its authority to open State-jurisdictional transmission
facilities to wholesale competitors.
- 19 -
D) Fuel Rate Matters
-----------------
As previously reported in the Company's 1994 Annual Report on Form 10-
K, on May 19, 1993, the Company's municipal customers filed a
complaint with the FERC seeking a $5.3 million refund of alleged
excessive fuel and replacement power costs related to coal procurement
practices and the operating performance of certain electric power
plants. On September 27, 1995, the FERC issued its order dismissing
all issues in the case except one. The FERC set for public hearing
the remaining issue, which could involve a maximum potential refund to
municipal customers of approximately $300,000. The Company believes
this issue is without merit.
On September 29, 1995, the Delaware Public Service Commission (DPSC)
issued its order in the Company's annual retail fuel adjustment filing
for 1995. The DPSC disallowed the Company's recovery of net
replacement power costs of $800,000 associated with the Salem Unit 1
outage from April 7, 1994 to June 4, 1994. However, the DPSC's order
also provides for the avoidance of penalties related to this Salem
Unit 1 outage under the Power Plant Performance Program estimated at
$300,000 for the years 1994-1996.
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 October 20, 1995, updating matters related to
Salem Units 1 and 2 previously reported was filed with the Commission.
- 20 -
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: November 14, 1995 /s/ B. S. Graham
----------------- --------------------------------------
B. S. Graham, Senior Vice President,
Treasurer, and Chief Financial Officer
- 21 -
EXHIBIT INDEX
Exhibit Page
Number Number
------- ------
Computation of ratio of earnings to fixed charges 12 23
Financial Data Schedule 27 24
- 22 -