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, 1994
-----------------------------------------------
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________________ to _____________________
Commission file number 1-1405
DELMARVA POWER & LIGHT COMPANY
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Delaware and Virginia 51-0084283
- ---------------------------- -------------------
(States of incorporation) (I.R.S. Employer
Identification No.)
800 King Street, P.O. Box 231, Wilmington, Delaware 19899
- --------------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 302-429-3011
------------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at October 31, 1994
- ----------------------------- -------------------------------
Common Stock, $2.25 par value 59,542,006 Shares
DELMARVA POWER & LIGHT COMPANY
------------------------------
Table of Contents
-----------------
Page No.
--------
Part I. Financial Information:
Consolidated Balance Sheets as of September 30, 1994
and December 31, 1993................................... 2-3
Consolidated Statements of Income for the three, nine,
and twelve months ended September 30, 1994 and 1993..... 4
Consolidated Statements of Cash Flows for the nine and
twelve months ended September 30, 1994 and 1993......... 5
Notes to Consolidated Financial Statements.............. 6-9
Selected Financial and Operating Data................... 10
Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 11-20
Part II. Other Information and Signature............................ 21-27
-1-
PART I. FINANCIAL INFORMATION
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
September 30, December 31,
1994 1993
------------ -----------
(Unaudited)
ASSETS
------
UTILITY PLANT, AT ORIGINAL COST:
Electric........................................ $2,641,479 $2,561,507
Gas............................................. 188,358 176,167
Common.......................................... 131,731 122,182
----------- -----------
2,961,568 2,859,856
Less: Accumulated depreciation................. 1,050,906 989,351
----------- -----------
Net utility plant in service.................... 1,910,662 1,870,505
Construction work-in-progress................... 75,722 91,001
Leased nuclear fuel, at amortized cost.......... 30,163 33,905
----------- -----------
2,016,547 1,995,411
----------- -----------
INVESTMENTS AND NONUTILITY PROPERTY:
Investment in leveraged leases.................. 49,903 50,914
Funds held by trustee........................... 20,154 17,577
Other investments and nonutility property, net.. 60,180 55,248
----------- -----------
130,237 123,739
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents....................... 29,591 23,017
Accounts receivable:
Customers................................... 93,293 98,472
Other....................................... 13,258 18,405
Inventories, at average cost:
Fuel (coal, oil, and gas)................... 38,095 27,335
Materials and supplies...................... 37,393 37,687
Prepayments..................................... 10,760 9,534
Deferred income taxes, net...................... 7,625 10,713
----------- -----------
230,015 225,163
----------- -----------
DEFERRED CHARGES AND OTHER ASSETS:
Unamortized debt expense........................ 11,039 11,222
Deferred debt refinancing costs................. 27,102 28,794
Deferred recoverable plant costs................ 14,206 15,613
Deferred recoverable income taxes............... 120,464 144,463
Other........................................... 40,489 49,124
----------- -----------
213,300 249,216
----------- -----------
TOTAL ASSETS $2,590,099 $2,593,529
=========== ===========
See accompanying Notes to Consolidated Financial Statements.
-2-
DELMARVA POWER & LIGHT COMPANY
------------------------------
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
----------------------
September 30, December 31,
1994 1993
------------ -----------
(Unaudited)
CAPITALIZATION AND LIABILITIES
------------------------------
CAPITALIZATION:
Common stock.................................... $133,970 $132,366
Additional paid-in capital...................... 484,377 470,997
Retained earnings............................... 273,793 259,507
Unearned compensation........................... (1,125) (675)
----------- -----------
Total common stockholders' equity........... 891,015 862,195
Preferred stock................................. 168,085 168,085
Long-term debt.................................. 746,732 736,368
----------- -----------
1,805,832 1,766,648
----------- -----------
CURRENT LIABILITIES:
Long-term debt due within one year.............. 26,211 25,986
Variable rate demand bonds...................... 41,500 41,500
Accounts payable................................ 46,105 55,175
Taxes accrued................................... 9,754 10,987
Interest accrued................................ 18,602 15,522
Dividends declared.............................. 22,853 22,664
Current capital lease obligation................ 12,604 12,684
Deferred energy costs........................... 11,996 14,229
Other........................................... 30,839 32,681
----------- -----------
220,464 231,428
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes, net...................... 468,289 497,457
Deferred investment tax credits................. 47,590 49,475
Long-term capital lease obligation.............. 19,538 23,335
Other........................................... 28,386 25,186
----------- -----------
563,803 595,453
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $2,590,099 $2,593,529
=========== ===========
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
-------------------- -------------------- --------------------
1994 1993 1994 1993 1994 1993
--------- --------- --------- --------- --------- ---------
OPERATING REVENUES
Electric............................................. $248,309 $263,991 $688,996 $670,516 $894,144 $853,735
Gas.................................................. 12,292 11,394 82,464 67,514 109,893 91,695
--------- --------- --------- --------- --------- ---------
260,601 275,385 771,460 738,030 1,004,037 945,430
--------- --------- --------- --------- --------- ---------
OPERATING EXPENSES
Electric fuel and purchased power.................... 70,610 80,487 217,325 224,505 291,127 287,857
Gas purchased........................................ 7,318 7,030 50,039 38,179 65,491 50,149
Operation and maintenance............................ 83,971 61,867 207,055 177,090 278,016 240,249
Depreciation......................................... 27,749 26,538 81,620 74,405 108,144 98,722
Taxes other than income taxes........................ 10,212 10,207 29,923 28,560 38,782 37,537
Income taxes......................................... 17,820 30,241 54,813 58,759 64,186 66,088
--------- --------- --------- --------- --------- ---------
217,680 216,370 640,775 601,498 845,746 780,602
--------- --------- --------- --------- --------- ---------
OPERATING INCOME....................................... 42,921 59,015 130,685 136,532 158,291 164,828
--------- --------- --------- --------- --------- ---------
OTHER INCOME
Nonutility Subsidiaries
Revenues and gains................................. 11,027 9,026 31,783 25,425 43,993 28,575
Expenses including interest and income taxes....... (10,576) (9,218) (29,438) (23,655) (41,610) (26,610)
--------- --------- --------- --------- --------- ---------
Net earnings (loss) of nonutility subsidiaries.. 451 (192) 2,345 1,770 2,383 1,965
Allowance for equity funds used during construction.. 852 613 2,577 4,675 3,211 6,645
Other income, net of income taxes.................... 143 357 (884) 11 (384) 561
--------- --------- --------- --------- --------- ---------
1,446 778 4,038 6,456 5,210 9,171
--------- --------- --------- --------- --------- ---------
INCOME BEFORE UTILITY INTEREST CHARGES................. 44,367 59,793 134,723 142,988 163,501 173,999
--------- --------- --------- --------- --------- ---------
UTILITY INTEREST CHARGES
Debt................................................. 14,415 14,911 42,860 46,151 57,140 62,474
Other................................................ 1,041 996 3,420 2,383 4,701 3,078
Allowance for borrowed funds used during
construction....................................... (455) (393) (1,340) (2,997) (1,747) (4,424)
--------- --------- --------- --------- --------- ---------
15,001 15,514 44,940 45,537 60,094 61,128
--------- --------- --------- --------- --------- ---------
NET INCOME............................................. 29,366 44,279 89,783 97,451 103,407 112,871
DIVIDENDS ON PREFERRED STOCK........................... 2,358 2,490 6,945 7,472 9,475 9,979
--------- --------- --------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK.................... $27,008 $41,789 $82,838 $89,979 $93,932 $102,892
========= ========= ========= ========= ========= =========
COMMON STOCK
Average shares outstanding (000)..................... 59,542 58,372 59,322 57,180 59,164 56,381
Earnings per average share........................... $0.46 $0.72 $1.40 $1.57 $1.59 $1.82
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
---------------------- ----------------------
1994 1993 1994 1993
-------- -------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $89,783 $97,451 $103,407 $112,871
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization.......................... 90,321 84,705 118,542 111,934
Allowance for equity funds used during construction.... (2,577) (4,675) (3,211) (6,645)
Investment tax credit adjustments, net................. (1,885) (1,886) (2,514) (2,407)
Deferred income taxes, net............................. (1,925) (9,584) 6,488 (4,707)
Provision for early retirement offer................... 17,500 - 17,500 -
Net change in :
Accounts receivable............................... 10,312 (18,969) 13,430 (19,264)
Inventories....................................... (10,466) 2,866 (7,064) 6,304
Accounts payable.................................. (9,180) (25,669) 15,301 (15,188)
Other current assets & liabilities*............... (4,433) 45,783 (39,167) 13,408
Other,net.............................................. (450) (4,756) (1,131) (3,981)
-------- -------- -------- --------
Net cash provided by operating activities..................... 177,000 165,266 221,581 192,325
-------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures, excluding AFUDC................ (98,680) (117,995) (140,676) (177,899)
Allowance for borrowed funds used during construction..... (1,340) (2,997) (1,747) (4,424)
Cash flows from leveraged leases:
Insurance proceeds from casualty loss.................. - - - 4,115
Sale of interests in leveraged leases.................. - 21,603 (61) 21,603
Other.................................................. 1,201 1,139 1,573 1,862
Proceeds from the sale of subsidiary property............. 4,596 - 4,596 -
Investment in subsidiary projects and operations.......... (10,512) (3,276) (10,063) (2,983)
(Increase)/decrease in bond proceeds held in trust funds.. 7 (3,184) 4,343 3,562
Deposits to nuclear decommissioning trust funds........... (1,849) (2,110) (2,396) (2,548)
Other, net................................................ (4,358) (1,498) (3,249) 2,293
-------- -------- -------- --------
Net cash used by investing activities......................... (110,935) (108,318) (147,680) (154,419)
-------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends: Common..................................... (68,270) (65,476) (90,783) (86,177)
Preferred.................................. (7,030) (7,386) (9,686) (9,906)
Issuances: Long-term debt............................. 4,640 148,200 4,640 245,535
Variable rate demand bonds................. - - 15,500 -
Common stock............................... 14,974 102,137 22,300 109,804
Preferred stock............................ - - 20,000 -
Redemptions: Long-term debt............................. (600) (183,764) (1,042) (280,942)
Variable rate demand bonds................. - - (15,500) -
Common stock............................... (794) (743) (799) (743)
Preferred stock............................ - - (28,280) -
Principal portion of capital lease payments............... (8,701) (8,259) (10,398) (11,171)
Net change in term loan................................... 6,500 - 16,500 -
Net change in short-term debt ............................ - (17,000) - (3,500)
Cost of issuances and refinancings........................ (210) (11,192) (2,115) (17,056)
-------- -------- -------- --------
Net cash used by financing activities......................... (59,491) (43,483) (79,663) (54,156)
-------- -------- -------- --------
Net change in cash and cash equivalents....................... 6,574 13,465 (5,762) (16,250)
Cash and cash equivalents at beginning of period.............. 23,017 21,888 35,353 51,603
-------- -------- -------- --------
Cash and cash equivalents at end of period.................... $29,591 $35,353 $29,591 $35,353
======== ======== ======== ========
*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 1993 Annual Report to
Stockholders, the Company's Reports on Form 10-Q for the first and second
quarters of 1994, and Part II of this Report on Form 10-Q for additional
relevant information.
2. ACCOUNTING PRINCIPLE ADOPTED IN THE FIRST QUARTER OF 1994
---------------------------------------------------------
For information concerning the Company's adoption of Statement of Financial
Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt
and Equity Securities," refer to Note 3 to the Consolidated Financial Statements
included in the Company's Report on Form 10-Q for the first quarter of 1994.
3. BASE RATE MATTERS
-----------------
Below is an update to matters previously reported on under "Regulatory and Rate
Matters--Base Rate Proceedings" in Part I of the Company's 1993 Annual Report on
Form 10-K and the notes to the Consolidated Financial Statements of the
Company's Reports on Form 10-Q for the first and second quarters of 1994.
Resale Electric Rates
- ---------------------
On October 30, 1992, the Company filed an application with the Federal Energy
Regulatory Commission (FERC) for an increase in electric base rates. The
Company subsequently reached settlement agreements (in principle) with all of
its resale customers allowing for an increase of $1.5 million or 1.5%. The FERC
approved the Company's settlement agreements with Old Dominion Electric
Cooperative (ODEC) in June 1994 and the Town of Berlin, Maryland in August 1994.
A settlement agreement with the Company's remaining resale customers was filed
with the FERC on September 14, 1994, and is expected to be approved in the
fourth quarter of 1994.
On November 2, 1994, the Company and ODEC filed a settlement agreement with the
FERC on how transmission services and partial energy requirements will be
supplied for the next ten years. The agreement defines the terms, conditions,
and pricing for ODEC to wheel 150 megawatts (MW) of power from alternate
suppliers through the Company's transmission system and provides a pricing
mechanism under which the Company will supply the balance of ODEC's power
requirements.
Delaware Gas Base Rates
- -----------------------
On May 6, 1994, the Company filed an application with the Delaware Public
Service Commission (DPSC) for a $4.2 million or 4.1% increase in gas base rates.
On July 5, 1994, an interim $1 million rate increase became effective, subject
to refund. On October 18, 1994, the DPSC approved a settlement agreement for a
$3.1 million or 3.1% increase, reflecting an 11.5% return on equity. The
increase is effective November 1, 1994, at which time lower fuel rates will also
become effective. The reduced fuel rates, when combined with the base rate
increase, result in a net average decrease of 1.75%.
-6-
Limited Issue Electric Base Rate Cases
- --------------------------------------
On August 16, 1994, the Company filed an application with the DPSC for a $13.5
million increase in electric base rates. The increase, when netted with fuel
savings related to the reduction in load from ODEC beginning in 1995, is $8.8
million or 1.8%. This "limited issue" increase is designed to recover costs
specific to the Company's compliance with the Clean Air Act Amendments of 1990,
the one-percent increase in the marginal federal income tax rate to 35%, demand
side management and conservation programs, and an increase in funding for
nuclear decommissioning based on the current Nuclear Regulatory Commission (NRC)
minimum funding requirements. The Company is requesting that final rates become
effective January 1, 1995. On November 2, 1994, the Company notified the DPSC
that if final rates are not approved by January 1, 1995, the Company would place
a $1 million interim rate increase into effect, subject to refund, as allowed
under Delaware law. The Company is permitted to implement the requested
increase, subject to refund, on March 16, 1995, if the case is not decided prior
to that date.
On September 1, 1994, the Company filed an application with the Maryland Public
Service Commission (MPSC) for a $3.9 million increase in electric base rates.
The increase, when netted with ODEC related fuel savings, is $2.2 million or
1.1%. This "limited issue" increase is designed to recover costs similar to
those in the Delaware "limited issue" case, except for demand side management
and conservation program costs which are recoverable from Maryland customers
through a surcharge. The Company is requesting that final rates become
effective January 1, 1995. The Company is permitted to implement the requested
increase, subject to refund, on March 30, 1995, if the case is not decided prior
to that date. On November 7, 1994, the Staff of the MPSC filed testimony
proposing a base rate decrease of $13.3 million. The Company strongly opposes
the Staff's position, which focuses on issues beyond the scope of the "limited
issue" filing. The Company plans to file rebuttal testimony on December 5,
1994.
4. COMMON STOCK
------------
During the first nine months of 1994, the Company issued 712,723 shares of
common stock for $14,973,335 primarily through the Dividend Reinvestment and
Common Share Purchase Plan (DRIP). As of September 30, 1994, 59,542,006 shares
of Common Stock were outstanding. Effective June 1, 1994, the shares acquired
for the DRIP began to be purchased on the open market rather than through the
issuance of new shares.
5. DEBT
----
The Company redeemed its 4 5/8% First Mortgage Bonds, $25 million principal
amount, at maturity on October 1, 1994.
On October 12, 1994, the Delaware Economic Development Authority issued on
behalf of the Company $30 million of Variable Rate Demand Gas Facilities Revenue
Bonds, due on demand or at maturity on October 1, 2029. The bonds may bear
interest at a daily rate, weekly rate, short-term interest rate, or fixed rate
as determined from time to time in accordance with the indenture. The bonds
will initially bear interest at a daily rate. Proceeds from the bonds will be
used to finance enhancements to and expansion of the Company's gas system.
Although these bonds will be classified as current liabilities, the Company
intends to use these bonds as a source of long-term financing by setting the
bonds' interest rates at market rates and, if advantageous, by utilizing one of
the fixed rate/fixed term conversion options of the bonds.
Refer to Note 10 for information concerning debt issued by a subsidiary of the
Company.
-7-
6. PURCHASE OF CONOWINGO POWER COMPANY
-----------------------------------
On May 24, 1994, the Company entered into agreements with PECO Energy Company
(PECO) to buy its Maryland retail electric subsidiary, Conowingo Power Company
(COPCO), for $150 million and to purchase capacity and energy from PECO. For
further information concerning these agreements, refer to Note 5 to the
Consolidated Financial Statements included in the Company's Report on Form 10-Q
for the second quarter of 1994.
7. EARLY RETIREMENT OFFER
----------------------
In the third quarter of 1994, the Company completed a one-time voluntary early
retirement offer (ERO) for all management and union employees at least 55 years
old with at least 10 years of continuous service by December 31, 1994. The ERO
was accepted by approximately 10% of the Company's workforce (about 300 people),
which represents an 82% participation rate among eligible employees. In
accordance with SFAS No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits," the
Company recorded the costs associated with the ERO of $17.5 million ($10.675
million after taxes or $0.18 per share) as a one-time charge in the third
quarter of 1994.
8. CONTINGENCIES
-------------
Nuclear Insurance
- -----------------
In the event of an incident at any commercial nuclear power plant in the
United States, the Company could be assessed for a portion of any third-party
claims associated with the incident. Under the provisions of the Price
Anderson Act, if third-party claims relating to such an incident exceed $200
million (the amount of primary insurance), the Company could be assessed up to
$23.7 million for third-party claims. In addition, Congress could impose a
revenue-raising measure on the nuclear industry to pay such claims.
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 $2.7 billion for each
station. The Company is self-insured, to the extent of its ownership
interest, for its share of property losses in excess of insurance coverages.
Under the terms of the various insurance agreements, the Company could be
assessed up to $3.5 million in any policy year for losses incurred at nuclear
plants insured by the insurance companies.
The Company is a member of an industry mutual insurance company which provides
replacement power cost coverage in the event of a major accidental outage at a
nuclear power plant. The premium for this coverage is subject to
retrospective assessment for adverse loss experience. The Company's present
maximum share of any assessment is $1.4 million per year.
Environmental Matters
- ---------------------
As previously disclosed under "Hazardous Substances" on page I-17 of the
Company's 1993 Annual Report on Form 10-K, the disposal of Company-generated
hazardous substances can result in costs to clean up facilities found to be
contaminated due to past disposal practices. The Company is currently a
potentially responsible party (PRP) at two federal superfund sites and is
alleged to be a third-party contributor at two other sites. The Company also
has three former coal gasification sites and 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. The Company does not
expect clean-up and other potential costs related to the PRP and coal
gasification sites, either separately or cumulatively, to have a material
effect on the Company's financial position or results of operations.
-8-
Other
- -----
On December 14, 1993, Star Enterprise (Star) filed a complaint against the
Company in Delaware Chancery Court alleging that the Company overcharged it
for pension and tax-related costs under a contract entered into by the
parties' predecessors in 1955. The complaint asked for a refund and damages
totaling $9.3 million. On October 20, 1994, Star and the Company signed a
settlement agreement resolving Star's claims. The settlement does not have a
material effect on the Company's financial position or results of operations.
The Company is involved in certain other legal and administrative proceedings
before various courts and governmental agencies concerning rates, fuel
contracts, tax filings and other matters. The Company expects that the
ultimate disposition of these proceedings will not have a material effect on
the Company's financial position or results of operations.
9. SUPPLEMENTAL CASH FLOW INFORMATION
----------------------------------
Nine Months Ended Twelve Months Ended
September 30, September 30,
------------------- -------------------
1994 1993 1994 1993
(Dollars in Thousands) -------- -------- -------- --------
Cash paid for
Interest, net of amounts
capitalized $39,766 $40,910 $57,010 $60,706
Income taxes, net of refunds $61,095 $50,962 $82,470 $63,682
10. NONUTILITY SUBSIDIARIES
-----------------------
The following presents consolidated condensed financial information of the
Company's nonregulated wholly-owned subsidiaries: Delmarva Energy Company;
Delmarva Industries, Inc.; and Delmarva Capital Investments, Inc. (DCI). 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) 1994 1993 1994 1993 1994 1993
-------- -------- -------- -------- -------- --------
Revenues and Gains
Landfill and waste hauling $ 3,845 $ 3,320 $10,252 $ 8,356 $13,641 $10,763
Operating services 5,073 5,137 15,672 15,247 22,543 15,909
Other revenues 1,845 266 5,117 770 6,464 1,108
Leveraged leases 74 140 191 791 232 451
Other investment income 190 163 551 261 1,113 344
-------- -------- -------- -------- -------- --------
11,027 9,026 31,783 25,425 43,993 28,575
-------- -------- -------- -------- -------- --------
Cost and Expenses
Operating expenses 10,112 8,565 27,704 24,808 39,321 29,308
Interest expense 87 60 197 182 260 387
Capitalized interest (45) (53) (136) (118) (264) (189)
Income taxes 422 646 1,673 (1,217) 2,293 (2,896)
-------- -------- -------- -------- -------- --------
10,576 9,218 29,438 23,655 41,610 26,610
-------- -------- -------- -------- -------- --------
Net income (loss) $ 451 $ (192) $ 2,345 $ 1,770 $ 2,383 $ 1,965
======== ======== ======== ======== ======== ========
Earnings per share of common
stock attributed to subsidiaries $0.01 $ - $0.04 $0.03 $0.04 $0.03
In July 1994, a subsidiary of DCI purchased an office building for $5.8 million.
The purchase was financed primarily by the issuance of $4.6 million of long-term
debt.
-9-
SELECTED FINANCIAL AND OPERATING DATA
-------------------------------------
(Dollars in Thousands)
3 Months Ended 9 Months Ended 12 Months Ended
September 30 September 30 September 30
----------------------- ----------------------- -----------------------
1994 1993 1994 1993 1994 1993
---------- ---------- ---------- ---------- ---------- ----------
ELECTRIC REVENUES
- -----------------
Residential $95,193 $99,600 $251,157 $241,673 $314,931 $302,269
Commercial 72,943 74,333 189,062 184,211 242,636 234,613
Industrial 40,038 41,646 110,410 113,400 147,188 148,517
Resale, etc. 31,083 32,644 87,035 85,897 112,919 110,649
Unbilled Sales Revenues (3,446) (2,428) (1,886) 627 405 1,607
---------- ---------- ---------- ---------- ---------- ----------
Sales Revenues 235,811 245,795 635,778 625,808 818,079 797,655
Interchange Deliveries 10,393 15,905 47,157 40,917 67,677 50,075
Miscellaneous Revenues 2,105 2,291 6,061 3,791 8,388 6,005
---------- ---------- ---------- ---------- ---------- ----------
Total Electric Revenues $248,309 $263,991 $688,996 $670,516 $894,144 $853,735
========== ========== ========== ========== ========== ==========
ELECTRIC SALES
- --------------
(1000 kilowatthours)
Residential 1,006,522 1,046,606 2,882,667 2,773,042 3,609,012 3,501,457
Commercial 982,682 976,959 2,671,418 2,566,727 3,441,538 3,313,437
Industrial 854,651 855,930 2,427,281 2,413,321 3,246,193 3,198,095
Resale, etc. 619,563 617,027 1,719,602 1,648,904 2,255,704 2,161,620
Unbilled Sales, net (59,080) (49,615) (82,848) (67,164) 11,073 4,538
---------- ---------- ---------- ---------- ---------- ----------
Total Electric Sales 3,404,338 3,446,907 9,618,120 9,334,830 12,563,520 12,179,147
========== ========== ========== ========== ========== ==========
Interchange Deliveries 409,735 582,459 1,565,878 1,505,138 2,286,124 1,751,722
========== ========== ========== ========== ========== ==========
GAS REVENUES
- ------------
Billed Sales Revenues $11,818 $11,413 $83,868 $69,202 $108,785 $91,097
Unbilled Sales Revenues 101 (115) (2,225) (2,095) 133 (31)
Gas Transportation Revenues 373 96 821 407 975 629
---------- ---------- ---------- ---------- ---------- ----------
Total Gas Revenues $12,292 $11,394 $82,464 $67,514 $109,893 $91,695
========== ========== ========== ========== ========== ==========
GAS SALES AND GAS TRANSPORTED
- -----------------------------
(mcf 000)
Billed Sales 2,107 2,280 14,084 13,451 18,577 17,802
Unbilled Sales 33 18 (968) (845) 0 1
Gas Transported 684 244 1,544 1,244 1,838 1,928
---------- ---------- ---------- ---------- ---------- ----------
Total 2,824 2,542 14,660 13,850 20,415 19,731
========== ========== ========== ========== ========== ==========
September 30, 1994 December 31, 1993 September 30, 1993
----------------------- ----------------------- -----------------------
$ % $ % $ %
---------- ---------- ---------- ---------- ---------- ----------
CAPITALIZATION
- --------------
Variable Rate Demand Bonds (1) $41,500 2.2 $41,500 2.3 $41,500 2.3
Long-Term Debt 746,732 40.4 736,368 40.7 751,842 40.9
Preferred Stock 168,085 9.1 168,085 9.3 176,365 9.6
Common Stockholders' Equity 891,015 48.3 862,195 47.7 867,574 47.2
---------- ---------- ---------- ---------- ---------- ----------
Total $1,847,332 100.0 $1,808,148 100.0 $1,837,281 100.0
========== ========== ========== ========== ========== ==========
(1) The Company intends to use the bonds as a source of long-term financing as
discussed in Note 9 to the Consolidated Financial Statements of the 1993
Annual Report.
-10-
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EARNINGS
- --------
Earnings per average share of common stock outstanding for the three-, nine-,
and twelve-month periods ended September 30, 1994, and September 30, 1993, were
as follows:
Three Months Nine Months Twelve Months
Ended Ended Ended
---------------- ---------------- ----------------
9/30/94 9/30/93 9/30/94 9/30/93 9/30/94 9/30/93
------- ------- ------- ------- ------- -------
Core Utility
Operations $0.63 $0.72 $1.54 $1.54 $1.73 $1.79
ERO Charge (0.18) - (0.18) - (0.18) -
Nonutility Subsidiaries 0.01 - 0.04 0.03 0.04 0.03
------- ------- ------- ------- ------- -------
$0.46 $0.72 $1.40 $1.57 $1.59 $1.82
======= ======= ======= ======= ======= =======
Major components of the change in earnings per share from the same period of the
previous year are shown below:
Increase (Decrease) in Earnings Per Share
------------------------------------------------
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30 September 30 September 30
------------ ------------ ------------
1994 vs 1993 1994 vs 1993 1994 vs 1993
Core Utility
Operations
Revenues, net of fuel expense
Rate increases $ - $0.17 $0.28
Sales volume and other (0.06) 0.14 0.16
Operation and maintenance expense,
excluding ERO charge (0.05) (0.14) (0.23)
Depreciation (0.01) (0.08) (0.10)
Allowance for funds used during
construction (AFUDC) 0.01 (0.05) (0.09)
Effect of increased number of
average common shares (0.01) (0.05) (0.08)
Other 0.03 0.01 -
------ ------ ------
(0.09) - (0.06)
ERO Charge (0.18) (0.18) (0.18)
Nonutility Subsidiaries 0.01 0.01 0.01
------ ------ ------
($0.26) ($0.17) ($0.23)
====== ====== ======
CORE UTILITY EARNINGS
- ---------------------
Earnings per share from core utility operations, excluding a one-time ERO
charge, decreased $0.09 for the three-month period ended September 30, 1994,
compared to the same period last year. This decrease was primarily due to lower
electric base revenues and higher non-fuel operating expenses. The lower
electric base revenues were mainly due to lower kilowatt-hour (kWh) sales as a
result of weather conditions. Weather in the current quarter, though relatively
normal, did not match the unusually hot weather experienced last year.
For the nine- and twelve-month periods, earnings from core utility operations,
excluding a one-time ERO charge, remained unchanged and decreased $0.06,
respectively, compared to the same periods last year. Both reporting periods
showed increases in electric base revenues which resulted from increases in
customer rates and higher kWh sales. Electric sales benefited from colder
weather in the winter heating season and an improving service area
-11-
economy. The increase in electric base revenues was offset in both periods by
higher non-fuel operating expenses, lower AFUDC, and the dilutive effect on
earnings of more common shares outstanding.
Core utility earnings for all three current reporting periods were reduced by
$0.18 per share due to a one-time third quarter 1994 charge associated with the
Company's ERO.
STRATEGIC PLANS AND COMPETITION
- -------------------------------
As previously disclosed under the "Competition" section of the Company's 1993
Annual Report on Form 10-K, the Company has developed strategic plans to address
anticipated operating cost increases and the expected loss of up to $24 million
in non-fuel revenue beginning in 1995 when the Company's largest resale customer
(ODEC) will start to purchase about one-half of its electricity from another
utility. The strategies are as follows: (1) reduce costs by $15 to $20
million; (2) increase revenues through $10 to $15 million of targeted price
increases; and (3) increase revenues by an additional $10 to $20 million through
short-term energy and capacity sales to regional utilities and additional retail
sales. Current projections for 1995 show these strategies resulting in
approximately $30 to $45 million of reduced costs and increased revenues. These
strategies are designed to aid the Company in achieving its goal of earning a
return on equity of at least 11.5%, while keeping prices competitive, growing
earnings, and protecting the current dividend level. Below are updates to the
discussion of these strategies previously disclosed in the 1993 Annual Report on
Form 10-K.
Costs
- -----
In April 1994, the Company announced that through a voluntary ERO, the work
force would be reduced by 7% to 10%. The Company also initiated a review of
work activities performed by employees throughout the Company and identified
areas where work could be reduced or eliminated in order to capture the savings
of the workforce reduction. The ERO election process was completed in the third
quarter of 1994 resulting in approximately 10% of the Company's workforce (about
300 people), or 82% of eligible employees, accepting the ERO. The Company
recorded a one-time charge in the current quarter for the ERO resulting in an
increase to operation and maintenance expense of $17.5 million and a decrease in
net income of $10.675 million ($0.18 per share). The Company expects the annual
cost savings from the ERO to range from $13 to $17 million.
In addition to the ERO and related reduction in work activities, the Company
continues to review key business processes. These key business process reviews
enable the Company to continuously evaluate the effectiveness of work performed
by employees in order to enhance the Company's competitive position.
Revenues
- --------
On August 16, 1994, the Company filed an application with the DPSC for a $13.5
million increase in electric base rates. The increase, when netted with fuel
savings related to the reduction in load from ODEC beginning in 1995, is $8.8
million or 1.8%. This "limited issue" increase is designed to recover costs
specific to the Company's compliance with the Clean Air Act Amendments of 1990,
the one-percent increase in the marginal federal income tax rate to 35%, demand
side management and conservation programs, and an increase in funding for
nuclear decommissioning based on the current NRC minimum funding requirements.
The Company is requesting that final rates become effective January 1, 1995. On
November 2, 1994, the Company notified the DPSC that if final rates are not
approved by January 1, 1995, the Company would place a $1 million interim rate
increase into effect, subject to refund, as allowed under Delaware law. The
Company is permitted to implement the requested increase, subject to refund, on
March 16, 1995, if the case is not decided prior to that date.
-12-
On September 1, 1994, the Company filed an application with the MPSC for a
$3.9 million increase in electric base rates. The increase, when netted with
ODEC related fuel savings, is $2.2 million or 1.1%. This "limited issue"
increase is designed to recover costs similar to those in the Delaware "limited
issue" case, except for demand side management and conservation program costs
which are recoverable from Maryland customers through a surcharge. The Company
is requesting that final rates become effective January 1, 1995. The Company is
permitted to implement the requested increase, subject to refund, on March 30,
1995, if the case is not decided prior to that date. On November 7, 1994, the
Staff of the MPSC filed testimony proposing a base rate decrease of
$13.3 million. The proposal is based on a historical, not forward-looking, test
year (12 months ended June 30, 1994), return on equity of only 11.4%,
adjustments for the Company's "limited issues", plus several adjustments the
Company considers inappropriate. The Company believes the Staff's approach of
focusing on a historical test period and on issues well beyond the scope of the
"limited issue" filing contravenes the Company's plan to manage the financial
impact of the loss of the ODEC business with a combination of cost reductions,
higher sales, and modest price increases. The Company believes that the
inappropriateness of the Staff's position can be successfully addressed in the
Company's rebuttal testimony to be filed on December 5, 1994. In the interim,
the Company plans to continue meeting with the Staff with the goal of obtaining
a settlement. The Company believes the trend in recent years of reaching a
mutual agreement to settle rate cases in Maryland should continue.
On October 18, 1994, the DPSC approved a settlement agreement for a $3.1
million, or 3.1% increase in gas base rates. The increase is effective November
1, 1994, at which time lower fuel rates will also become effective. The reduced
fuel rates when combined with the base rate increase results in a net average
decrease of 1.75%.
Sales
- -----
As discussed in Note 5 to the Consolidated Financial Statements and Part II of
the Company's Report on Form 10-Q for the second quarter of 1994, the Company
entered into agreements with PECO to purchase its Maryland retail electric
subsidiary, COPCO, for $150 million and to purchase capacity and energy from
PECO. For an update on the status of the COPCO purchase, see Part II of this
Report on Form 10-Q.
The Company's offer to purchase the electric system from the City of Dover,
Delaware (Dover) for $103.5 million remains outstanding. As an alternative, the
Company has held discussions with Dover concerning a long-term power supply
contract. It is the Company's understanding that other parties have also had
discussions with Dover regarding the generation segment of Dover's business.
Recently, the Dover city council voted to request bids from utilities and
independent power producers for purchase power agreements and hired an outside
consultant to help review proposals.
In addition to growing the retail market share, the Company's strategy is to add
value by retaining profitable wholesale and large industrial customers. This
can be achieved through long-term energy supply contracts with customers who
have the option (under the National Energy Policy Act) to buy power elsewhere.
On August 22, 1994, the Company signed a 20-year, full requirements electric
service agreement with the Town of Clayton, Delaware (Clayton). The Company
previously signed a long-term agreement with the Town of Smyrna, Delaware
(Smyrna). Under these agreements, the initial wholesale rates charged to Smyrna
and Clayton will be modestly discounted with future increases or decreases based
on the percentage change in base rates approved by the DPSC for the Company's
Delaware retail customers. The Company will also perform new services for the
towns. Both contracts have been approved by the FERC.
-13-
The Delaware Municipal Electric Corporation (DEMEC) represents the Company's
Delaware municipal customers and Dover. The Company is presently supplying
approximately 125 MW of load to its Delaware municipal customers, or about 5% of
the Company's estimated 1995 firm load of 2,287 MW. Included in the 125 MW is
12 MW of combined load for Smyrna and Clayton. On May 26, 1994, DEMEC,
excluding Dover, issued a request for proposal (RFP) for firm supply of capacity
and energy for a minimum term of 10 years. Twenty MW of DEMEC's RFP represents
load not previously supplied by the Company. The amounts and dates of the
capacity and energy requirements in the RFP reflect the termination notice
provisions included in the base rate settlement agreement between the Company
and the DEMEC customers filed with the FERC on September 14, 1994, i.e., a
two-year notice for up to 30% load reduction and a five-year notice for more
than 30% load reduction. Therefore, DEMEC's full capacity and energy
requirements to be supplied under the RFP from a supplier other than the Company
would not be reached until the year 2000. On July 14, 1994, in response to the
RFP, the Company submitted its proposal to DEMEC to serve the requirements of
the DEMEC members, excluding Dover. Also, the Company is engaged in preliminary
discussions with certain DEMEC members individually for separate long-term power
supply contracts similar to the Smyrna and Clayton contracts.
On November 2, 1994, the FERC issued an order interpreting the terms of a prior
settlement agreement between the Company and the Cities of Milford, Newark, and
New Castle, Delaware, which was entered into in 1983. In its order, the FERC
determined that under the terms of this 1983 settlement agreement, the three
cities may elect to terminate service provided by the Company with only one
year's prior notice up to January 27, 1995, the date on which the 1983
settlement agreement expires. Therefore, the termination notice requirements
agreed to by the Company and the three cities in the base rate settlement
agreement filed on September 14, 1994 (of two years for up to 30% load reduction
and five years for more than a 30% load reduction), do not become effective with
respect to the three cities until after January 27, 1995. The Company is
preparing a request for rehearing which will be filed with the FERC by
December 2, 1994. The Company is presently supplying approximately 86 MW of
load to the three cities. The Company cannot predict the outcome of its request
for rehearing or what impact, if any, the FERC order may have on DEMEC's RFP.
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) Revenue
Increased Rates $ 0.2 $15.9 $25.5
Sales Volume and Other (5.9) 7.7 10.5
Fuel Revenue (4.5) (11.4) (13.2)
Interchange Delivery Revenue (5.5) 6.3 17.6
------ ------ ------
Total ($15.7) $18.5 $40.4
====== ====== ======
-14-
Electric Non-Fuel (Base Rate) Revenue - Increased Rates
- -------------------------------------------------------
The electric non-fuel (base rate) revenue increases shown on the previous page
as "Increased Rates" are due to the following:
Electric Base Rate Increases
------------------------------------------------------
Annualized Base Effective
Jurisdiction Revenue Increase Date
------------ ----------------- ---------
Retail Electric
Delaware (1) $ 24.9 million 06/01/93
Maryland (1) $ 7.8 million 04/01/93
Virginia $ 1.3 million 10/05/93
Resale (FERC) (1), (2) $ 1.5 million 06/03/93
(1) On a comparative basis, these rate increases contributed to the
nine-and twelve-month revenue increases but had no effect on the
three- month revenue variance because the rate increases were
effective throughout the entire three-month period for both 1994
and 1993.
(2) This rate increase is based on settlement agreements reached
between the Company and its resale customers. See Note 3 to the
Consolidated Financial Statements for further details.
Electric Non-Fuel (Base Rate) Revenue - Sales Volume And Other
- --------------------------------------------------------------
Percentage changes in kWh sales billed by customer class are shown below:
Percentage Increase (Decrease) in kWh Sales
From Comparable Period in Prior Year
-----------------------------------------------------
Three Nine Twelve
Customer Class Months Months Months
-------------- ------ ------ ------
Residential (3.8)% 4.0 % 3.1 %
Commercial 0.6 4.1 3.9
Industrial (0.1) 0.6 1.5
Resale, etc. 0.4 4.3 4.4
Total Billed Sales (0.9) 3.2 3.1
Total Sales, including
Unbilled Sales (1.2)% 3.0 % 3.2 %
Electric non-fuel revenues from "Sales Volume and Other" variances decreased
$5.9 million for the three-month period primarily due to a 3.8% decrease in
residential kWh sales attributed to cooler weather. Commercial and resale
sales, which are less weather sensitive than residential sales, were relatively
unchanged from the prior year. Resale sales reflect additional sales made on a
short-term basis to Delaware municipal customers to cover a portion of their
load previously supplied by another source.
Electric non-fuel revenues from "Sales Volume and Other" variances increased
$7.7 million for the nine-month period and $10.5 million for the twelve-month
period due to increases in total kWh sales of 3.0% and 3.2%, respectively. For
both periods, increases in residential, commercial, and resale kWh sales were
largely due to weather conditions involving a winter heating season that was
colder than the previous year, partially offset by a summer cooling season that
was not as hot as the previous year. Customer growth, reflecting an improving
service area economy, also contributed to increased residential and commercial
kWh sales for both periods. The total number of electric customers increased
2.2% for the twelve months ended September 30, 1994.
-15-
Electric Fuel Revenue
- ---------------------
Electric fuel costs billed to customers, or fuel revenues, generally do not
affect net income since the expense recognized as fuel costs is adjusted to
match the fuel revenues. The amount of under- or over-recovered fuel costs is
deferred until it is subsequently recovered from or returned to utility
customers. For the three-, nine-, and twelve-month periods, fuel revenues
decreased $4.5, $11.4, and $13.2 million, respectively, primarily due to lower
average fuel rates charged to customers. For the three-month period, lower kWh
sales also contributed to lower fuel revenues. For the nine- and twelve-month
periods, higher kWh sales partially offset the lower fuel revenues resulting
from lower average rates.
Interchange Delivery Revenue
- ----------------------------
Interchange delivery revenues are reflected in the calculation of rates charged
to customers under fuel adjustment clauses as a reduction of fuel costs and,
thus, do not generally affect net income. For the three-month period,
interchange delivery revenues decreased $5.5 million primarily due to lower
sales to the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM)
which resulted from decreased demand for electricity in the region. For the
nine- and twelve-month periods, interchange delivery revenues increased $6.3 and
$17.6 million, respectively, mainly due to higher sales to PJM during the winter
which resulted from increased demand for electricity in the region.
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) Revenue $ 0.8 $ 3.2 $ 3.1
Fuel Revenue 0.1 11.8 15.1
------ ------ ------
Total $ 0.9 $15.0 $18.2
====== ====== ======
For the three-month period, non-fuel revenues increased $0.8 million primarily
due to an increase in gas sold and transported. Non-fuel revenue increases for
the nine- and twelve-month periods of $3.2 and $3.1 million, respectively, were
primarily due to higher firm sales resulting from colder winter weather and
customer growth. For the nine-month period, firm sales increased 4.7% and total
gas sold and transported increased 5.8%. For the twelve-month period, firm
sales increased 3.4% and total gas sold and transported increased 3.5%
Gas fuel revenues, like electric fuel revenues, represent fuel costs billed to
customers and generally do not affect net income since the expense recognized as
fuel costs is adjusted to match the fuel revenues. For the nine- and twelve-
month periods, higher fuel revenues resulted primarily from higher average fuel
rates charged to customers. Increased firm gas sales also contributed to higher
fuel revenues for both periods.
-16-
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 ($2.2) $ 4.8 -
Increased (Decreased) kWh Output (4.2) 6.8 18.2
Deferral of Energy Costs (3.5) (18.8) (14.9)
------ ------ ------
Total ($9.9) ($7.2) $ 3.3
====== ====== ======
For the three-month period, the "Average Cost of Electric Fuel and Purchased
Power" decreased $2.2 million primarily due to the increased output of gas
generating units, which had lower fuel costs than the current period system
average and last year, and power purchases at rates lower than last year. An
additional $4.2 million decrease in electric fuel and purchased power expenses
resulted from lower kWh output from electric generating units. Output decreased
due to lower electric sales demand in the Company's service territory and
decreased interchange deliveries.
For the nine-month period, the "Average Cost of Electric Fuel and Purchased
Power" increased $4.8 million primarily due to the increased output from oil
generating peaking units, which have fuel costs substantially higher than the
system average, and interchange and power purchases at rates higher than last
year. These factors were partially offset by the increased output of gas
generating units, which had lower fuel costs than the system average and last
year. An additional $6.8 million increase in electric fuel and purchased power
expenses resulted from higher kWh output from electric generating units. Output
rose due to greater electric sales demand in the Company's service territory and
increased interchange deliveries.
For the twelve-month period, the "Average Cost of Electric Fuel and Purchased
Power" remained unchanged as a result of various offsetting factors. The
variance in electric fuel and purchased power for the twelve-month period
reflects an $18.2 million increase due to higher kWh output from electric
generating units for the same reasons as stated above for the nine-month period.
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, 1994, the Company's output for load within
the service territory was provided by 44% coal generation, 32% oil and gas
generation, 14% nuclear generation, and 10% net purchased power, which
consisted primarily of purchases under an energy-only purchase agreement with
PECO.
In comparison to the same periods last year, the "Deferred Energy Costs"
decreased by $3.5, $18.8, and $14.9 million for the three, nine, and twelve
months, respectively. These decreases were the net results of the accrual and
amortization of deferred fuel costs in the Company's various regulatory
jurisdictions.
-17-
OPERATION, MAINTENANCE, AND DEPRECIATION EXPENSES
- -------------------------------------------------
For the three-, nine-, and twelve-month periods ended September 30, 1994,
compared to the same periods a year ago, operation and maintenance expense
increased $22.1, $30.0, and $37.8 million, respectively. The increases for all
three periods include a one-time $17.5 million charge recorded in the third
quarter of 1994 for the Company's ERO, higher maintenance outage costs of
electric generating plants, and increased postretirement benefits other than
pensions due to the Company's adoption of SFAS No. 106 beginning in 1993. The
Company deferred the additional expense attributed to SFAS No. 106 until the
costs were reflected in rates on the dates shown on page 15 for the electric
business. The Company also wrote off in the third quarter of 1994 the deferred
SFAS No. 106 costs related to the Delaware jurisdiction (electric and gas) in
accordance with the settlement agreement approved October 18, 1994, in the
Company's gas base rate case. The nine- and twelve-month periods also included
higher maintenance costs due to storm-related damage in the first quarter of
1994.
Depreciation increased $1.2, $7.2, and $9.4 million for the three-, nine-, and
twelve-month periods, respectively, mainly due to additions to the electric
system.
UTILITY FINANCING COSTS
- -----------------------
In comparison to the same periods last year, interest charges on debt of the
core utility decreased $0.5, $2.3, and $3.7 million for the three-, nine-, and
twelve-month periods, respectively. The decrease for the three-month period
was primarily due to interest savings from refinancings of long-term debt
issues. The decreases for the nine- and twelve- month periods were mainly due
to the redemption on June 1, 1993, of $50 million of 10% First Mortgage Bonds
with a portion of the proceeds from the March 1993 public offering of common
stock and refinancing savings.
AFUDC increased $0.3 million for the three-month period due to higher average
construction work-in-progress balances. AFUDC decreased $3.8 and $6.1 million
for the nine- and twelve-month periods, respectively, due to lower average
construction work-in-progress balances as a result of the completion of Hay
Road Unit No. 4 on June 1, 1993. For the twelve months ended September 30,
1994, AFUDC was 4.1% of net income.
Due to increased common equity financing, the average number of shares of
common stock outstanding increased for the three-, nine-, and twelve-month
periods. The additional shares outstanding decreased earnings per share by
$0.01, $0.05, and $0.08 for the three-, nine-, and twelve-month periods,
respectively. Rates charged to customers have been designed to result in
sufficient revenues to offset the dilution of earnings per share due to
increased common equity financing.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
For the nine months ended September 30, 1994, utility construction expenditures
were $98.7 million compared to $118.0 million for the same period last year.
Internally generated funds (net cash provided by operating activities less
common and preferred dividends) provided 103% of the cash required for
construction for the nine months ended September 30, 1994, compared to 78% for
the same period last year. For the twelve months ended September 30, 1994, and
September 30, 1993, utility construction expenditures were $140.7 and $177.9
million, respectively. Internally generated funds provided 86% and 54% of the
cash required for construction during the twelve months ended September 30,
1994, and September 30, 1993, respectively. Lower construction expenditures
for the nine- and twelve-month periods ended September 30, 1994, as compared to
the prior year periods reflect lower budgeted capital expenditures.
-18-
During the nine months ended September 30, 1994, the Company's term loan
balance increased by $6.5 million. Also during this period, $15.0 million of
common stock was issued primarily through the Company's DRIP. As of June 1,
1994, cash was no longer being provided through the DRIP because the plan began
acquiring shares through purchase on the open market rather than through the
issuance of new shares.
The Company redeemed its 4 5/8% First Mortgage Bonds, $25 million principal
amount, at maturity on October 1, 1994. On October 12, 1994, the Delaware
Economic Development Authority issued on behalf of the Company $30 million of
Variable Rate Demand Gas Facilities Revenue Bonds, due on demand or at maturity
on October 1, 2029. Proceeds from the bonds will be used to finance
enhancements to and expansion of the Company's gas system.
RATIO OF EARNINGS TO FIXED CHARGES
- ----------------------------------
12 Months
Ended
September 30, Year Ended December 31,
1994 ------------------------------------------
------------ 1993 1992 1991 1990 1989
------ ------ ------ ------ ------
Ratio of Earnings to Fixed Charges
(SEC Method)....................... 3.43X 3.47X 3.03X 2.58X 2.03X 3.01X
Under the SEC Method, earnings, including AFUDC, have been computed by adding
the amount of income taxes and fixed charges to net income. Fixed charges
include gross interest expense and the estimated interest component of rentals.
Excluding the one-time charge for the ERO, the ratio of earnings to fixed
charges for the twelve months ended September 30, 1994, would be 3.68X.
Excluding the gain from the Company's share of a settlement reached in the
lawsuit against PECO in connection with the shutdown of Peach Bottom, the ratio
of earnings to fixed charges for year ended December 31, 1992, would be 2.78X.
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 this ratio. Excluding the write-off of an investment in certain
non-regulated subsidiary projects, the ratio of earnings to fixed charges for
the year ended December 31, 1990, would be 2.89X.
NONUTILITY SUBSIDIARIES
- -----------------------
Information on the Company's nonutility subsidiaries, in addition to the
following discussion, can be found in Note 10 to the Consolidated Financial
Statements. Nonutility earnings per share were as follows:
Period Ended
September 30,
----------------
1994 1993
------ ------
Three Months Ended $0.01 $ -
Nine Months Ended $0.04 $0.03
Twelve Months Ended $0.04 $0.03
-19-
All three prior year reporting periods (three, nine, and twelve months ended
September 30, 1993) included gains on the sale of interests in leveraged
leases, which had the effect of lowering operating leveraged lease income in all
three current year reporting periods (three, nine, and twelve months ended
September 30, 1994). All three current year reporting periods reflect gains on
the sale of real estate and lower administrative and general costs, partially
offset by a write-down in the investment of oil and gas wells. The nine- and
twelve-month current year reporting periods also reflect the recovery of
previously written-off joint venture assets and improved operating results from
the waste hauling and landfill business.
During the third quarter of 1994, a subsidiary of DCI purchased an office
building for $5.8 million. The purchase was financed primarily by the issuance
of $4.6 million of long-term debt.
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PART II. OTHER INFORMATION
--------------------------
Item 1. Legal Proceedings
- --------------------------
Refer to Note 8 to the Consolidated Financial Statements for updated
information concerning the complaint filed by Star against the Company in
December 1993.
Item 5. Other Information
- --------------------------
A) Purchase of COPCO
-----------------
As discussed in Note 5 to the Consolidated Financial Statements and Part II of
the Company's Report on Form 10-Q for the second quarter of 1994, on May 24,
1994, the Company entered into agreements with PECO to purchase its Maryland
retail electric subsidiary, COPCO, for $150 million and to purchase capacity
and energy from PECO. As previously discussed, the Company reached a
settlement in principle with the interested parties in Maryland. On September
9, 1994, the Company and COPCO filed a Joint Application with the MPSC. The
Company expects the MPSC to decide on this matter in the fourth quarter of
1994. On October 28, 1994, the Company made filings with the DPSC and Virginia
State Corporation Commission. On November 4, 1994, the Company made its filing
with the FERC. Assuming prompt regulatory approval from each of the Company's
Commissions, the purchase is expected to be completed in the second quarter of
1995.
B) Transmission Rate Filing
------------------------
As part of the Company's November 4, 1994, filing with the FERC for approval of
the COPCO purchase, the Company has proposed to offer comparable transmission
services to its wholesale customers and third parties. FERC policy requires
that the transmission services be offered under terms and conditions that are
"comparable" to the transmission services the Company provides to itself to
transmit power from its generating units to customers.
C) DCEP Contract Cancellation
--------------------------
As previously reported on page I-5 of the Company's 1993 Annual Report on Form
10-K, the Company entered into an agreement to purchase 165 MW of capacity and
energy from the Delaware Clean Energy Project (DCEP) over a 30-year period
beginning at the Company's option in 1996 or 1997. A subsequent amendment to
the agreement delayed the purchase of the capacity while extending an option to
cancel the agreement until November 1, 1994. On October 27, 1994, the Company
notified DCEP that it would be terminating the agreement. The Company's lack
of need for long-term capacity at this time necessitated the cancellation.
D) Peach Bottom
------------
As previously reported on page 22 of the Company's Report on Form 10-Q for the
second quarter of 1994, initial examinations of Peach Bottom Unit No. 2 for core
shroud seam weld cracks were planned for the Unit's scheduled September 1994
refueling outage. PECO has informed the Company that in September 1994, Unit
No. 2 was examined and PECO determined that no corrective actions were necessary
to operate Unit No. 2 for another two-year cycle.
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E) Salem
-----
Unit No. 1 Outage
-----------------
As previously reported on page 16 of the Company's Report on Form 10-Q for the
first quarter of 1994, on April 7, 1994, a series of problems occurred at Salem
Unit No. 1 which resulted in a shutdown of the unit and declaration of an alert.
The unit returned to service on June 4, 1994. PSE&G has informed the Company
that PSE&G has continued to address matters to improve Salem's operations
identified by itself, the NRC, and the Institute of Nuclear Power Operations
(INPO), an independent industry group consisting of utilities, including PSE&G,
that provides self-critical analysis of nuclear operations to member utilities.
Actions are being taken to improve the plant's material condition, to upgrade
procedures, and to enhance personnel performance, as well as other efforts,
including appointment of a new station manager and senior plant staff. In
addition, effective September 29, 1994, PSE&G established its nuclear operations
as a separate business unit reporting directly to the Chairman and Chief
Executive Officer of PSE&G and hired an executive from outside of PSE&G as its
Chief Nuclear Officer and President of its new Nuclear Business Unit.
On October 5, 1994, the NRC issued a Notice of Violation and Proposed Imposition
of Civil Penalty (Notice) to PSE&G advising that it proposed to impose an
aggregate fine of $500,000 for violations relating to the April 7, 1994 event,
including: the failure to identify and correct significant conditions adverse to
quality at the facility related to spurious steam flow signals and inoperable
atmospheric relief valves, both of which, it concluded, led to unnecessary
safety injections during the event; the failure to identify and correct
significant conditions adverse to quality at the facility related to providing
adequate training, guidance, and procedures for the operators to cope with the
event; and the failure by supervisors to exercise appropriate command and
control of the operations staff and the reactor during the event. In assessing
its fine, the NRC advised PSE&G that it "expects an aggressive and prompt
response to this matter as neither PSE&G nor the NRC can accept (1) such
performance in the future, and (2) the large number of equipment related events
that have recently occurred at Salem." The NRC has stated that, after reviewing
PSE&G's response to the Notice, including PSE&G's proposed corrective actions
and the results of future inspections, it will determine whether further NRC
enforcement action is necessary to ensure compliance with NRC regulatory
requirements. PSE&G has indicated that the $500,000 fine, of which the
Company's share is 7.41%, will be paid without challenge.
PSE&G's own assessments, as well as those by the NRC and INPO, indicate that
additional efforts are required to further improve operating performance, and
PSE&G is committed to taking the necessary actions to address Salem's
performance needs. No assurance can be given as to what, if any, further or
additional actions may be taken by the NRC or what further or additional actions
may be taken by PSE&G, or required by the NRC, to improve Salem's performance.
Operating Permit
----------------
As previously reported on page I-18 of the Company's 1993 Annual Report on Form
10-K, in June 1993, the New Jersey Department of Environmental Protection and
Energy (NJDEPE) issued a revised draft permit that would allow Salem to
continue to operate with once-through cooling and would require PSE&G to make
certain plant modifications and to undertake various measures to protect and
enhance aquatic life in the Delaware Bay. On July 20, 1994, the NJDEPE issued
a final five-year permit, effective September 1, 1994, with essentially the
same provisions as the revised draft permit. PSE&G has informed the Company
that certain environmental groups and other entities, including the State of
Delaware, have filed requests for hearings with the NJDEPE challenging the
final permit. The NJDEPE granted the hearing requests on certain of the issues
and PSE&G has been named as a respondent along with the NJDEPE in these matters
which are pending in the New Jersey Office of Administrative Law. The U.S.
Environmental Protection Agency, which has
-22-
authority to review the final permit issued by the NJDEPE, completed its review
and has not raised any objections. PSE&G is implementing the final permit.
Additional permits from various agencies are required to be obtained to
implement the permit. No assurances can be given as to the receipt of any such
additional permits. The estimated capital cost of compliance with the final
permit is approximately $100 million, of which the Company's share would be
7.41%.
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 copy of the Company's press release announcing the results of its ERO was
filed as a Report on Form 8-K dated October 17, 1994.
-23-
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 10, 1994 /s/ B. S. Graham
----------------- --------------------------------
B. S. Graham, Vice President and
Chief Financial Officer
-24-
EXHIBIT INDEX
Exhibit Page
Number Number
------- -------
Computation of ratio of earnings to fixed charges 12 26
Financial Data Schedule 27 27
-25-