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 March 31, 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 April 30, 1995
- ----------------------------- -----------------------------
Common Stock, $2.25 par value 60,135,488 Shares
DELMARVA POWER & LIGHT COMPANY
------------------------------
Table of Contents
-----------------
Page No.
--------
Part I. Financial Information:
Consolidated Balance Sheets as of March 31, 1995
and December 31, 1994................................... 2-3
Consolidated Statements of Income for the three and
twelve months ended March 31, 1995 and 1994............. 4
Consolidated Statements of Cash Flows for the three
and twelve months ended March 31, 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..................... 10-15
Part II. Other Information and Signature............................ 16-22
- 1 -
PART I. FINANCIAL INFORMATION
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
March 31, December 31,
1995 1994
------------ ------------
(Unaudited)
ASSETS
------
UTILITY PLANT, AT ORIGINAL COST:
Electric........................................ $2,701,624 $2,676,871
Gas............................................. 199,425 196,188
Common.......................................... 122,864 120,933
------------ ------------
3,023,913 2,993,992
Less: Accumulated depreciation................. 1,080,702 1,062,565
------------ ------------
Net utility plant in service.................... 1,943,211 1,931,427
Construction work-in-progress................... 69,654 85,220
Leased nuclear fuel, at amortized cost.......... 29,720 30,349
------------ ------------
2,042,585 2,046,996
------------ ------------
INVESTMENTS AND NONUTILITY PROPERTY:
Investment in leveraged leases.................. 49,401 49,595
Funds held by trustee........................... 33,868 32,824
Other investments and nonutility property, net.. 56,877 57,289
------------ ------------
140,146 139,708
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents....................... 33,032 25,029
Accounts receivable:
Customers................................... 91,036 93,739
Other....................................... 16,485 15,144
Inventories, at average cost:
Fuel (coal, oil, and gas)................... 35,158 48,262
Materials and supplies...................... 38,643 37,055
Prepayments..................................... 5,725 9,014
Deferred income taxes, net...................... 12,387 9,276
------------ ------------
232,466 237,519
------------ ------------
DEFERRED CHARGES AND OTHER ASSETS:
Unamortized debt expense........................ 11,273 11,387
Deferred debt refinancing costs................. 25,927 26,530
Deferred recoverable plant costs................ 12,211 12,693
Deferred recoverable income taxes............... 149,716 149,206
Other........................................... 50,450 45,746
------------ ------------
249,577 245,562
------------ ------------
TOTAL ASSETS $2,664,774 $2,669,785
============ ============
See accompanying Notes to Consolidated Financial Statements.
- 2 -
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
March 31, December 31,
1995 1994
------------ ------------
(Unaudited)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stock.................................... $134,726 $133,970
Additional paid-in capital...................... 490,138 484,377
Retained earnings............................... 276,893 267,002
Unearned compensation........................... (2,217) (1,180)
------------ ------------
Total common stockholders' equity........... 899,540 884,169
Preferred stock................................. 168,085 168,085
Long-term debt.................................. 729,245 774,558
------------ ------------
1,796,870 1,826,812
------------ ------------
CURRENT LIABILITIES:
Short-term debt................................. 15,980 10,000
Long-term debt due within one year.............. 1,425 1,399
Variable rate demand bonds...................... 71,500 71,500
Accounts payable................................ 48,360 59,596
Taxes accrued................................... 27,555 7,264
Interest accrued................................ 17,941 15,459
Dividends declared.............................. 23,174 22,831
Current capital lease obligation................ 12,602 12,571
Deferred energy costs........................... 21,635 12,241
Other........................................... 25,892 27,538
------------ ------------
266,064 240,399
------------ ------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes, net...................... 507,070 505,435
Deferred investment tax credits................. 46,931 47,577
Long-term capital lease obligation.............. 18,960 19,660
Other........................................... 28,879 29,902
------------ ------------
601,840 602,574
------------ ------------
TOTAL CAPITALIZATION AND LIABILITIES $2,664,774 $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 Twelve Months Ended
March 31 March 31
----------------------- -----------------------
1995 1994 1995 1994
---------- ---------- ---------- ----------
OPERATING REVENUES
Electric............................................. $215,409 $242,753 $855,771 $908,127
Gas.................................................. 42,191 49,641 100,456 106,867
---------- ---------- ---------- ----------
257,600 292,394 956,227 1,014,994
---------- ---------- ---------- ----------
OPERATING EXPENSES
Electric fuel and purchased power.................... 73,881 88,494 267,957 311,279
Gas purchased........................................ 23,087 29,699 57,201 63,076
Operation and maintenance............................ 53,638 57,883 262,963 253,056
Depreciation......................................... 26,883 26,651 109,755 103,028
Taxes other than income taxes........................ 10,067 10,729 37,923 38,501
Income taxes......................................... 21,792 25,168 62,809 74,423
---------- ---------- ---------- ----------
209,348 238,624 798,608 843,363
---------- ---------- ---------- ----------
OPERATING INCOME....................................... 48,252 53,770 157,619 171,631
---------- ---------- ---------- ----------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains................................. 12,147 9,971 45,318 39,998
Expenses including interest and income taxes....... (10,248) (8,679) (42,359) (37,587)
---------- ---------- ---------- ----------
Net earnings of nonutility subsidiaries....... 1,899 1,292 2,959 2,411
Allowance for equity funds used during construction.. 184 706 2,867 3,700
Other income, net of income taxes.................... 386 (1,090) 1,211 (623)
---------- ---------- ---------- ----------
2,469 908 7,037 5,488
---------- ---------- ---------- ----------
INCOME BEFORE UTILITY INTEREST CHARGES................. 50,721 54,678 164,656 177,119
---------- ---------- ---------- ----------
UTILITY INTEREST CHARGES
Interest expense..................................... 15,854 15,408 62,523 63,107
Allowance for borrowed funds used during
construction....................................... (541) (371) (1,944) (2,292)
---------- ---------- ---------- ----------
15,313 15,037 60,579 60,815
---------- ---------- ---------- ----------
NET INCOME............................................. 35,408 39,641 104,077 116,304
DIVIDENDS ON PREFERRED STOCK........................... 2,519 2,264 9,625 9,762
---------- ---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK.................... $32,889 $37,377 $94,452 $106,542
========== ========== ========== ==========
COMMON STOCK
Average shares outstanding (000)..................... 59,738 59,022 59,556 58,529
Earnings per average share........................... $0.55 $0.63 $1.59 $1.82
Dividends declared per share......................... $0.38 1/2 $0.38 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)
-----------
Three Months Ended Twelve Months Ended
March 31 March 31
---------------------- -----------------------
1995 1994 1995 1994
--------- --------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.................................................... $35,408 $39,641 $104,077 $116,304
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization............................ 29,337 29,550 120,590 115,097
Allowance for equity funds used during construction...... (184) (706) (2,867) (3,700)
Investment tax credit adjustments, net................... (646) (628) (1,916) (2,514)
Deferred income taxes, net............................... (1,987) (138) 2,980 4,419
Provision for early retirement offer..................... - - 17,500 -
Net change in:
Accounts receivable................................. 1,362 (7,522) 16,864 (11,219)
Inventories......................................... 11,516 (161) (8,618) 3,732
Accounts payable.................................... (11,236) (4,823) (2,102) 2,565
Other current assets & liabilities (1).............. 32,832 32,279 (10,168) 12,039
Other, net............................................... (1,824) (2,897) (2,209) (5,046)
--------- --------- --------- ---------
Net cash provided by operating activities....................... 94,578 84,595 234,131 231,677
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures, excluding AFUDC.................... (22,393) (27,604) (148,908) (149,151)
Allowance for borrowed funds used during construction......... (541) (371) (1,944) (2,292)
Cash flows from leveraged leases:
Sale of interests in leveraged leases.................... - - - 17,699
Other.................................................... 288 274 1,606 1,529
Proceeds from the sale of subsidiary property................. - - 4,596 -
Investment in subsidiary projects and operations.............. (712) (978) (10,779) (2,390)
Net (increase)/decrease in bond proceeds held in trust funds.. (123) 7 (11,946) 473
Deposits to nuclear decommissioning trust funds............... (644) (671) (2,411) (2,312)
Other, net.................................................... (824) (3,681) 521 (802)
--------- --------- --------- ---------
Net cash used by investing activities........................... (24,949) (33,024) (169,265) (137,246)
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends: Common.......................................... (22,873) (22,618) (91,430) (89,762)
Preferred....................................... (2,302) (2,313) (9,453) (9,974)
Issuances: Long-term debt (2).............................. - - 4,640 148,200
Variable rate demand bonds...................... - - 30,000 15,500
Common stock.................................... 6,518 7,943 13,549 30,818
Preferred stock................................. - - - 20,000
Redemptions: Long-term debt.................................. (273) (198) (26,171) (184,225)
Variable rate demand bonds...................... - - - (15,500)
Common stock.................................... (1,223) (794) (1,223) (799)
Preferred stock................................. - - - (28,280)
Principal portion of capital lease payments................... (2,454) (2,899) (10,835) (10,028)
Net change in term loan....................................... (45,000) (10,000) - -
Net change in short-term debt ................................ 5,981 - 15,981 (2,000)
Cost of issuances and refinancings............................ - (41) (560) (10,593)
--------- --------- --------- ---------
Net cash used by financing activities........................... (61,626) (30,920) (75,502) (136,643)
--------- --------- --------- ---------
Net change in cash and cash equivalents......................... 8,003 20,651 (10,636) (42,212)
Cash and cash equivalents at beginning of period................ 25,029 23,017 43,668 85,880
--------- --------- --------- ---------
Cash and cash equivalents at end of period...................... $33,032 $43,668 $33,032 $43,668
========= ========= ========= =========
(1) Other than debt classified as current and current deferred income taxes.
(2) Excluding net change in term loan.
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 and Part II of this Report on Form 10-Q for additional
relevant information.
2. BASE RATE MATTERS
-----------------
Below is an update to matters previously reported on under "Regulatory and
Rate Matters-Base Rate Proceedings" in Part I of the Company's 1994 Annual
Report on Form 10-K.
Delaware and Maryland Limited Issues Electric Base Rate Cases
- ------------------------------------------------------------
In 1994, the Company filed applications with the Delaware Public Service
Commission (DPSC) and Maryland Public Service Commission (MPSC) for increases
in electric base rates of $13.5 million and $3.9 million, respectively. The
Company subsequently revised its proposed Delaware increase to $11.1 million.
Both these cases were designed to recover the cost of "limited issues," which
are primarily costs imposed by government and are outside the reasonable
control of the Company.
On April 18, 1995, the DPSC approved a proposed joint resolution submitted by
the Company and two customer groups. The resolution provides for the
following:
- - A $4.5 million base rate increase effective May 1, 1995. The increase
when netted with reduced electric fuel rates will result in an overall
decrease in revenues of $7.0 million or 1.45%.
- - A rate moratorium whereby the Company will not increase its total electric
base revenues before January 1, 1997. However, the Company is permitted
to file for a redesign of electric base rates which would not result in a
change in total electric base revenues.
- - A rate reduction provision whereby the Company will voluntarily file to
reduce its electric base rates prospectively if its return on common
equity, as adjusted for unusual items and abnormal weather, exceeds its
currently approved rate of 11.5%. However, in such event, the Company
retains the right to submit an alternative proposal which would not result
in reduced rates. The return on common equity test will be performed
quarterly beginning with the twelve-month period ended December 31, 1995
and continuing through the twelve-month period ended December 31, 1996.
- - Funding of nuclear decommissioning costs at the current Nuclear Regulatory
Commission (NRC) minimum financial assurance amount of $118 million, of
which the Delaware portion is $68 million. See Note 8 to the Consolidated
Financial Statements in the Company's Annual Report to Stockholders for a
further discussion of the Company's accounting and funding policies for
nuclear decommissioning.
- 6 -
On April 4, 1995, the MPSC denied the Company's application to increase
rates. Subsequently, the MPSC instituted a new proceeding to examine the
reasonableness of the Company's existing base rates stating that it was
unable to determine whether current base rates were reasonable due to the
test period used and the limited issues format.
Virginia Electric Base Rates
- ----------------------------
On April 28, 1995, the Company informed the Virginia State Corporation
Commission (VSCC) of its intent to file for an increase in electric base
rates on or after June 30, 1995. The amount of the increase to be requested
has not been determined. Virginia electric operating revenues were 3% of
total 1994 electric operating revenues.
3. COMMON STOCK
------------
During the first quarter of 1995, the Company issued 336,143 shares of common
stock for $6,518,212 primarily through the Dividend Reinvestment and Common
Share Purchase Plan (DRIP). As of March 31, 1995, 59,878,149 shares of
Common Stock were outstanding.
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.
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 (PRP) 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.
- 7 -
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
----------------------------------
Three Months Ended Twelve Months Ended
March 31, March 31,
------------------- --------------------
(Dollars in Thousands) 1995 1994 1995 1994
-------- -------- -------- --------
Cash paid for
Interest, net of amounts
capitalized $12,151 $11,546 $58,442 $60,084
Income taxes, net of refunds $6,685 $2,863 $73,080 $65,858
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 Twelve Months Ended
March 31, March 31,
------------------- --------------------
(Dollars in Thousands) 1995 1994 1995 1994
-------- -------- -------- --------
Revenues and Gains
Landfill and waste hauling $3,183 $2,763 $14,606 $12,296
Operating services 5,480 4,724 23,224 22,538
Other revenues 365 1,679 3,610 3,479
Leveraged leases 94 53 313 146
Other investment income 3,025 752 3,565 1,539
-------- -------- -------- --------
12,147 9,971 45,318 39,998
-------- -------- -------- --------
Cost and Expenses
Operating expenses 9,126 7,822 39,789 36,957
Interest expense, net 74 15 430 (17)
Income taxes 1,048 842 2,140 647
-------- -------- -------- --------
10,248 8,679 42,359 37,587
-------- -------- -------- --------
Net income $ 1,899 $ 1,292 $ 2,959 $ 2,411
======== ======== ======== ========
Earnings per share of common
stock attributed to subsidiaries $0.03 $0.02 $0.05 $0.04
- 8 -
SELECTED FINANCIAL AND OPERATING DATA
-------------------------------------
(Dollars in Thousands)
3 Months Ended 12 Months Ended
March 31 March 31
------------------------ ------------------------
1995 1994 1995 1994
----------- ----------- ----------- -----------
Electric Revenues
- -----------------
Residential $84,591 $92,748 $304,067 $318,213
Commercial 58,801 59,499 241,808 242,828
Industrial 36,064 34,786 146,872 149,584
Resale 16,098 29,549 91,899 107,483
Other Sales Revenues(1) (1,825) (2,722) 7,713 7,608
----------- ----------- ----------- -----------
Sales Revenues 193,729 213,860 792,359 825,716
Interchange Deliveries 18,873 26,960 54,301 76,136
Miscellaneous Revenues 2,807 1,933 9,111 6,275
----------- ----------- ----------- -----------
Total Electric Revenues $215,409 $242,753 $855,771 $908,127
=========== =========== =========== ===========
Electric Sales
- --------------
(1000 kWh)
Residential 1,040,004 1,176,817 3,441,930 3,650,745
Commercial 877,659 892,149 3,446,568 3,404,975
Industrial 801,045 771,067 3,278,109 3,231,590
Resale 320,242 596,521 1,889,875 2,186,051
Other sales (2) (47,187) (65,354) 69,162 33,173
----------- ----------- ----------- -----------
Total Electric Sales 2,991,763 3,371,200 12,125,644 12,506,534
=========== =========== =========== ===========
Gas Revenues
- ------------
Sales (1) $41,590 $49,362 $98,494 $105,834
Gas Transportation Revenues 482 172 1,501 590
Miscellaneous Revenues 119 107 461 443
----------- ----------- ----------- -----------
Total Gas Revenues $42,191 $49,641 $100,456 $106,867
=========== =========== =========== ===========
Gas Sales and Gas Transported
- -----------------------------
(1000 mcf)
Sales (2) 7,201 7,880 17,409 18,686
Gas Transported 737 328 2,663 1,369
----------- ----------- ----------- -----------
Total 7,938 8,208 20,072 20,055
=========== =========== =========== ===========
March 31, 1995 December 31, 1994 March 31, 1994
------------------------ ------------------------ ------------------------
$ % $ % $ %
----------- ----------- ----------- ----------- ----------- -----------
Capitalization
- --------------
Variable Rate Demand Bonds(3) $71,500 3.8 $71,500 3.8 $41,500 2.3
Long-Term Debt 729,245 39.0 774,558 40.8 726,230 39.9
Preferred Stock 168,085 9.0 168,085 8.8 168,085 9.2
Common Stockholders' Equity 899,540 48.2 884,169 46.6 884,081 48.6
----------- ----------- ----------- ----------- ----------- -----------
Total $1,868,370 100.0 $1,898,312 100.0 $1,819,896 100.0
=========== =========== =========== =========== =========== ===========
(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
- --------
The earnings per average share of common stock attributed to the core utility
business and nonutility subsidiaries are shown below.
Three Months Twelve Months
Ended Ended
---------------- ----------------
3/31/95 3/31/94 3/31/95 3/31/94
------- ------- ------- -------
Core Utility
Operations $0.52 $0.61 $1.72 $1.78
Early retirement offer - - (0.18) -
------- ------- ------- -------
0.52 0.61 1.54 1.78
Nonutility subsidiaries 0.03 0.02 0.05 0.04
------- ------- ------- -------
$0.55 $0.63 $1.59 $1.82
======= ======= ======= =======
The components of change from the prior year in core utility earnings per
share are shown below.
Increase (Decrease) in
Earnings Per Share
------------------------------
Three Months Twelve Months
Ended Ended
March 31 March 31
1995 vs 1994 1995 vs 1994
------------ ------------
Operations
Revenues, net of fuel expense
Rate increases $0.02 $0.07
Portion of electric resale business
supplied by another utility (0.06) (0.06)
Sales volume and other (0.10) (0.11)
Operation and maintenance expense 0.04 0.08
Depreciation - (0.07)
Other 0.01 0.03
------ ------
(0.09) (0.06)
Early retirement offer - (0.18)
------ ------
($0.09) ($0.24)
====== ======
CORE UTILITY EARNINGS
- ---------------------
Earnings per share from core utility operations decreased $0.09 and $0.06
for the three- and twelve-month periods ended March 31, 1995, respectively,
compared to the same periods last year. In both periods, net revenues
declined due primarily to a decrease in sales which resulted from weather
conditions and an electric resale customer's purchase of about one-half of
its power from another utility beginning January 1995. The declines in net
revenues were partially offset by lower operation and maintenance costs. In
addition to these factors, the twelve-month period earnings per share
comparison also reflects an $0.18 decrease due to the Company's early
retirement offer (ERO) which was recorded in the third quarter of 1994.
- 10 -
STRATEGIC PLANS FOR COMPETITION
- -------------------------------
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 quarter of 1995, the Company
is on target to meet its year-end goal of at least an 11.5% return on equity.
Cost reduction efforts along with retail electric sales growth and price
increases will enable the Company to keep this goal on track. The only
significant update to the discussion of the "Three-Legged Stool" initiatives
in the 1994 Annual Report on Form 10-K relates to rate matters, which can be
found in Note 2 to the Consolidated Financial Statements.
For a discussion of a recent Federal Energy Regulatory Commission (FERC)
proposal to further promote competition, see Part II - Other Information,
Item 5(B) on page 16.
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 Twelve
Months Months
------ ------
Non-fuel (Base Rate) Revenue
Increased Rates $ - $ 4.7
Portion of resale business
supplied by another utility (6.1) (6.1)
Sales Volume and Other (6.9) (9.2)
Fuel Revenue (6.2) (19.9)
Interchange Delivery Revenue (8.1) (21.9)
------ ------
Total ($27.3) ($52.4)
====== ======
Electric Non-fuel (Base Rate) Revenue
- -------------------------------------
The electric non-fuel (base rate) revenue increase shown above as "Increased
Rates" for the twelve-month period is primarily due to a $24.9 million annual
increase in Delaware effective June 1, 1993.
Electric non-fuel revenues decreased $6.1 million in both 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.
- 11 -
Percentage changes in kWh sales billed by customer class are shown below.
The percentage changes for resale, total billed sales, and total sales
reflect the elimination of the effect of ODEC's electricity purchase from
another utility.
Percentage Increase (Decrease) in kWh Sales
From Comparable Period in Prior Year
-------------------------------------------
Three Twelve
Customer Class Months Months
-------------- ------ ------
Residential (11.6)% (5.7)%
Commercial (1.6) 1.2
Industrial 3.9 1.4
Resale (11.3) (4.0)
Total Billed Sales (5.5) (1.6)
Total Sales, including
Unbilled Sales (5.1)% (1.4)%
Excluding the effect of ODEC's electricity purchase from another utility,
electric non-fuel revenues from "Sales Volume and Other" variances decreased
$6.9 million and $9.2 million for the three- and twelve-month periods,
respectively, primarily due to decreased sales in weather sensitive customer
classes. The decreased residential and resale sales in both periods reflect
a heating season that was mild compared to the significantly colder weather
experienced during the prior year. In addition, the current twelve-month
period also reflects a summer cooling season that was not as hot as the
previous year. Commercial sales were less affected by weather. Mitigating
the impact of weather on current period sales was 1.6% annual customer
growth. Industrial sales increased for both periods mainly due to increased
production levels of certain large customers.
Electric Fuel Revenue
- ---------------------
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.
Fuel revenues decreased $6.2 million for the three-month period due to lower
kWh sales. Fuel revenues decreased $19.9 million for the twelve-month period
due primarily to lower fuel rates as well as lower kWh sales.
Interchange Delivery Revenue
- ----------------------------
Interchange delivery revenues are reflected in the calculation of rates
charged to customers under fuel adjustment clauses and, thus, do not affect
net income. Interchange delivery revenues benefit customers by reducing the
effective cost of fuel billed to customers. For the three- and twelve-month
periods, interchange delivery revenues decreased $8.1 million and $21.9
million, respectively, mainly due to lower sales to the Pennsylvania-New
Jersey-Maryland Interconnection Association (PJM Interconnection) which
resulted from decreased demand for electricity in the region.
- 12 -
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 Twelve
Months Months
------ ------
Non-fuel (Base Rate) Revenue
Rate Increase $1.6 $2.1
Sales Volume and Other (1.8) (1.6)
Fuel Revenue (7.3) (6.9)
------ ------
Total ($7.5) ($6.4)
====== ======
The gas non-fuel (base rate) revenue increases for both 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 $1.8
million for the three-month period and $1.6 million for the twelve-month
period due primarily to decreases in firm sales of 11.8% and 10.7%,
respectively. The sales decreases for both periods resulted from a heating
season that was mild compared to the significantly colder weather
experienced during the prior year. Mitigating the impact of weather on
current period sales was 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 decreased 3.3% for the
three-month period and remained flat for the twelve-month period.
Gas fuel revenues decreased $7.3 million and $6.9 million for the three- and
twelve-month periods, respectively, due to decreased firm sales and lower
average fuel rates charged to customers.
ELECTRIC FUEL AND PURCHASED POWER EXPENSES
- ------------------------------------------
For the three months ended March 31, 1995, electric fuel and purchased power
expenses decreased $14.6 million for the following reasons. (1) Expenses
decreased $10.8 million due to a lower average cost per kWh of output which
was primarily the result of lower priced purchased power and greater output
from lower priced gas generation. (2) Expenses decreased $9.3 million due
to decreased kWh output which was attributed to lower demand within the
Company's service territory and the region served by the PJM
Interconnection. (3) Expenses increased $5.5 million due to variances in
fuel costs deferred and subsequently amortized under the Company's fuel
adjustment clauses.
For the twelve months ended March 31, 1995, electric fuel and purchased
power expenses decreased $43.3 million for the following reasons. (1)
Expenses decreased $21.3 million due to a lower average cost per kWh of
output which was primarily the result of lower priced purchased power and
greater output from lower priced gas generation. (2) Expenses decreased
$15.9 million due to decreased kWh output which was attributed to lower
demand within the Company's service territory and the region served by the
PJM Interconnection. (3) Expenses decreased $6.1 million due to variances
in fuel costs deferred and subsequently amortized under the Company's fuel
adjustment clauses.
- 13 -
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 March 31, 1995, the Company's output for load within
its service territory was provided by 42% coal generation, 30% oil and gas
generation, 16% nuclear generation, and 12% net purchased power.
OPERATION, MAINTENANCE, DEPRECIATION, AND INCOME TAX EXPENSES
- -------------------------------------------------------------
For the three months ended March 31, 1995, compared to the same period a year
ago, operation and maintenance expenses decreased $4.2 million primarily due
to lower salary and wages as a result of the 1994 ERO and lower storm damage
expenses. For the twelve months ended March 31, 1995, compared to the same
period a year ago, operation and maintenance expenses increased $9.9 million.
Costs increased as a result of the $17.5 million ERO charge recorded in the
third quarter of 1994 as well as certain other expenses, including
postretirement benefits other than pensions. These increases were partially
offset by a reduction in pension expense, salary and wage expense savings
from the ERO, and lower storm damage expenses.
Depreciation increased $6.7 million for the twelve-month period primarily due
to plant additions.
Income tax expense on operations decreased $3.4 million and $11.6 million for
the three- and twelve-month periods primarily due to lower pre-tax income.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
For the three months ended March 31, 1995, utility construction expenditures
were $22.4 million compared to $27.6 million for the same period last year.
For the twelve months ended March 31, 1995 and March 31, 1994, utility
construction expenditures were $148.9 million and $149.2 million,
respectively. Internally generated funds provided approximately 89% of the
cash required for construction during the twelve months ended March 31,
1995, and March 31, 1994.
As of March 31, 1995, the Company had repaid its term loan which had a $45
million balance as of December 31, 1994. During the three months ended March
31, 1995, $6.5 million of common stock was issued primarily through the
Company's DRIP.
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,
March 31, ----------------------------------------
1995 1994 1993 1992 1991 1990
---- ---- ---- ---- ---- ----
Ratio of Earnings to Fixed Charges (SEC Method) 3.37X 3.49X 3.47X 3.03X 2.58X 2.03X
Ratio of Earnings to Fixed Charges (SEC Method)
as Adjusted 3.61X 3.74X 3.47X 2.78X 2.58X 2.89X
- 14 -
Adjusted ratios reflect the following pre-tax amounts: for the twelve months
ended March 31, 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
Energy Company (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.
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 were $0.03 for the first
quarter of 1995 and $0.02 for the first quarter of 1994. The $0.01 increase
was primarily due to higher recoveries of previously written off joint
venture assets, partially offset by the first quarter 1994 gain on sale of a
mini-storage facility.
Earnings per share of nonutility subsidiaries were $0.05 and $0.04 for the
twelve months ended March 31, 1995 and 1994, respectively. The $0.01
increase was primarily due to higher recoveries of previously written off
joint venture assets and improved operating results of the solid waste
group. These earnings increases were largely offset by an adjustment in the
current period to the realizable value of oil and gas wells and by after-tax
gains on sales of leveraged leases in the prior period.
- 15 -
PART II. OTHER INFORMATION
--------------------------
Item 5. Other Information
- --------------------------
A) Purchase of COPCO
-----------------
As previously disclosed under "Strategic Plans for Competition" in Part I of
the Company's 1994 Annual Report on Form 10-K, in 1994 the Company entered
into an agreement with PECO Energy Company to purchase its Maryland retail
electric subsidiary, Conowingo Power Company (COPCO). On March 23, 1995, the
VSCC became the third commission to approve the purchase plan. Final
regulatory approval by the FERC is expected during the second quarter of
1995.
B) Notice of Proposed Rulemaking Issued by the FERC
------------------------------------------------
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR)
which promotes open access non-discriminatory transmission services by public
utilities and also provides guidelines for the recovery of stranded costs.
A primary goal of the proposed rules is to facilitate competitive wholesale
power markets by assuring that all wholesale sellers of generation have the
opportunity to compete on a fair basis and that all wholesale purchasers can
reach alternative suppliers. The FERC finds that the key to competitive bulk
power markets is access to transmission services. Utilities with
transmission facilities would be required to file open access tariffs
offering wholesale transmission services to third parties on a non-
discriminatory basis as to price and non-price terms and conditions.
Utilities would be required to offer transmission to eligible customers
comparable to the service they provide themselves. Also, the utility must
charge itself and third parties the same rates for use of the transmission
system.
In November 1994, the Company filed an open access transmission tariff in
conjunction with the planned acquisition of COPCO. The Company expects that
the FERC may suspend this filing to allow the guidelines of the final rule
resulting from the NOPR to be incorporated in the tariff.
Wholesale stranded costs are costs incurred by a public utility to provide
service to a wholesale requirements customer that subsequently chooses an
alternate supplier for all or part of its power needs. Stranded costs may
also result from municipalization and former retail customers becoming
wholesale customers. The FERC proposed that for contracts executed before
July 11, 1994 stranded cost recovery will be allowed if the seller can
demonstrate grounds for a reasonable expectation that the customer would
renew the contract. For contracts executed after July 11, 1994, a utility
may not seek recovery of stranded costs unless explicitly permitted in the
contract. Virtually all of the Company's electric wholesale business is
conducted pursuant to contracts executed after July 11, 1994 and these
contracts do not include provisions specific to stranded costs. However, 95%
of the Company's electric municipal business is under contracts for extended
terms of eight to twenty years and the Company's contracts with its other
electric wholesale customers include notice provisions for load reductions.
As to stranded costs that may result if retail power markets are opened, the
FERC concluded that these costs should be addressed by state regulatory
commissions.
The Company is continuing to evaluate the NOPR to determine its full impact
on the Company and its customers. Comments on the NOPR are due August 7,
1995. It is anticipated that a final rule could take effect in early 1996.
The Company cannot predict the outcome of this matter.
- 16 -
C) Salem
-----
1) General Update on Operations
----------------------------
The following is an update to matters disclosed under "Power
Plants-Salem Units" in Part I of the Company's 1994 Annual Report on
Form 10-K.
Public Service Electric and Gas Company (PSE&G) has informed the
Company that on March 21, 1995, representatives of the NRC staff met
with the Boards of Directors of Public Service Enterprise Group,
Incorporated and PSE&G to reiterate the previously expressed concerns
with regard to Salem's operations, including plant materiel
conditions that required operators to operate various systems
manually, maintenance backlog, root cause analysis, quality
assurance, engineering, repeat equipment failures, procedure
adherence, four events over the past four years causing the NRC to
conduct four Augmented Inspected Team reviews, leadership, employee
concerns, attention to balance of plant, management oversight and
vertical communication with employees and oversight of contractors.
The NRC staff acknowledged that PSE&G had made efforts to improve
Salem's operations, including making senior management changes, but
indicated that demonstrated sustained results have not yet been
achieved.
Also in March 1995, the Institute of Nuclear Power Operations (INPO)
reported an assessment of Salem's operations that indicated that
improvement was needed in a wide range of areas, with significant
improvement required in areas such as equipment performance and plant
materiel conditions, management and supervision, engineering
activities and training.
On April 21, 1995, the NRC commenced an inspection, expected to take
about four weeks, 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. This inspection is
currently ongoing.
As previously stated, PSE&G is in agreement with the assessment of
the NRC staff, as well as that of INPO, that Salem's operations must
be further improved in order to assure continued reliable operation.
PSE&G is fully committed to take the actions needed to improve
Salem's operations and is committed to safe and conservative
operations before production.
PSE&G cannot predict what further action, if any, it or the NRC may
take in respect of Salem's operations.
The Company continues to closely monitor Salem's operations and has
expressed its concerns to PSE&G's management. In this connection, on
March 30, 1995, the Company's Nuclear Oversight Committee of the Board
met with PSE&G's chief nuclear officer to better understand the NRC's
concerns with, and to voice the Company's desire to see improvements
in, Salem's operations.
- 17 -
2) Notice of Violation and Penalty
-------------------------------
PSE&G has informed the Company that on April 12, 1995, PSE&G received
notification of a Level II violation including an $80,000 civil
penalty for an incident that occurred in December 1992 in which two
former Salem station managers did not properly respond to safety
concerns raised by two employees. The incident was thoroughly
investigated and brought to the NRC's attention by PSE&G at that
time. PSE&G has agreed to pay the penalty and has instituted several
measures to reinforce to personnel that their concerns about safety
and all issues relating to the operation of the nuclear facilities
can be brought openly to management's attention.
3) New Enforcement Conference
--------------------------
PSE&G has informed the Company that PSE&G has been notified of an NRC
enforcement conference to be held on June 1, 1995 pertaining to
valves that were incorrectly positioned after a plant modification
was installed in May 1993 and several examples of inadequate root
cause determination of events, which led to insufficient corrective
actions at Salem. During this enforcement conference, PSE&G will
address the issues identified and ensure they are clearly understood,
establish the safety significance of the issues and discuss the
mitigating factors related to these issues. PSE&G cannot predict
what action, if any, the NRC may take as a result of this meeting.
4) Operating Permit
----------------
The following is an update to "Environmental Matters-Salem Operating
Permit" in Part I of the Company's 1994 Annual Report on Form 10-K.
PSE&G has informed the Company that in March 1995, the State of
Delaware agreed to withdraw its hearing request related to Salem's
New Jersey Pollution Discharge Elimination System (NJPDES) permit in
return for PSE&G funding a number of environmental projects in
Delaware, similar to and including certain NJPDES permit conservation
measures, which will not materially increase the cost of compliance
with the permit. In May 1995, PSE&G resolved all issues with the
remaining interveners, thus eliminating a hearing and any further
challenge to the Salem permit.
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
-------------------
The Company did not file any Reports on Form 8-K during the first quarter of
1995.
- 18 -
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Delmarva Power & Light Company
------------------------------
(Registrant)
Date: May 11, 1995 /s/ B. S. Graham
------------------- --------------------------------
B. S. Graham, Senior Vice President,
Treasurer, and Chief Financial Officer
- 19 -
EXHIBIT INDEX
-------------
Exhibit Page
Number Number
------- -------
Computation of ratio of earnings to fixed charges 12 21
Financial Data Schedule 27 22
- 20 -