SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported) February 6, 1996
POTOMAC ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 1-1072 53-0127880
(State or other jurisdiction of (Commission (I.R.S. Employer
incorporation) File Number) Identification No.)
1900 Pennsylvania Avenue, N. W., Washington, D. C. 20068
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (202) 872-3526
<PAGE>
PEPCO
Form 8-K
Item 7. Financial Statements, Pro-Forma Financial Information and
Exhibits.
Exhibits
Exhibit No. Description of Exhibit Reference
12 Computation of ratios...............Filed herewith.
23 Consent of Independent
Accountants.........................Filed herewith.
27 Financial Data Schedule.............Filed herewith.
27.1 Restated Financial Data Schedule....Filed herewith.
99 The 1995 consolidated financial
statements of the Company and
Subsidiaries, together with the
report thereon of Price Waterhouse
dated January 19, 1996; and
Management's Discussion and
Analysis of Consolidated Results
of Operations and Financial
Condition as well as selected
financial data......................Filed herewith.
-2-
<PAGE>
Signatures
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 hereunto duly authorized.
Potomac Electric Power Company
(Registrant)
By ___________________________
H. Lowell Davis
Vice Chairman and
Chief Financial Officer
February 6, 1996
DATE
-3-
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, excluding the cumulative effect of the 1992
accounting change, before income taxes, and the coverage of combined fixed charges and preferred
dividends for each of the years 1995 through 1991 on the basis of parent company operations only, are
as follows.
<CAPTION>
For The Year Ended December 31,
-------------------------------------------------------
1995 1994 1993 1992 1991
-------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $218,788 $208,074 $216,478 $172,599 $186,813
Taxes based on income 129,439 116,648 107,223 76,965 80,988
-------------------------------------------------------
Income before taxes and cumulative effect
of accounting change 348,227 324,722 323,701 249,564 267,801
-------------------------------------------------------
Fixed charges:
Interest charges 146,558 139,210 141,393 138,097 138,512
Interest factor in rentals 23,431 6,300 5,859 6,140 5,690
-------------------------------------------------------
Total fixed charges 169,989 145,510 147,252 144,237 144,202
-------------------------------------------------------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $518,216 $470,232 $470,953 $393,801 $412,003
======== ======== ======== ======== ========
Coverage of fixed charges 3.05 3.23 3.20 2.73 2.86
==== ==== ==== ==== ====
Preferred dividend requirements $16,851 $16,437 $16,255 $14,392 $12,298
-------------------------------------------------------
Ratio of pre-tax income to net income 1.59 1.56 1.50 1.45 1.43
-------------------------------------------------------
Preferred dividend factor $26,793 $25,642 $24,383 $20,868 $17,586
-------------------------------------------------------
Total fixed charges and preferred dividends $196,782 $171,152 $171,635 $165,105 $161,788
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.63 2.75 2.74 2.39 2.55
==== ==== ==== ==== ====
</TABLE>
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, excluding the cumulative effect of the 1992
accounting change, before income taxes, and the coverage of combined fixed charges and preferred
dividends for each of the years 1995 through 1991 on a fully consolidated basis are as follows.
<CAPTION>
For The Year Ended December 31,
-------------------------------------------------------
1995 1994 1993 1992 1991
-------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $94,391 $227,162 $241,579 $200,760 $210,164
Taxes based on income 43,731 93,953 62,145 79,481 80,737
-------------------------------------------------------
Income before taxes and cumulative effect
of accounting change 138,122 321,115 303,724 280,241 290,901
-------------------------------------------------------
Fixed charges:
Interest charges 238,724 224,514 221,312 226,453 225,323
Interest factor in rentals 26,685 9,938 9,257 6,599 6,080
-------------------------------------------------------
Total fixed charges 265,409 234,452 230,569 233,052 231,403
-------------------------------------------------------
Nonutility subsidiary capitalized interest (529) (521) (2,059) (2,200) (6,542)
-------------------------------------------------------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $403,002 $555,046 $532,234 $511,093 $515,762
======== ======== ======== ======== ========
Coverage of fixed charges 1.52 2.37 2.31 2.19 2.23
==== ==== ==== ==== ====
Preferred dividend requirements $16,851 $16,437 $16,255 $14,392 $12,298
-------------------------------------------------------
Ratio of pre-tax income to net income 1.46 1.41 1.26 1.40 1.38
-------------------------------------------------------
Preferred dividend factor $24,602 $23,176 $20,481 $20,149 $16,971
-------------------------------------------------------
Total fixed charges and preferred dividends $290,011 $257,628 $251,050 $253,201 $248,374
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 1.39 2.15 2.12 2.02 2.08
==== ==== ==== ==== ====
</TABLE>
Item 7
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Prospectuses constituting parts of the Registration Statements on
Form S-8 (Numbers 33-36798, 33-53685 and 33-54197) and on Form S-3
(Numbers 33-58810 and 33-61379) of Potomac Electric Power Company
and in the Joint Proxy Statement/Prospectus constituting part of the
Registration Statement on Form S-4 of Constellation Energy Corporation
of our report dated January 19, 1996 appearing on page 30 of
Exhibit 99 of the Current Report on Form 8-K of Potomac Electric
Power Company dated February 6, 1996.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Washington, D.C.
February 6, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,378,269
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 431,204
<TOTAL-DEFERRED-CHARGES> 671,572
<OTHER-ASSETS> 1,637,105
<TOTAL-ASSETS> 7,118,150
<COMMON> 118,495
<CAPITAL-SURPLUS-PAID-IN> 1,010,521
<RETAINED-EARNINGS> 742,296
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,871,312
143,485
125,325
<LONG-TERM-DEBT-NET> 1,817,077
<SHORT-TERM-NOTES> 3,540<F1>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 254,925<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 26,280
0
<CAPITAL-LEASE-OBLIGATIONS> 165,235
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,690,199
<TOT-CAPITALIZATION-AND-LIAB> 7,118,150
<GROSS-OPERATING-REVENUE> 1,876,102
<INCOME-TAX-EXPENSE> 128,460
<OTHER-OPERATING-EXPENSES> 1,399,901
<TOTAL-OPERATING-EXPENSES> 1,528,361
<OPERATING-INCOME-LOSS> 347,741
<OTHER-INCOME-NET> (114,300)
<INCOME-BEFORE-INTEREST-EXPEN> 233,441
<TOTAL-INTEREST-EXPENSE> 139,050
<NET-INCOME> 94,391
16,851
<EARNINGS-AVAILABLE-FOR-COMM> 77,540
<COMMON-STOCK-DIVIDENDS> 196,469
<TOTAL-INTEREST-ON-BONDS> 127,900<F2>
<CASH-FLOW-OPERATIONS> 376,722
<EPS-PRIMARY> $.65
<EPS-DILUTED> 0<F3>
<FN>
<F1>Included on the Balance Sheet in the caption "Short-term debt."
<F2>Total annualized interest costs for all utility long-term debt outstanding
at December 31, 1995.
<F3>If all the convertible preferred stock and debentures were converted into
common stock, the result would be anti-dilutive.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<RESTATED>
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C> <C> <C>
<PERIOD-TYPE> 6-MOS 3-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1995 DEC-31-1995 DEC-31-1994
<PERIOD-START> JAN-01-1995 JAN-01-1995 JAN-01-1994
<PERIOD-END> JUN-30-1995 MAR-31-1995 DEC-31-1994
<BOOK-VALUE> PER-BOOK PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,357,551 4,353,341 4,327,434
<OTHER-PROPERTY-AND-INVEST> 0 0 0
<TOTAL-CURRENT-ASSETS> 454,664 372,449 425,138
<TOTAL-DEFERRED-CHARGES> 628,161 588,622 568,069
<OTHER-ASSETS> 1,515,821 1,670,401 1,681,254
<TOTAL-ASSETS> 6,956,197 6,984,813 7,001,895
<COMMON> 118,486 118,349 118,248
<CAPITAL-SURPLUS-PAID-IN> 1,010,593 1,008,180 1,006,526
<RETAINED-EARNINGS> 689,475 785,792 830,524
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,818,554 1,912,321 1,955,298
143,485 143,562 143,563
125,401 125,405 125,409
<LONG-TERM-DEBT-NET> 1,703,370 1,727,848 1,723,399
<SHORT-TERM-NOTES> 0 0 0
<LONG-TERM-NOTES-PAYABLE> 0 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 354,000<F1> 237,525<F1> 189,600<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 65,000 40,000 45,445
0 0 0
<CAPITAL-LEASE-OBLIGATIONS> 166,304 166,817 167,324
<LEASES-CURRENT> 20,772 20,772 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,559,311 2,610,563 2,631,085
<TOT-CAPITALIZATION-AND-LIAB> 6,956,197 6,984,813 7,001,895
<GROSS-OPERATING-REVENUE> 810,268 364,909 1,823,074
<INCOME-TAX-EXPENSE> 34,394 (421) 119,859
<OTHER-OPERATING-EXPENSES> 653,817 334,512 1,378,722
<TOTAL-OPERATING-EXPENSES> 688,211 334,091 1,498,581
<OPERATING-INCOME-LOSS> 122,057 30,818 324,493
<OTHER-INCOME-NET> (113,721) (1,129) 32,257
<INCOME-BEFORE-INTEREST-EXPEN> 8,336 29,689 356,750
<TOTAL-INTEREST-EXPENSE> 69,146 33,661 129,588
<NET-INCOME> (60,810) (3,972) 227,162
8,475 4,241 16,437
<EARNINGS-AVAILABLE-FOR-COMM> (69,285) (8,213) 210,725
<COMMON-STOCK-DIVIDENDS> 98,164 49,046 195,755
<TOTAL-INTEREST-ON-BONDS> 123,600<F2> 123,600<F2> 123,700<F2>
<CASH-FLOW-OPERATIONS> 96,381 60,091 376,450
<EPS-PRIMARY> ($.59) ($.07) $1.79
<EPS-DILUTED> 0<F3> 0<F4> 0<F4>
<FN>
<F1>Included on the Balance Sheet in the caption "Short-term debt."
<F2>Total annualized interest costs for all utility long-term debt outstanding.
<F3>If all the convertible preferred stock and debentures were converted into
common stock, the result would be anti-dilutive.
<F4>No material dilution would occur if all the convertible preferred stock and
debentures were converted into common stock.
</FN>
</TABLE>
Item 7
Exhibit 99
Financial Information
- ---------------------
Potomac Electric Power Company and Subsidiaries
Contents
- --------
Management's Discussion and Analysis of
Consolidated Results of Operations and
Financial Condition...................................... 2
Report of Independent Accountants.......................... 30
Consolidated Statements of Earnings........................ 31
Consolidated Balance Sheets................................ 32
Consolidated Statements of Cash Flows...................... 34
Notes to Consolidated Financial Statements................. 35
Selected Consolidated Financial Data....................... 75
1
Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
- ----------------------------------------------------
PROPOSED MERGER
- ---------------
In September 1995, Potomac Electric Power Company (the Company,
PEPCO) announced a proposed merger (the Merger) with Baltimore
Gas and Electric Company (BGE). The Merger Agreement was
approved by the Board of Directors of each company on September
22, 1995. The Merger requires the approval of shareholders of
each company and certain regulatory agencies, including the
Federal Energy Regulatory Commission, the Public Service
Commissions of Maryland and the District of Columbia and the
Nuclear Regulatory Commission. The approval process is expected
to take until the end of the first quarter of 1997 to complete.
The Company believes that the Merger will provide
opportunities to achieve benefits for its shareholders,
customers, employees and communities that would not be available
to the Company as a separate entity, including expanded
opportunities in both the core utility operations and nonutility
businesses. Preliminary estimates indicate that the Merger will
result in savings of approximately $1.3 billion, net of costs to
achieve, over 10 years primarily through economies of scale and
eliminating duplicate functions which will result in a reduction
in the combined work force of approximately 10%. Sharing of the
net savings between customers and shareholders of the Company
will be determined in regulatory proceedings. See the Notes to
Consolidated Financial Statements, (13) Commitments and
Contingencies, for additional information.
GENERAL
- -------
As an investor-owned electric utility, the Company is capital
intensive, with a gross investment in property and plant of
approximately $3 for each $1 of annual total revenue. The costs
associated with property and plant investment amounted to 47% of
the Company's total revenue in 1995. Fuel and purchased energy,
capacity purchase payments and other operating expenses were 53%
of total revenue. The Company's principal wholly owned
subsidiary, Potomac Capital Investment Corporation (PCI),
conducts nonutility investment programs with the objective of
supplementing current utility earnings and building long-term
shareholder value.
The information set forth below discusses the results of
operations, capital resources and liquidity during the period
1993 through 1995 for the Company and PCI.
2
The Company's earnings for common stock during 1995 totaled
$77.5 million, as compared to $210.7 million in 1994. As set
forth below, utility earnings increased from $1.63 in 1994 to
$1.70 in 1995. With noncash, non-recurring charges of $1.04
related to the decision to end aircraft equipment leasing
investment by PCI, consolidated earnings per share for common
stock decreased from $1.79 in 1994 to $.65 for 1995.
- -----------------------------------------------------------------
1995 1994 1993
- -----------------------------------------------------------------
Utility Operations $1.70 $1.63 $1.73
Nonutility Subsidiary (1.05) .16 .22
----- ----- -----
Consolidated $ .65 $1.79 $1.95
===== ===== =====
- -----------------------------------------------------------------
The average number of common shares outstanding at December 31,
1995, increased by .4 million shares as compared to December 31,
1994.
3
UTILITY
- -------
RESULTS OF OPERATIONS
- ---------------------
Total Revenue
- -------------
The changes in total revenue are shown in the following table.
- -----------------------------------------------------------------
Increase (Decrease)
from Prior Year
1995 1994 1993
- -----------------------------------------------------------------
(Millions of Dollars)
Change in kilowatt-hour sales $ 27.2 $(18.7) $ 87.0
Change in base rate revenue 42.8 32.2 45.4
Change in fuel adjustment clause
billings to cover cost of
fuel and interchange and
capacity purchase payments (39.3) 73.2 8.0
Change in other revenue 1.1 1.5 (.1)
------ ------ ------
Change in Operating Revenue 31.8 88.2 140.3
------ ------ ------
Change in interchange deliveries 21.2 9.7 (16.7)
------ ------ ------
Change in Total Revenue $ 53.0 $ 97.9 $123.6
====== ====== ======
- -----------------------------------------------------------------
The $42.8 million change in 1995 base rate revenue compared
to 1994 reflects the effects of a District of Columbia rate
increase of $27.9 million (effective in July 1995), the continued
effect of a 1994 rate increase in the District of Columbia and an
increase of $29.2 million associated with the Company's Demand
Side Management (DSM) surcharge tariff rate in Maryland, which
includes $8.7 million for achieving specified 1994 Maryland
energy goals associated with the conservation incentive provision
of the tariff.
The increase in base rate revenue in 1994 as compared to
1993 reflects the effect of a District of Columbia rate increase
of $26.7 million (effective primarily in March 1994) and the
continued effect of 1993 rate increases in Maryland. Also, 1994
revenue reflects cooler weather during the summer billing months
as compared to the warmer than average weather during the
corresponding period in 1993. The Company's base rates in the
summer period are higher than at other times of the year, and for
4
many customers incorporate time-of-use rates, to encourage
customer conservation and peak load shifting. In addition, 1994
base rate revenue reflects $5 million for achieving specified
1993 Maryland energy goals associated with the conservation
incentive provision of the Company's DSM surcharge tariff.
The increase in base rate revenue in 1993 as compared to
1992 reflects the effects of Maryland rate increases of $7.3
million (effective June 1993) and $27 million (effective November
1993) and the continued effect of 1992 rate increases in both of
the Company's retail jurisdictions. Also, 1993 revenue reflects
warmer than average weather during the summer billing months of
June through October.
An increase in 1995 and 1994 and a decrease in 1993 in
revenue from interchange deliveries reflect changes in levels and
pricing in energy delivered to the Pennsylvania-New Jersey-
Maryland Interconnection Association (PJM). Interchange
deliveries in 1995 also reflect an increase in the number of
companies involved in power sales tariff interchange
transactions, where the Company buys energy from one party for
the purpose of selling that energy to a third party. Interchange
deliveries continue to be a component of the Company's fuel
rates.
5
Kilowatt-hour Sales
- -------------------
- -----------------------------------------------------------------
1995 1994
vs. vs.
1995 1994 1993 1994 1993
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
By Customer Type
Residential 6,707 6,574 6,727 2.0% (2.3)%
Commercial 11,861 11,685 11,751 1.5 (.6)
U.S. Government 3,998 4,010 3,986 (.3) .6
D.C. Government 879 914 903 (3.8) 1.2
Wholesale 2,465 2,363 2,327 4.3 1.5
------ ------ ------
Total energy sales 25,910 25,546 25,694 1.4 (.6)
====== ====== ======
Interchange
Energy deliveries 1,784 800 483 - 65.6
====== ====== ======
By Geographic Area
Maryland, including
wholesale 15,594 15,251 15,319 2.2 (.4)
District of Columbia 10,316 10,295 10,375 .2 (.8)
------ ------ ------
Total energy sales 25,910 25,546 25,694 1.4 (.6)
====== ====== ======
- -----------------------------------------------------------------
Kilowatt-hour sales increased 1.4% in 1995 resulting in part
from a 1% increase in customers. Cooling degree hours and
heating degree days remained relatively stable as compared to
1994 but were above the 20-year averages by 4% for cooling degree
hours and 5% for heating degree days. Kilowatt-hour sales
decreased slightly in 1994 as compared to 1993 as customer usage
was down because of 14% fewer cooling degree hours in the summer
of 1994. Assuming future weather conditions approximate
historical averages, the Company expects its compound annual
growth in kilowatt-hour sales to range between 1% and 2% over the
next decade.
6
The 1995 summer peak demand of 5,732 megawatts occurred on
August 4, 1995. This compares with the 1994 summer peak demand
of 5,660 megawatts, and the all-time summer peak demand of 5,769
megawatts which occurred in July 1991. The Company's present
generation capability, including capacity purchase contracts, is
6,576 megawatts. In addition, the Company had approximately 270
megawatts available from its dispatchable energy use management
programs to meet the 1995 summer peak demand. Based on average
weather conditions, the Company estimates that its peak demand
will grow at a compound annual rate of approximately 1%,
reflecting continuing success with conservation and energy use
management programs and anticipated service area growth trends.
The 1994-1995 winter season peak demand of 4,685 megawatts was
6.5% below the all-time winter peak demand of 5,010 megawatts
which was established in January 1994.
Operating Expenses
- ------------------
Fuel, Purchased Energy and Capacity Purchase Payments
- -----------------------------------------------------------------
1995 1994 1993
- -----------------------------------------------------------------
(Millions of Dollars)
Fuel expense $355.4 $392.7 $354.3
------ ------ ------
Purchased energy
PJM receipts 79.4 108.8 108.9
Other purchases 114.2 64.6 64.5
------ ------ ------
Total purchased energy 193.6 173.4 173.4
------ ------ ------
Fuel and purchased energy $549.0 $566.1 $527.7
====== ====== ======
Capacity purchase payments $125.8 $127.8 $ 96.3
====== ====== ======
- -----------------------------------------------------------------
Net System Generation and Purchased Energy were as follows.
- -----------------------------------------------------------------
1995 1994 1993
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
Net system generation 19,234 19,320 19,145
====== ====== ======
Purchased energy 9,755 8,356 8,448
====== ====== ======
- -----------------------------------------------------------------
7
The 1995 decrease in fuel expense reflects the decrease in
the system average fuel cost summarized below and a .4% decrease
in net generation. The 1994 increase in fuel expense reflects an
increase of .9% in net generation and increased use of major
cycling and peaking generation units which burn higher cost
fuels. During January 1994, severe cold weather sent demand for
electricity to a new winter peak, which required significantly
increased net generation. Major cycling and peaking generation
units were used to meet the increased demand. The 1993 increase
in fuel expense primarily reflects a 4.8% increase in net
generation resulting from the increase in kilowatt-hour sales,
partially offset by the Company's ability to purchase low-cost
economy energy from PJM, which helped keep the fuel expense
increase to a minimum.
The Company's unit costs of fuel burned and the percentages
of system fuel requirements obtained from coal, oil and natural
gas were as shown in the following table.
- -----------------------------------------------------------------
Percent of Unit Cost
Fuel Burned of Fuel Burned
------------------- --------------------------------
System
Coal Oil Gas Coal Oil Gas Average
- -----------------------------------------------------------------
(Per Million Btu)
1995 85.4 6.1 8.5 $1.60 $3.22 $2.10 $1.74
1994 76.1 18.4 5.5 1.73 2.70 2.49 1.95
1993 79.4 17.4 3.2 1.72 2.55 2.88 1.90
- -----------------------------------------------------------------
The 1995 system average unit fuel cost decreased by
approximately 11% which was primarily the result of the increased
use of lower-cost coal and gas and decreased net generation. The
increase of approximately 3% in the 1994 system average unit fuel
cost compared with the 1993 system average resulted from
increased use of major cycling and peaking generation units which
burn higher cost fuels. The Company's major cycling and certain
peaking units can burn natural gas or oil, adding flexibility in
selecting the most cost-effective fuel mix. The increase in the
percent of gas burned in 1995 and 1994 reflects the decreased
price of gas and the increased price of oil. The decrease in the
actual percent of coal contribution to the fuel mix in 1994
primarily reflects major outages for construction related to
Clean Air Act additions on baseload coal-fired generation units.
The Company's generating and transmission facilities are
interconnected with the other members of PJM and other utilities.
The pricing of most PJM internal economy energy transactions is
based upon "split savings" so that the price of such energy is
8
halfway between the cost that the purchaser would incur if the
energy were supplied by its own sources and the cost of
production to the company actually supplying the energy.
In addition to PJM interchange activity, the Company has
interconnection agreements with Allegheny Power System (APS) and
Virginia Power. These agreements provide a mechanism and the
flexibility to purchase power from these parties or from others
with whom they are interconnected on an as-needed basis in
amounts mutually agreed to from time-to-time pursuant to
negotiated rates, terms and conditions. "Other purchases"
includes the cost of this energy together with purchases of
energy from Ohio Edison under the Company's 1987 long-term
capacity purchase agreements with Ohio Edison and APS. During
1995, the Company entered into an agreement with PECO Energy
Company (PECO) to purchase up to 300, but not less than 200
megawatt-hours of energy each hour beginning on June 1, 1995.
The agreement will remain in effect until either party gives 30-
day notice of termination.
In early 1995, the Federal Energy Regulatory Commission
(FERC) approved a power sales tariff, filed by the Company, which
allows both sales from Company-owned generation and sales of
energy purchased by the Company. This tariff expands the
Company's opportunities to participate in direct energy sales
with other utilities and power marketers. Through the use of
similar tariffs, many other parties are now in a position to buy
and sell energy. The Company is actively encouraging this market
by buying energy for its own use, selling energy and buying
energy for contemporaneous resale, when economic transactions are
available.
Pursuant to the Company's long-term capacity purchase
agreements with Ohio Edison and APS, the Company is purchasing
450 megawatts of capacity and associated energy through the year
2005. The monthly capacity commitment under these agreements,
excluding an allocation of fixed operating and maintenance cost,
increased from $12,380 per megawatt through 1993 to $18,060 per
megawatt effective January 1994, with provision for escalation in
1999. In addition, from June 1994 through May 1995, the Company
purchased 147 megawatts of capacity from Pennsylvania Power and
Light Company.
The Company has a purchase agreement with Southern Maryland
Electric Cooperative, Inc. (SMECO), through 2015, for 84
megawatts of capacity supplied by a combustion turbine installed
and owned by SMECO at the Company's Chalk Point Generating
Station. The Company is responsible for all costs associated
with operating and maintaining the facility. The capacity
payment to SMECO is $462,000 per month. Capacity purchase
payments incurred under agreements with Ohio Edison and SMECO,
compare favorably with other long-term capacity and energy
alternatives.
9
Other Operation and Maintenance Expenses
- ----------------------------------------
Other operation and maintenance expenses totaled $316.9 million
for 1995. These expenses increased by $18.2 million (6.1%) in
1995, including $15.2 million relating to the December 1994 sale
and leaseback of the Company's control center system. These
expenses decreased by $2.8 million (.9%) in 1994 and increased by
$6.2 million (2.1%) in 1993. The Company's budget and cost
control disciplines have resulted in a 16% decline in the number
of Company employees since 1989. Utility operating results were
also affected by a nonrecurring charge of $7.4 million in January
1995 for one-time operating costs associated with the Company's
successful Voluntary Severance Program, which will provide annual
savings in operating and construction costs of approximately $15
million. Bad debt expense, as a percent of revenues, was .4% in
1995, 1994 and 1993. At December 31, 1995, accounts receivable
included $23.4 million, or 9.4% of outstanding receivables, due
from agencies of the District of Columbia for electric service
and maintenance, of which $17.8 million, or 7.2% of outstanding
receivables, was in arrears. As of February 2, 1996, the
District of Columbia accounts receivable balance had been reduced
to $10.2 million due to the receipt of additional payments. The
Company believes that amounts owned by the District of Columbia
will be paid and, accordingly, has not established a bad debt
reserve for this receivable balance.
Depreciation and Amortization Expense, Income Taxes and
Other Taxes
- -------------------------------------------------------
Depreciation and amortization expense increased by $25.5 million
(14.2%), $16.4 million (10%) and $13.8 million (9.2%) in 1995,
1994 and 1993, respectively, due to additional investment in
property and plant and amortization of increased amounts of
conservation costs associated with the Company's DSM program.
The increase in income taxes in 1995 and 1994, reflects higher
taxable operating income. The increase in income taxes in 1993
reflects the higher federal income tax rate which became
effective in 1993 and higher taxable income. Other taxes
decreased by $3.4 million (1.6%) in 1995, and increased by $4.8
million (2.4%) and $7.1 million (3.6%) in 1994 and 1993,
respectively. The decrease in 1995 reflects the reduction in the
county fuel-energy tax rates. The increases in 1994 and 1993
reflect changes in the levels of operating revenue and plant
investment upon which taxes are based.
10
Other Income, Net Utility Interest Charges and Allowance
for Funds Used During Construction
- --------------------------------------------------------
Other income reflected the net (loss) earnings from PCI of
$(124.4) million in 1995, $19.1 million in 1994 and $25.1 million
in 1993. See the Nonutility Subsidiary discussion below and the
discussion included in Note (15) of the Notes to Consolidated
Financial Statements, Selected Nonutility Subsidiary Financial
Information. In addition, other income, which included credits
for the capital cost recovery factor associated with unamortized
DSM costs, in 1994 reflects a total after-tax reduction of
approximately $4.1 million in connection with District of
Columbia Public Service Commission decisions. This included
disallowance of rate case test period DSM program expenditures,
adoption of an unbilled revenue adjustment applicable to the
District of Columbia portion of the 1992 accounting change
related to unbilled revenue and adoption of a three-year phase-in
period to reflect increased postretirement benefit costs. In
1993, "Other, net" also included $2.8 million from the adoption
of Statement of Financial Accounting Standards (SFAS) No. 109
entitled "Accounting for Income Taxes".
Net utility interest charges were relatively stable during
the three-year period 1993 through 1995, notwithstanding
increased levels of borrowing. Short-term borrowing costs have
remained relatively low and, with the refinancing of higher cost
issues, the average cost of outstanding long-term utility debt
declined from 8.1% at the beginning of 1993 to 7.51% at the end
of 1995.
Allowance For Funds Used During Construction (AFUDC)
credits, which decreased during the period 1993 through 1995,
relate to portions of the Company's Construction Work In Progress
investment. See the Construction and Generating Capacity
discussion below. In 1995, AFUDC decreased by $9.7 million,
primarily due to the control center system which came on-line in
December 1994. See the Capital Resources and Liquidity
discussion below.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's total investment in property and plant, at original
cost, was $6.2 billion at year-end 1995. Investment in property
and plant construction, net of AFUDC, was $819.7 million for the
period 1993 through 1995.
Internally generated cash from utility operations, after
dividends, totaled $270 million for the period 1993 through 1995.
Sales of First Mortgage Bonds, Medium-Term Notes and Common Stock
during the period 1993 through 1995 provided a total of $1.1
billion. During the years 1993 through 1995, the Company retired
11
$896 million in outstanding long-term securities, including
refinancings, scheduled debt maturities and sinking fund
retirements. Interim financing was provided principally through
the issuance of short-term commercial promissory notes. During
the three-year period 1996 through 1998, capital resources of
$228.8 million ($26.3 million in 1996) will be required to meet
scheduled debt maturities and sinking fund requirements, and
additional amounts will be required for working capital and other
needs. Approximately $870 million is expected to be available
from depreciation and amortization charges and income tax
deferrals over the three-year period of which approximately $317
million is the 1996 portion.
During 1995, the Company sold $191 million principal amount
of First Mortgage Bonds, $4.6 million of Common Stock and short-
term borrowings increased by $68.9 million. Proceeds were
applied to meet construction requirements of $221.6 million, and
scheduled debt maturities and the refinancing of higher cost debt
or shorter maturity debt totaling $117.5 million. See the
discussion included in Notes (7) and (10) of the Notes to
Consolidated Financial Statements, Common Equity and Long-Term
Debt, respectively, for additional information.
Reflecting the refinancings of debt and the respective
principal amounts outstanding, total annualized interest costs
for all utility long-term debt outstanding at December 31, 1995,
was $127.9 million, compared with $123.7 million and $114 million
at December 31, 1994 and 1993, respectively.
During December 1994, the Company entered into a sale (at
cost) and leaseback agreement for its new control center system
(system). The system is an integrated energy management system
used by the Company's power dispatchers to centrally control the
operation of the Company's electric system, which consists of all
of its generating units, the transmission system and the
distribution system. The Company has accounted for the lease of
the system as a capital lease, recorded at the present value of
future lease payments which totaled $152 million. This lease has
been treated as an operating lease for ratemaking purposes.
Dividends on preferred stock were $16.9 million in 1995,
$16.4 million in 1994 and $16.3 million in 1993. The embedded
cost of preferred stock was 6.43% at December 31, 1995, 6.53% at
December 31, 1994 and 6.2% at December 31, 1993.
12
The Company's capitalization ratios (excluding nonutility
subsidiary debt), at December 31, 1995, are presented below.
- -----------------------------------------------------------------
Excluding Including
Amounts Due Amounts Due
In One Year In One Year
- -----------------------------------------------------------------
Long-term debt 45.9% 42.8%
Redeemable serial preferred stock 3.6 3.4
Serial preferred stock 3.2 3.0
Common equity 47.3 44.1
Short-term debt and amounts due in
one year - 6.7
----- -----
Total capitalization 100.0% 100.0%
===== =====
- -----------------------------------------------------------------
Year-end 1995 outstanding utility short-term indebtedness
totaled $258.5 million compared with $189.6 million and $294.6
million at the end of 1994 and 1993, respectively.
The Company maintains 100% line of credit back-up for its
outstanding commercial promissory notes, which was unused during
1995, 1994 and 1993.
Conservation
- ------------
The Company's conservation and energy use management programs
(EUM) are designed to curb growth in demand in order to defer the
need for construction of additional generating capacity and to
cost-effectively increase the efficiency of energy use. In 1994,
the Company reevaluated its conservation programs, including
additional review and consideration of the current and
prospective effect of these programs on customer rates and bills.
As a result of this reevaluation, the Company phased out several
conservation programs and reduced rebate levels for others. In a
June 1995 order, the Public Service Commission of the District of
Columbia adopted conservation spending limits for the four-year
period 1995 through 1998. By narrowing its conservation
offerings and limiting conservation spending, the Company expects
to continue to encourage its customers to use energy efficiently
without significantly increasing electricity prices. The Company
expects to realize approximately 80% of the previously estimated
benefits from conservation for approximately 45% of estimated
cost.
During 1995, the Company invested approximately $100 million
in energy conservation programs. The Company recovers the costs
of its conservation programs in its Maryland jurisdiction through
a base rate surcharge which amortizes costs over a five-year
13
period and permits the Company to earn a return on its
conservation investment while receiving compensation for lost
revenue. In addition, when the Company's performance exceeds its
annual goals, the Company earns a performance bonus. The Company
was awarded a bonus of $8.7 million in 1995, based on 1994
performance, which followed a bonus of $5 million in 1994, based
on 1993 performance.
In the District of Columbia, conservation costs are
amortized over 10 years with an accrued return on unamortized
costs. In June 1995, the Commission adopted a base rate
surcharge for the recovery of actual conservation costs prudently
incurred since June 30, 1993; prior to this decision,
conservation costs had been considered in base rate cases. This
surcharge includes both a conservation expenditure component and
a component for recovering certain expenditures associated with
complying with the Clean Air Act Amendments of 1990. The
conservation component is to be updated annually in the spring of
each year, while the Clean Air Act component is updated
quarterly.
In 1995, approximately 157,000 customers participated in
continuing energy use management programs which cycle air
conditioners and water heaters during peak periods. In addition,
the Company operates a commercial load program which provides
incentives to customers for reducing energy use during peak
periods. Time-of-use rates have been in effect since the early
1980s and currently approximately 60% of the Company's revenue is
based on time-of-use rates.
It is estimated that peak load reductions of over 600
megawatts have been achieved to date from conservation and energy
use management programs and that additional peak load reductions
of approximately 430 megawatts will be achieved in the next five
years. The Company also estimates that, in 1995, energy savings
of more than 1.2 billion kilowatt-hours have been realized
through operation of its conservation and energy use management
programs. During the next five years, the Company's projected
costs for these programs to encourage the efficient use of
electric energy and to reduce the need to build new generating
facilities total $364 million ($77 million in 1996).
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC, are projected to
total $1.1 billion for the five-year period 1996 through 2000,
which includes $112 million of estimated Clean Air Act
expenditures. In 1996, construction expenditures are projected
to total $170 million, which includes $6 million of estimated
Clean Air Act expenditures. As a result of lower rates of
projected load growth resulting in large part from implementing
economical conservation programs, the Company previously reduced
14
its projected construction expenditures by $155 million in 1994
and $425 million in 1993. The Company plans to finance its
construction program primarily through funds provided by
operations.
A 32-megawatt municipally financed resource recovery
facility in Montgomery County, Maryland, began commercial
operation in August 1995. Under the contract covering this
project, the Company will initially purchase energy without
capacity payment obligations. In addition, the Company has an
agreement with Panda Energy Corporation for a 230-megawatt gas-
fueled combined-cycle cogeneration project in Prince George's
County, Maryland, scheduled for operation in the fourth quarter
of 1996. The 25-year agreement currently requires capacity
purchase payments to Panda Energy Corporation of approximately
$1.6 million per month from January 1, 1997 through December 31,
1998. Capacity payments in 1999 and 2000 are approximately $3
million per month and generally increase thereafter, peaking at
approximately $4.5 million per month. The project was financed
in April 1995 and is currently one-third complete. The Company
projects that existing contracts for nonutility generation and
the Company's commitment to conservation will provide adequate
reserve margins to meet customers' needs well beyond the year
2000. In 1995, the Maryland Public Service Commission issued an
order that requires electric utilities to competitively procure
future capacity resources. The Company believes that completion
of the first combined-cycle unit at its Station H facility in
Dickerson, Maryland, currently scheduled for 2004, is likely to
be the most cost-effective alternative for the next increment of
capacity. This will add a steam cycle to the two existing
combustion turbine units.
CLEAN AIR ACT
- -------------
The Company has implemented cost-effective plans for complying
with Phase I of the Clean Air Act (CAA) which requires the
reduction of sulfur dioxide and nitrogen oxides emissions to
achieve prescribed standards. Boiler burner equipment for
nitrogen oxides emissions control has been replaced and the use
of lower, sulfur coal has been instituted at the Company's Phase
I affected stations, Chalk Point and Morgantown. Anticipated
capital expenditures for complying with the second phase of the
CAA total $112 million over the next five years. The Company's
plans call for continued replacement of boiler burner equipment
for nitrogen oxides emissions control and further use of
lower-sulfur fuel and cofiring with natural gas for sulfur
dioxide (SO2) emissions control. If economical, the Company will
purchase SO2 emission allowances in lieu of burning lower-sulfur
fuel.
15
The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located in western Pennsylvania. Nitrogen
oxides emissions reduction equipment and flue gas desulfurization
equipment have been installed at the station for compliance with
Phase I of the CAA. The Company's share of construction costs
for this equipment was $36.2 million. As a result of installing
the flue gas desulfurization equipment, the station has received
additional SO2 emission allowances. The Company's share of these
bonus allowances will be used to reduce the need for lower-sulfur
fuel at its other plants.
BASE RATE PROCEEDINGS
- ---------------------
The Company is subject to utility rate regulation based upon the
historical costs of plant investment, using recent test years to
measure the cost of providing service. The rate-making process
does not give recognition to the current cost of replacing plant
and the impact of inflation. Changes in industry structure and
regulation may affect the extent to which future rates are based
upon current costs of providing service. The regulatory
commissions have authorized fuel rates which provide for billing
customers on a timely basis for the actual cost of fuel and
interchange and for emission allowance costs and, in the District
of Columbia, for purchased capacity.
Annual base rate increases which became effective during the
period 1993 through 1995 are shown below.
- -----------------------------------------------------------------
District
of
Year Total Maryland Columbia Wholesale
- -----------------------------------------------------------------
(Millions of Dollars)
1995 $ 30.2 $ - $27.9 $2.3
1994 29.3 - 26.7 2.6
1993 38.1 34.3 - 3.8
------ ----- ----- ----
$ 97.6 $34.3 $54.6 $8.7
====== ===== ===== ====
- -----------------------------------------------------------------
Maryland
- --------
Pursuant to a settlement agreement, base rate revenue was
increased by $27 million, or 3%, effective November 1, 1993. The
Commission previously authorized an increase in base rate revenue
of $7.3 million, effective June 1, 1993, pursuant to an October
1992 settlement agreement. In connection with the settlement
agreements, no determination was made with respect to rate of
16
return. The rate of return on common stock equity most recently
determined for the Company in a fully litigated rate case was
12.75%, established by the Commission in a June 1991 rate
increase order.
The Company's Maryland DSM Surcharge, which provides for the
recovery of conservation program costs over a five-year period
and includes provisions for the recovery of lost revenue, a
capital cost recovery factor, calculated at 9.46%, on unrecovered
program balances and an incentive amount based on achieving
prior-year goals, was increased effective July 1, 1995. The new
rate will result in an increase in the annual surcharge recovery
of approximately $29 million, including the initial amortization
of 1995 projected program costs and the previously mentioned
incentives of $8.7 million and $5 million for exceeding 1994 and
1993 program goals, respectively.
District of Columbia
- --------------------
On June 30, 1995, in Formal Case No. 939, the Commission
authorized a $27.9 million, or 3.8%, increase in base rate
revenue effective July 11, 1995. The authorized rates are based
on a 9.09% rate of return on average rate base, including an
11.1% return on common stock equity and a capital structure which
excludes short-term debt. In addition, the Commission approved
the Company's Least-Cost Plan filed in June 1994. A four-year
DSM spending cap for the period 1995-1998 was approved,
consistent with the Company's proposal to narrow the scope of DSM
activities by discontinuing operation of certain DSM programs and
by reducing expenditures on the remaining programs. This will
enable the Company to implement cost-effective conservation
programs while limiting the impact of such programs on the price
of electricity. An Environmental Cost Recovery Rider (ECRR) was
approved to provide for full cost recovery of actual conservation
program expenditures, through a billing surcharge. Costs will be
amortized over 10 years, with a return on unamortized amounts by
means of a capital cost recovery factor computed at the
authorized rate of return. The initial rate, which reflects all
actual costs expended from July 1993 through December 1994, will
result in $15 million of additional revenue annually. Subsequent
rate updates will be filed annually on June 1 to reflect the
prior year's actual costs, subject to the annual surcharge
recovery limit within the four-year spending cap (amounts spent
in excess of the annual surcharge recovery limit, but within the
four-year spending cap, are deferred for future recovery). Pre-
July 1993 conservation costs receive rate base treatment.
Although the Commission denied the Company's request to recover
"lost revenue" due to DSM programs, through the surcharge, a
process has been established whereby the Company can seek
recovery of lost revenue in a separate proceeding. The
Commission also increased the time period for filing Least-Cost
Planning cases from two to three years.
17
Wholesale
- ---------
The Company has a 10-year full service power supply contract with
the Southern Maryland Electric Cooperative, Inc. (SMECO), a
wholesale customer. The contract period is to be extended for an
additional year on January 1 of each year, unless notice is given
by either party of termination of the contract at the end of the
10-year period. The full service obligation can be reduced by
SMECO by up to 20% of its annual requirements with a five-year
advance notice for each such reduction. SMECO rates were
increased by $2.3 million effective January 1, 1995, and $2.6
million effective January 1, 1994. A new agreement was recently
concluded with SMECO for the years 1996 through 1998. A rate
reduction of $2 million from the 1995 rate level is scheduled to
become effective January 1, 1996, with an additional $2.5 million
rate reduction effective January 1, 1998. Approval of the rate
settlement by the Federal Energy Regulatory Commission is
expected in February 1996. SMECO has agreed not to give the
Company a notice of reduction or termination of service (to take
effect after five years or nine years, respectively) prior to
December 15, 1998.
COMPETITION
- -----------
The electric utility industry is subject to increasing
competitive pressures, stemming from a combination of increasing
independent power production, greater reliance upon long-distance
transmission, and regulatory and legislative initiatives intended
to increase bulk power competition, including the Energy Policy
Act of 1992. Since the early 1980s, the Company has pursued
strategies which achieve financial flexibility through
conservation and energy use management programs, extension of the
useful life of generating equipment, cost-effective purchases of
capacity and energy and preservation of scheduling flexibility to
add new generating capacity in relatively small increments. The
Company serves a unique and stable service territory and is a
low-cost energy producer with customer prices which compare
favorably with regional and national averages.
On August 18, 1995, the Maryland Public Service Commission
issued an order in a generic proceeding dealing with electric
industry structure and the advent of competition. The Commission
found that competition at the wholesale level holds the greatest
potential for producing significant benefits, while competition
at the retail level would carry many potential problems and
difficult-to-find solutions. The Commission stated that it was
intrigued by a restructuring concept suggested by the Company,
which calls for functionally dividing the utility into generation
and transmission/distribution segments. The Commission
encouraged the Company to develop the concept further and
suggested that other electric utilities in the state develop
18
similar proposals specific to their competitive positions. A
proceeding dealing with structure and competition was initiated
by the District of Columbia Commission during 1995.
Based on the regulatory framework in which it operates, the
Company currently applies the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" in
accounting for its utility operations. SFAS No. 71 allows
regulated entities, in appropriate circumstances, to establish
regulatory assets and to defer the income statement impact of
certain costs that are expected to be recovered in future rates.
Deregulation of portions of the Company's business could, in the
future, result in not meeting the rate recovery criteria for
application of SFAS No. 71 for part or all of the business.
While the Company does not foresee such a situation at this time,
if this were to occur in the transition to a more competitive
business, accounting standards of enterprises in general would
apply which would entail the write-off of any previously deferred
costs to results of operations. Regulatory assets include
deferred income taxes, unamortized conservation costs and
unamortized debt reacquisition costs recoverable through future
rates.
RESTRUCTURING OF THE BULK POWER MARKET
- --------------------------------------
In March 1995, the FERC issued a Notice of Proposed Rulemaking
(NOPR) on competition in the wholesale energy market. The FERC's
goal is to achieve greater competition in the bulk power market
through open access to utilities' high voltage transmission
lines. The Company, through its membership in PJM, endorses the
goals of the FERC. PJM has many years of experience in providing
economically efficient transmission and generation services
throughout the Mid-Atlantic region, and has achieved for its
members, including the Company, significant cost savings through
shared generating reserves and integrated operations. In order
to meet the FERC's goals, the PJM members plan to implement
significant market-oriented changes which will support broader
market participation and achieve even greater efficiencies. The
PJM members are working to transform today's coordinated cost-
based pool dispatch into a vigorous price-based regional energy
market operating under a standard of transmission service
comparability. The Company, together with PJM, supports the
evolution of new market-based structures to make competition
truly effective.
Subsequent to this NOPR, Duquesne Light Company requested
that it be provided with 300 megawatts of transmission service,
firm and non-firm with flexible destinations, for 20 years on the
PJM and APS systems. During May 1995, FERC issued an order
directing the PJM and APS companies to provide Duquesne with the
transmission service it requested and to negotiate jointly the
appropriate rates, terms and conditions. On June 30, 1995, a
19
"final offer" was submitted as directed by the transmitting
companies. This final offer contained the allocation of the 300
megawatts among the member utilities and each company's firm
transmission rates. Final briefs were filed with FERC on July
25, 1995. The transmitting companies are currently awaiting a
decision from FERC.
On November 30, 1995, the PJM members filed with the FERC a
detailed proposal that offers to all generators and wholesale
buyers of electricity a regional energy market and open access to
PJM high voltage transmission lines. Under the proposal, PJM
will be transformed into an Independent System Operator (ISO),
which will administer a rate structure designed to eliminate
dealing with each company separately for transactions through
PJM. The ISO will administer operations, operate the regional
energy market and administer transmission service. PJM expects
to implement the new structure by year-end 1996. This change is
not expected to have a material effect on the operations of the
Company.
THE COVE POINT JOINT VENTURE
- ----------------------------
Subsidiaries of the Company and Columbia Gas System, Inc., have
formed a 50/50 joint venture partnership (the Partnership) to own
and operate natural gas storage and terminaling facilities at
Cove Point, Maryland, and an 87-mile natural gas pipeline that
extends from Cove Point to Loudoun County, Virginia. These
facilities were previously owned by Columbia LNG Corporation, a
Columbia Gas subsidiary.
Under the agreement, Columbia LNG Corp. contributed its Cove
Point terminal and pipeline assets and $7 million in cash in
exchange for an equity interest in the Partnership, and the
Company's subsidiaries invested $25 million in the form of equity
and debt. This investment was used by the Partnership to
construct a new liquefaction unit and to recommission certain
existing facilities at the terminal that are being used in the
peaking service business. In November 1994, the FERC approved
the project based on cost-of-service rates. Commercial operation
began on September 28, 1995,and to date, in accordance with the
business plan, the Partnership has sold storage service for one
of the four storage tanks.
One of the Company's principal strategic interests in the
Cove Point project is to secure a reliable and cost-effective
source of transportation for gas to provide fuel to the
generators at its Chalk Point Generating Station. The 87-mile
Cove Point pipeline is the sole means of delivering natural gas
to southern Maryland where Chalk Point is located. The FERC-
approved transportation rates on the pipeline resulted in a 49%
decrease from the transportation rates previously paid by the
20
Company. The Company has expanded Chalk Point's fuel flexibility
to burn increased amounts of gas to comply with the CAA and
minimize customer costs.
JOINT VENTURE FOR WIRELESS DATA COMMUNICATION NETWORK AND NEW
- -------------------------------------------------------------
ENERGY SERVICES SUBSIDIARY FORMED; W. A. CHESTER, L.L.C.
--------------------------------------------------------
ACQUIRED
--------
In May 1995, a subsidiary of the Company, PepData, Inc. and
Metricom, Inc., entered into a joint venture agreement to own and
operate a wireless data communication network which will offer
economical data communication services to approximately four
million people in the Washington, D.C. metropolitan area. The
agreement calls for the Company to invest $7 million and to own
20 percent of the joint venture company, Metricom DC L.L.C.,
which will install radio devices on public and private facilities
to create the wireless data communication service. This data
service, known as "Ricochet," will enable computer users to
access on-line services such as the Internet, E-Mail and local
area networks. The service will be offered at a fixed monthly
rate, which will include unlimited use of the service and access
to the Internet. The joint venture is currently obtaining the
necessary state and local approvals required for the deployment
and operation of the communication service. Operation is
expected to begin during 1996. As of December 31, 1995, the
Company has invested $.1 million in the joint venture.
Also in May 1995, a subsidiary, PEPCO Services, Inc., was
formed to offer a range of energy-related services to businesses
and government organizations in the region. The energy-related
services provided by the subsidiary include assessment of
existing energy systems, installation of lighting, heating,
cooling and refrigeration systems including provision of
financing and leasing arrangements or shared-savings
arrangements, and facilities management. As of December 31,
1995, the Company has invested $1.3 million in this subsidiary.
On December 31, 1995, a newly formed, wholly owned
subsidiary acquired, for $1 million, the assets of the W. A.
Chester Division of Fischbach Power Services, Inc., which
specializes in providing underground cable construction and
maintenance services for utility companies. The new company
known as W. A. Chester, L.L.C. intends to provide a broad array
of high-quality, cost-saving services for utility and
telecommunications companies.
21
NEW ACCOUNTING STANDARD
- ------------------------
In March 1995, the Financial Accounting Standards Board issued
SFAS No. 121 entitled "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of" which
will become effective for the Company's 1996 consolidated
financial statements. This statement requires the Company to
review long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an
asset may not be recovered. In addition, regulated companies are
required to write-off regulatory assets whenever those assets no
longer are probable of recovery from customers through future
rates. The Company does not expect implementation of this
pronouncement to have a material impact on its consolidated
financial statements.
ENVIRONMENTAL MATTERS
- ---------------------
The Company is subject to federal, state and local legislation
and regulation with respect to environmental matters, including
air and water quality and the handling of solid and hazardous
waste. As a result, the Company is subject to environmental
contingencies, principally related to possible obligations to
remove or mitigate the effects on the environment of the
disposal, effected in accordance with applicable laws at the
time, of certain substances at various sites. During 1995, the
Company was participating in environmental assessments and
cleanups under these laws at four federal Superfund sites and a
private party site as a result of litigation. While the total
cost of remediation at these sites may be substantial, the
Company shares liability with other potentially responsible
parties. Based on the information known to the Company at this
time, management is of the opinion that resolution of these
matters will not have a material effect on the results of
operations or financial position of the Company.
See the discussion included in Note (13) of the Notes to
Consolidated Financial Statements, Commitments and Contingencies,
for additional information.
22
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
In 1995, PCI incurred a net operating loss of $124.4 million
($1.05 per share) of which $122.2 million ($1.04 per share) was
the result of nonrecurring, noncash, after-tax charges associated
with the Company's decision to exit the aircraft equipment
leasing business. This compared with contributions to
consolidated net earnings of $19.1 million ($.16 per share) in
1994 and $25.1 million ($.22 per share) in 1993. As summarized
below, in May 1995, PCI adopted a plan to end its investment in
the aircraft equipment leasing business and made a second quarter
$110 million noncash, after-tax charge against earnings.
Additional noncash, after-tax charges of $12.2 million were made
to recognize a noncash valuation adjustment for aircraft
equipment under a master lease agreement.
The plan to exit the aircraft equipment leasing business was
developed following comprehensive review and analysis, and is
designed to preserve value through an orderly withdrawal from the
business. The decision to exit the business was based on an
accumulation of factors which led to the conclusion that the
aircraft leasing business was no longer consistent with PCI's
goal of providing a stable supplement to consolidated earnings.
These factors include the recent inability to secure satisfactory
leases for certain aircraft returned by prior lessees, continuing
difficulties and credit risks associated with certain lessees,
and PCI's evaluation of the prospects for its aircraft lease
portfolio and the airline industry in general.
Under the plan, PCI will make no new investments to increase
the size of the aircraft leasing portfolio. In addition, 13
aircraft, (seven L1011 aircraft, two F28-4000 aircraft, one A300
aircraft, two B747-200 aircraft and one B747-200F aircraft) were
designated for sale over 18 to 24 months from the date the plan
was announced. These aircraft are subject to short-term, usage-
based leases, long-term leases that will expire in the near term,
or are not currently under lease. Negotiations continue with
respect to the sale of these aircraft. The B747-200F aircraft
currently is the subject of litigation with the lessee. (See the
Notes to Consolidated Financial Statements, (13) Commitments and
Contingencies, Nonutility Subsidiary, for additional
information.) The book value of these aircraft (which, prior to
adoption of the plan, was $295 million) was reduced to an
estimated net realizable value of approximately $105 million.
After taking into account the elimination of a previously
established reserve of approximately $22 million for future
repair and maintenance expenditures and other minor adjustments,
the result was an immediate noncash charge to after-tax earnings
of approximately $110 million for the second quarter of 1995.
23
There will be no future depreciation of, or routine accrual for
repair and maintenance expenditures with respect to, these
aircraft. For accounting purposes, gains or losses from the sale
of individual aircraft will be deferred until completion of the
disposal process.
Also as a result of differences between the guaranteed
residual value and the expected market value of the two aircraft
under the master lease agreement, PCI, following generally
accepted accounting principles, recorded $12.2 million in
additional after-tax charges against 1995 earnings. In October
1995, PCI terminated the master lease, purchasing for $52 million
the two DC-10-30 aircraft on operating lease to Canadian Airlines
International, Ltd. (Canadian Airlines). Depreciation and
interest charges following purchase are substantially the same as
the master lease rental payments.
In accordance with the plan, PCI will continue to hold and
closely monitor the remainder of its aircraft leasing portfolio,
with the objective of identifying future opportunities for
disposition of these investments on favorable terms. Included in
this portion of the portfolio are two wholly owned DC-10-30
aircraft, six majority-owned aircraft (three DC-10-30 aircraft
and three B747-200 aircraft) and two DC-10-30 aircraft held by
partnerships in which PCI has a 50% interest, all of which are
under long-term operating leases to Canadian Airlines,
Continental Airlines or United Airlines. Depreciation on each of
these aircraft has been increased in order to achieve book values
at lease expiration that will correspond to their respective
anticipated residual values. The net effect of this revised
depreciation, coupled with the elimination of further
depreciation on the aircraft designated for sale, will result in
higher depreciation charges through 1997, and lower depreciation
charges thereafter, as compared to the depreciation charges PCI
would have incurred absent the plan. No adjustments were made to
the remainder of PCI's aircraft leasing portfolio, which consists
of 12 full or partial interests in aircraft under leveraged
leases or direct finance leases (one DC-10-30 aircraft, three MD-
82 aircraft, four B737-300 aircraft, two B747-300 aircraft, one
B757-200 aircraft and one MD-11F aircraft).
As a part of its plan to exit the aircraft equipment leasing
business, PCI has formed a joint venture with an affiliate of a
major institutional investor to assist with the disposition of 19
portfolio aircraft. All the assets of the venture are fully
consolidated on PCI's financial statements with the outside
investor's portion reflected as minority interest.
24
In January 1995, Continental announced its intention to seek
the early termination of all of its A300 aircraft leases and
rental reductions under certain leases of other widebody
aircraft. Following negotiations, in April 1995, PCI signed an
agreement with Continental regarding this matter. As
compensation for the 1995 early return and lease termination of
the A300 aircraft, PCI received Continental 6% convertible
debentures with an aggregate face value of $9.6 million. In
November 1995, PCI sold the debentures for 97% of par value,
resulting in a pre-tax gain of $7.1 million. The agreement with
Continental also provides for the deferral of approximately 40%
of aggregate monthly rentals from the four majority-owned and two
jointly owned DC-10-30 aircraft for a period of sixteen months,
commencing February 1995. The deferred amounts are to be repaid
over a three and one-half year period with 8% interest,
commencing June 1, 1996, at which time the aggregate deferred
amount will be approximately $20 million. In addition, as part
of the agreement, PCI obtained cross-default provisions in its
Continental leases and improvements in aircraft return
conditions.
25
PCI's aircraft portfolio at December 31, 1995 is summarized
below.
Aircraft
Designated for
Sale in Near Term Qty(1) Year(2) Lessee Lease Type
- ------------------ --------------------------------------------
A-300 aircraft 1 1979 (4) N/A
B747-200 aircraft 2 1976/77 (3) (4) N/A
B747-200F aircraft
& spare engine 1 1976 Atlas Air Operating
F-28-4000 aircraft
& spare engine 2 1979/80 USAir(3) Operating
L1011-50 aircraft 2 1974 ING(3) Operating
L1011-50 aircraft 1 1975 TWA(3) Operating
L1011-100 aircraft 4 1974/75 (3) (4) N/A
Aircraft
With Increased
Depreciation
- -------------------
B747-200 aircraft
& spare engine 1 1972 Continental(3) Operating
B747-200 aircraft 2 1978 United(3) Operating
DC-10-30 aircraft 4 1973 Continental(3) Operating
DC-10-30 aircraft 1 1974 Continental(3) Operating
DC-10-30 aircraft 2 1975/76 Canadian(5) Operating
- -----------------------------------------------------------------
(1) Includes all equipment in which PCI has a greater than 10%
ownership interest.
(2) Year of manufacture.
(3) PCI owns a partial interest in certain of this equipment.
(4) Currently not on lease.
(5) Subject to a master lease agreement prior to October 1995.
26
All Other Aircraft
Equipment Qty(1) Year(2) Lessee Lease Type
- ------------------ --------------------------------------------
B737-300 aircraft 4 1988 United(3) Direct
Finance
B747-300 Combi
aircraft 1 1984 KLM(3) Leveraged
B747-300 aircraft 1 1985 Singapore(3) Leveraged
B757-200 aircraft 1 1986 Northwest Leveraged
DC-10-30 aircraft 1 1979 Continental(3) Direct
Finance
MD-11F aircraft 1 1993 Fed. Express Leveraged
MD-82 aircraft 1 1982 Continental(3) Direct
Finance
MD-82 aircraft
& spare engine 2 1987 Continental(3) Direct
Finance
Aircraft Engines 10 Various Various Operating
- -----------------------------------------------------------------
(1) Includes all equipment in which PCI has a greater than 10%
ownership interest.
(2) Year of manufacture.
(3) PCI owns a partial interest in certain of this equipment.
In September 1995, PCI purchased from and leased back to an
Australian governmental entity two 350 megawatt (gross) coal-
fired electric generating units located in Queensland, Australia.
PCI's original equity investment totaled $96 million and is
accounted for as a leveraged lease.
During 1994, PCI purchased from and leased back to a Dutch
electric utility company an approximate one-third undivided
interest in a recently-constructed 650 megawatt (gross) base
load, coal and gas-fired power plant located in The Netherlands.
PCI's original equity investment totaled $60 million and is
accounted for as a leveraged lease.
PCI's investment in finance leases at December 31, 1995
included a net investment of $50.6 million in five 30-megawatt
Solar Electric Generating Systems (SEGS) projects in the Mojave
Desert in California. The Company owns 22%, 10%, 19%, 31%, and
25% of SEGS projects III through VII, respectively. During
December 1995, PCI recorded a $3.2 million pretax writedown
related to its investment in the SEGS III project. The five SEGS
power generating projects sell electricity to Southern California
Edison Company (Edison) under thirty year Interim Standard Offer
No. 4 power purchase agreements which fix the capacity charge for
the term of the agreement and fix the energy rate paid by Edison
for the first 10 years of the agreements. For the remaining term
of the agreements, energy rates are variable, based on
27
Edison's avoided cost of generation. The SEGS projects are
scheduled to begin supplying electricity at avoided cost rates at
various times beginning in early 1997 through the end of 1998.
As a result of declines in Edison's avoided costs subsequent to
the inception of these agreements, revenue at these projects
currently is expected to be substantially lower than revenue
presently being realized under the fixed energy price terms of
the agreements. If current avoided cost levels were to continue,
PCI could experience reduced earnings or incur additional losses
associated with these projects. In conjunction with other
project investors, PCI is investigating and pursuing alternatives
for these projects, including but not limited to, renegotiating
the power purchase agreements and restructuring the associated
non-recourse debt.
PCI generates income primarily from its leasing activities
and securities investments. Income from leasing activities,
which includes rental income, gains on asset sales, interest
income and fees totaled $100.7 million in 1995 compared to $111.3
million in 1994 and $114.2 million in 1993. The decrease in 1995
revenue from leasing activities over 1994 was primarily due to a
decrease in rental income from operating leases and reduced fee
income.
PCI's marketable securities portfolio contributed pre-tax
income of $36.1 million in 1995 compared with $35.1 million and
$38.4 million in 1994 and 1993, respectively, which results
included net realized gains of $.4 million in 1995 compared with
$.8 million and $7 million in 1994 and 1993, respectively.
Other income decreased in 1995 compared to 1994 primarily
due to a 1994 sale of real estate held for development.
28
Expenses, before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $174.5 million in 1995 compared to $150.6
million and $159.3 million in 1994 and 1993, respectively.
Expenses increased in 1995 over 1994 primarily as a result of the
$18.8 million pre-tax charge in 1995 to recognize the difference
between the guaranteed residual value and the expected market
value of aircraft subject to the master lease agreement which
expired in September 1995. Depreciation expense also increased
in 1995 as a result of the plan to exit the aircraft equipment
leasing business.
PCI had income tax credits of $85.7 million in 1995 compared
to income tax credits of $22.7 million and $45.1 million in 1994
and 1993, respectively. The increase in income tax credits in
1995 over 1994 and 1993 was the result of the previously
mentioned charge relating to the decision to exit the aircraft
equipment leasing business.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The $530.3 million securities portfolio, consisting primarily of
investment grade preferred stocks, provides PCI significant
liquidity and investment flexibility.
Investments in leased equipment of approximately $155
million in 1995 were for the purchase of two 350 megawatt (gross)
coal-fired electric generating units located in Australia for $96
million, two DC-10-30 aircraft previously under a master lease
for $52 million and $7.4 million for the purchase of aircraft
engines placed under operating leases. The aircraft are on
operating lease to Canadian Airlines. The electric generating
units were purchased and leased back under a long-term leveraged
lease to an Australian governmental entity.
PCI's outstanding short-term debt totaled $223.4 million at
December 31, 1995, an increase of $175 million from the $48.4
million outstanding at December 31, 1994. During 1995, PCI
issued $182 million in long-term debt, including non-recourse
debt, and debt repayments totaled $275 million. At December 31,
1995, PCI had $394 million available under its Medium-Term Note
Program and $400 million of unused short-term bank credit lines.
PCI has paid a total of $100 million in dividends to PEPCO,
including a $9 million dividend paid in January 1995. PCI paid a
dividend of $50 million to the Company in December 1990, and
subsequent dividend payments, through January 1995, have been
approximately 50% of annual net earnings, with consideration
given to future business plans, debt-to-equity ratios and
anticipated capital requirements.
29
Report of Independent Accountants
To the Shareholders and
Board of Directors of
Potomac Electric Power Company
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of earnings and of cash flows
present fairly, in all material respects, the financial position
of Potomac Electric Power Company and its subsidiaries at
December 31, 1995 and 1994, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted
accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is
to express an opinion on these financial statements based on our
audits. We conducted our audits of these statements in
accordance with generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed
above.
/s/ Price Waterhouse LLP
Washington, D.C.
January 19, 1996
30
<TABLE>
Consolidated Statements of Earnings
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- ------------------------------------------------------------------------------------------------------
For the year ended December 31,
1995 1994 1993
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Revenue (Note 2)
Operating revenue $1,822,432 $1,790,600 $1,702,442
Interchange deliveries 53,670 32,474 22,763
---------- ---------- ----------
Total Revenue 1,876,102 1,823,074 1,725,205
---------- ---------- ----------
Operating Expenses
Fuel 355,453 392,730 354,282
Purchased energy 193,592 173,384 173,456
---------- ---------- ----------
Fuel and purchased energy 549,045 566,114 527,738
Capacity purchase payments (Note 13) 125,769 127,822 96,288
Other operation 224,030 206,106 207,814
Maintenance 92,859 92,614 93,668
Depreciation and amortization 205,490 179,986 163,607
Income taxes (Note 4) 128,460 119,859 110,176
Other taxes (Note 5) 202,708 206,080 201,252
---------- ---------- ----------
Total Operating Expenses 1,528,361 1,498,581 1,400,543
---------- ---------- ----------
Operating Income 347,741 324,493 324,662
---------- ---------- ----------
Other (Loss) Income
Nonutility subsidiary (Note 15)
Income 134,493 147,006 139,341
Loss on assets held for disposal (170,078) - -
Expenses, including interest and income taxes (88,812) (127,918) (114,240)
---------- ---------- ----------
Net (loss) earnings from nonutility subsidiary (124,397) 19,088 25,101
Allowance for other funds used during construction 1,548 9,123 13,242
Other, net 8,549 4,046 10,221
---------- ---------- ----------
Total Other (Loss) Income (114,300) 32,257 48,564
---------- ---------- ----------
Income Before Utility Interest Charges 233,441 356,750 373,226
---------- ---------- ----------
Utility Interest Charges
Interest on debt 146,558 139,210 141,393
Allowance for borrowed funds used during construction (7,508) (9,622) (9,746)
---------- ---------- ----------
Net Utility Interest Charges 139,050 129,588 131,647
---------- ---------- ----------
Net Income 94,391 227,162 241,579
Dividends on Preferred Stock 16,851 16,437 16,255
---------- ---------- ----------
Earnings for Common Stock $ 77,540 $ 210,725 $ 225,324
========== ========== ==========
Average Common Shares Outstanding (000s) 118,412 118,006 115,640
Earnings Per Common Share <F1> $.65 $1.79 $1.95
Cash Dividends Per Common Share $1.66 $1.66 $1.64
<FN>
<F1>No material dilution would occur if all of the convertible preferred stock
and debentures were converted into common stock.
</FN>
31
</TABLE>
<TABLE>
Consolidated Balance Sheets
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- ---------------------------------------------------------------------------------------------
December 31,
Assets 1995 1994
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Property and Plant - at original cost (Notes 6 and 10)
Electric plant in service $ 6,041,203 $ 5,801,349
Construction work in progress 93,047 147,224
Electric plant held for future use 4,082 18,041
Nonoperating property 22,771 7,556
----------- -----------
6,161,103 5,974,170
Accumulated depreciation (1,760,792) (1,639,771)
----------- -----------
Net Property and Plant 4,400,311 4,334,399
----------- -----------
Current Assets
Cash and cash equivalents 5,844 7,198
Customer accounts receivable, less allowance for uncollectible
accounts of $1,669 and $2,432 137,456 107,351
Other accounts receivable, less allowance for uncollectible
accounts of $300 36,765 57,128
Accrued unbilled revenue (Note 1) 73,622 67,543
Prepaid taxes 36,255 34,352
Other prepaid expenses 7,562 5,448
Material and supplies - at average cost
Fuel 63,203 73,671
Construction and maintenance 70,497 72,447
----------- -----------
Total Current Assets 431,204 425,138
----------- -----------
Deferred Charges
Income taxes recoverable through future rates, net (Note 4) 244,181 251,357
Conservation costs, net 230,412 161,204
Unamortized debt reacquisition costs 58,360 56,725
Other 138,619 98,783
----------- -----------
Total Deferred Charges 671,572 568,069
----------- -----------
Nonutility Subsidiary Assets
Cash and cash equivalents 1,594 -
Marketable securities (Notes 11 and 15) 530,323 473,608
Investment in finance leases (Note 15) 489,430 410,327
Operating lease equipment, net of accumulated depreciation
of $79,275 and $116,832 (Note 15) 272,947 544,064
Assets held for disposal 104,370 -
Receivables, less allowance for uncollectible
accounts of $6,000 and $5,000 74,957 76,426
Other investments 125,783 147,313
Other assets 15,659 22,551
----------- -----------
Total Nonutility Subsidiary Assets 1,615,063 1,674,289
----------- -----------
Total Assets $ 7,118,150 $ 7,001,895
=========== ===========
32
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
December 31,
Capitalization and Liabilities 1995 1994
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Capitalization
Common equity (Note 7)
Common stock, $1 par value - authorized 200,000,000 shares,
issued 118,494,577 and 118,248,103 shares $ 118,495 $ 118,248
Premium on stock and other capital contributions 1,025,088 1,020,689
Capital stock expense (14,567) (14,163)
Retained income 742,296 830,524
----------- -----------
Total Common Equity 1,871,312 1,955,298
Preference stock, cumulative, $25 par value -
authorized 8,800,000 shares, no shares issued or outstanding - -
Serial preferred stock (Notes 8 and 11) 125,325 125,409
Redeemable serial preferred stock (Notes 9 and 11) 143,485 143,563
Long-term debt (Notes 10 and 11) 1,817,077 1,723,399
----------- -----------
Total Capitalization 3,957,199 3,947,669
----------- -----------
Other Non-Current Liabilities
Capital lease obligation (Note 13) 165,235 167,324
----------- -----------
Total Other Non-Current Liabilities 165,235 167,324
----------- -----------
Current Liabilities
Long-term debt due within one year 26,280 45,445
Short-term debt (Note 12) 258,465 189,600
Accounts payable and accrued payroll 104,396 117,909
Capital lease obligation due within one year 20,772 20,772
Taxes accrued 19,111 20,509
Interest accrued 38,532 36,840
Customer deposits 23,372 22,563
Other 62,662 84,841
----------- -----------
Total Current Liabilities 553,590 538,479
----------- -----------
Deferred Credits
Income taxes (Note 4) 892,544 848,456
Investment tax credits (Note 4) 64,607 68,256
Other 35,089 31,766
----------- -----------
Total Deferred Credits 992,240 948,478
----------- -----------
Nonutility Subsidiary Liabilities
Long-term debt (Notes 10 and 11) 1,047,484 1,140,505
Short-term notes payable (Note 12) 223,350 48,400
Deferred taxes and other (Note 4) 179,052 211,040
----------- -----------
Total Nonutility Subsidiary Liabilities 1,449,886 1,399,945
----------- -----------
Commitments and Contingencies (Note 13)
Total Capitalization and Liabilities $ 7,118,150 $ 7,001,895
=========== ===========
33
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- -----------------------------------------------------------------------------------------------------
For the year ended December 31,
1995 1994 1993
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities
Income from utility operations $ 218,788 $ 208,074 $ 216,478
Adjustments to reconcile income to net cash
from operating activities:
Depreciation and amortization 205,490 179,986 163,607
Deferred income taxes and investment tax credits 51,774 44,641 27,711
Allowance for funds used during construction (9,056) (18,745) (22,988)
Changes in materials and supplies 12,418 (13,883) 44,509
Changes in accounts receivable and accrued unbilled revenue (15,822) (6,098) (35,399)
Changes in accounts payable (14,419) 8,257 (441)
Changes in other current assets and liabilities (1,484) (6,760) 4,317
Changes in deferred conservation costs (104,796) (92,504) (59,639)
Net other operating activities (45,664) 360 (37,121)
Nonutility subsidiary:
Net (loss) earnings (124,397) 19,088 25,101
Deferred income taxes (49,697) 6,386 (32,814)
Loss on assets held for disposal 170,078 - -
Changes in other assets and net other operating activities 83,509 47,648 56,897
--------- --------- ---------
Net Cash From Operating Activities 376,722 376,450 350,218
--------- --------- ---------
Investing Activities
Total investment in property and plant (230,675) (316,890) (322,951)
Allowance for funds used during construction 9,056 18,745 22,988
--------- --------- ---------
Net investment in property and plant (221,619) (298,145) (299,963)
Nonutility subsidiary:
Purchase of marketable securities (35,221) (127,335) (254,213)
Proceeds from sale or redemption of marketable securities 27,846 82,444 194,295
Investment in leased equipment (154,766) (72,134) (32,360)
Proceeds from sale or disposition of leased equipment - 1,150 120,529
Proceeds from sale of assets 5,966 - -
Purchase of other investments (3,818) (7,191) (44,628)
Proceeds from sale or distribution of other investments 15,614 18,429 -
Investment in promissory notes (7,955) (542) (1,628)
Proceeds from promissory notes 7,977 4,902 3,013
--------- --------- ---------
Net Cash Used by Investing Activities (365,976) (398,422) (314,955)
--------- --------- ---------
Financing Activities
Dividends on common stock (196,469) (195,755) (189,837)
Dividends on preferred stock (16,851) (16,437) (16,255)
Issuance of common stock 4,580 9,285 96,001
Redemption of preferred stock (78) (4,047) (1,500)
Issuance of long-term debt 188,594 302,999 521,264
Reacquisition and retirement of long-term debt (117,465) (144,422) (628,448)
Proceeds from sale and leaseback of control center system - 152,000 -
Short-term debt, net 68,865 (105,015) 233,015
Other financing activities (23,611) (14,452) (26,199)
Nonutility subsidiary:
Issuance of long-term debt 182,000 286,750 363,653
Repayment of long-term debt (275,021) (173,950) (247,077)
Short-term debt, net 174,950 (77,850) (137,265)
--------- --------- ---------
Net Cash (Used by) From Financing Activities (10,506) 19,106 (32,648)
--------- --------- ---------
Net Increase (Decrease) In Cash and Cash Equivalents 240 (2,866) 2,615
Cash and Cash Equivalents at Beginning of Year 7,198 10,064 7,449
--------- --------- ---------
Cash and Cash Equivalents at End of Year (Note 14) $ 7,438 $ 7,198 $ 10,064
========= ========= =========
34
</TABLE>
Notes to Consolidated Financial Statements
- ------------------------------------------
(1) Summary of Significant Accounting Policies
------------------------------------------
The Company is engaged in the generation, transmission,
distribution and sale of electric energy in the Washington, D.C.
metropolitan area. The Company's retail service territory
includes all of the District of Columbia and major portions of
Montgomery and Prince George's counties in suburban Maryland.
Potomac Capital Investment Corporation (PCI), a wholly owned
subsidiary of the Company, was formed in 1983 to provide a
permanent vehicle for the conduct of the Company's ongoing
nonutility investment programs. PCI's principal investments have
been in aircraft and power generation equipment, equipment
leasing and marketable securities, primarily preferred stock with
mandatory redemption features. PCI also has investments in real
estate properties in the Washington, D.C. metropolitan area.
The Company's utility operations are regulated by the
Maryland and District of Columbia public service commissions and
its wholesale business by the Federal Energy Regulatory
Commission (FERC). The Company complies with the Uniform System
of Accounts prescribed by the FERC and adopted by the Maryland
and District of Columbia regulatory commissions. Based upon the
regulatory framework in which it operates, the Company currently
applies the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71 entitled "Accounting for the Effects of
Certain Types of Regulation" in accounting for certain deferred
charges and credits to be recognized in future customer billings
pursuant to regulatory authorization: deferred income taxes,
unamortized conservation costs and unamortized debt reacquisition
costs.
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenue and expenses during the reporting
period. Actual results could differ from those estimates and
assumptions.
Certain prior year amounts have been reclassified to conform
to the current year presentation.
A description of significant accounting policies follows.
35
Principles of Consolidation
- ---------------------------
The consolidated financial statements combine the financial
results of the Company and all majority-owned subsidiaries. The
Company's principal subsidiary is PCI. All material intercompany
balances and transactions have been eliminated.
Total Revenue
- -------------
Revenue is accrued for service rendered but unbilled as of the
end of each month. The Company includes in revenue the amounts
received for sales to other utilities related to pooling and
interconnection agreements. Amounts received for such
interchange deliveries are a component of the Company's fuel
rates.
In each jurisdiction, the Company's rate schedules include
fuel rates. The fuel rate provisions are designed to provide for
separately stated fuel billings which cover applicable net fuel
and interchange costs, purchased capacity in the District of
Columbia, and emission allowance costs in the Company's retail
jurisdictions, or changes in the applicable costs from levels
incorporated in base rates. Differences between applicable net
costs incurred and fuel rate revenue billed in any given period
are accounted for as other current assets or other current
liabilities in those cases where specific provision has been made
by the appropriate regulatory commission for the resolution of
such differences within one year. Where no such provision has
been made, the differences are accounted for as other deferred
charges or other deferred credits pending regulatory
determination.
In the District of Columbia, pre-July 1993 conservation
costs receive rate base treatment. Conservation expenditures for
the period July 1993 to December 1994 are recovered through a
surcharge mechanism which initially became effective July 11,
1995, and which will be updated annually on June 1 to recover
1995 and subsequent conservation expenditures, including a
capital cost recovery factor, which is a mechanism that enables
the Company to earn a return on certain costs, principally
unamortized demand side management (DSM) costs not in rate base.
A procedure has been established to consider lost revenue without
the need for base rate proceedings. In Maryland, conservation
costs are recovered through a surcharge rate which reflects
amortization of program costs including costs in the year during
which the surcharge commences, a capital cost recovery factor,
incentives, applicable taxes and estimated lost revenue. The
surcharge is established annually in a collaborative process with
the recovery of lost revenue subject to an earnings test
performed on a quarterly basis.
36
Leasing Transactions
- --------------------
Income from PCI investments in direct finance and leveraged lease
transactions, in which PCI is an equity participant, is reported
using the financing method. In accordance with the financing
method, investments in leased property are recorded as a
receivable from the lessee to be recovered through the collection
of future rentals. For direct finance leases, unearned income is
amortized to income over the lease term at a constant rate of
return on the net investment. Income, including investment tax
credits on leveraged equipment leases, is recognized over the
life of the lease at a level rate of return on the positive net
investment.
PCI investments in equipment under operating leases are
stated at cost less accumulated depreciation, except that assets
held for disposal are carried at estimated fair value less
estimated costs to sell. Depreciation is recorded on a straight
line basis over the equipment's estimated useful life. No
depreciation is taken on assets held for disposal.
Property and Plant
- ------------------
The cost of additions to, and replacements or betterments of,
retirement units of property and plant is capitalized. Such cost
includes material, labor, the capitalization of an Allowance for
Funds Used During Construction (AFUDC) and applicable indirect
costs, including engineering, supervision, payroll taxes and
employee benefits. The original cost of depreciable units of
plant retired, together with the cost of removal, net of salvage,
is charged to accumulated depreciation. Routine repairs and
maintenance are charged to operating expenses as incurred.
The Company uses separate depreciation rates for each
electric plant account. The rates, which vary from jurisdiction
to jurisdiction, were equivalent to a system-wide composite
depreciation rate of approximately 3.1% for 1995, 1994 and 1993.
Conservation
- ------------
In general, the Company accounts for conservation expenditures in
connection with its DSM program as a deferred charge, and
amortizes the costs over five years in Maryland and 10 years in
the District of Columbia. At December 31, 1995, unamortized
conservation costs totaled $105.5 million in Maryland and $124.9
million in the District of Columbia.
37
Allowance for Funds Used During Construction
- --------------------------------------------
In general, the Company capitalizes AFUDC with respect to
investments in Construction Work in Progress with the exception
of expenditures required to comply with federal, state or local
environmental regulations (pollution control projects), which are
included in rate base without capitalization of AFUDC. The
Company accrues a capital cost recovery factor on the retail
jurisdictional portion of certain pollution control projects
related to compliance with the Clean Air Act (CAA). The base for
calculating this return is the amount by which the retail
jurisdictional CAA expenditure balance exceeds the CAA balance
included in rate base in the Company's most recently completed
base rate proceeding.
The jurisdictional AFUDC capitalization rates are determined
as prescribed by the FERC. The effective capitalization rates
were approximately 7.9% in 1995, 7.6% in 1994 and 8.7% in 1993,
compounded semiannually.
Amortization of Debt Issuance and Reacquisition Costs
- -----------------------------------------------------
The Company defers and amortizes expenses incurred in connection
with the issuance of long-term debt, including premiums and
discounts associated with such debt, over the lives of the
respective issues. Costs associated with the reacquisition of
debt are also deferred and amortized over the lives of the new
issues.
New Accounting Standard
- -----------------------
In March 1995, the Financial Accounting Standards Board issued
SFAS No. 121 entitled "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of" which
will become effective for the Company's 1996 consolidated
financial statements. This statement requires the Company to
review long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an
asset may not be recovered. In addition, regulated companies are
required to write-off regulatory assets whenever those assets no
longer are probable of recovery from customers through future
rates. The Company does not expect implementation of this
pronouncement to have a material impact on its consolidated
financial statements.
38
Nonutility Subsidiary Receivables
- ---------------------------------
PCI, the Company's nonutility subsidiary, continuously monitors
its receivables and establishes an allowance for doubtful
accounts against its notes receivable, when deemed appropriate,
on a specific identification basis. The direct write-off method
is used when trade receivables are deemed uncollectible.
(2) Total Revenue
-------------
The Company's retail service area includes all of the District of
Columbia and major portions of Montgomery and Prince George's
counties in suburban Maryland. The Company supplies electricity,
at wholesale, under a contract with Southern Maryland Electric
Cooperative, Inc. (SMECO), and also delivers economy energy to
the Pennsylvania-New Jersey-Maryland Interconnection Association
(PJM) of which the Company is a member. PJM is composed of 11
electric utilities which operate on a fully integrated basis.
Total revenue for each year was comprised as shown below.
- -----------------------------------------------------------------
1995 1994 1993
-------------------------------------------------
Amount % Amount % Amount %
- -----------------------------------------------------------------
(Thousands of Dollars)
Residential $ 543,532 30.0 $ 524,738 29.5 $ 505,173 29.8
Commercial 848,892 46.8 834,323 46.8 791,357 46.6
U.S. Government 252,144 13.9 254,030 14.2 238,192 14.0
D.C. Government 52,105 2.9 56,655 3.2 53,551 3.2
Wholesale 117,117 6.4 113,318 6.3 108,162 6.4
---------- ----- --------- ----- ---------- -----
Sales of
electricity 1,813,790 100.0 1,783,064 100.0 1,696,435 100.0
===== ===== =====
Other electric
revenue 8,642 7,536 6,007
---------- ---------- ----------
Operating
revenue 1,822,432 1,790,600 1,702,442
Interchange
deliveries 53,670 32,474 22,763
---------- ---------- ----------
Total Revenue $1,876,102 $1,823,074 $1,725,205
========== ========== ==========
- -----------------------------------------------------------------
39
Sales of electricity include base rate revenue and fuel rate
revenue. Fuel rate revenue was $526.6 million in 1995, $557.4
million in 1994 and $487.9 million in 1993.
The Company's Maryland fuel rate is based on historical net
fuel, interchange and emission allowance costs. The zero-based
rate may not be changed without prior approval of the Maryland
Public Service Commission. Application to the Commission for an
increase in the rate may only be made when the currently
calculated fuel rate, based on the most recent actual net fuel,
interchange and emission allowance costs, exceeds the currently
effective fuel rate by more than 5%. If the currently calculated
fuel rate is more than 5% below the currently effective fuel
rate, the Company must apply to the Commission for a fuel rate
reduction.
The District of Columbia fuel rate is based upon an average
of historical and projected net fuel, interchange and emission
allowance costs and purchased capacity, and is adjusted monthly
to reflect changes in such costs.
Rates for service, at wholesale, to SMECO include a fuel
adjustment charge based upon estimated applicable fuel and
interchange costs for each billing month. The difference between
the estimated costs and the actual applicable fuel and
interchange costs incurred each month is reflected as an
adjustment to the fuel rate in the succeeding month.
Amounts received for interchange deliveries are a component
of the Company's fuel rates.
(3) Pensions and Other Postretirement and Postemployment
Benefits
----------------------------------------------------
The Company's General Retirement Program (Program), a
noncontributory defined benefit program, covers substantially all
full-time employees of the Company and its subsidiaries. The
Program provides for benefits to be paid to eligible employees at
retirement based primarily upon years of service with the Company
and their compensation rates for the three years preceding
retirement. Annual provisions for accrued pension cost are based
upon independent actuarial valuations. The Company's policy is
to fund accrued pension costs.
40
Pension expense included in net income was $13.9 million in
1995, $14.3 million in 1994 and $13.7 million in 1993. The net
periodic pension cost was computed as follows.
- -----------------------------------------------------------------
1995 1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Service cost-benefits earned $ 9,900 $10,800 $10,300
Interest cost on projected
benefit obligation 28,400 26,800 25,100
Actual return on Program assets (51,900) (4,600) (24,300)
Differences between actual
and expected return on
Program assets and net
amortization 27,500 (18,700) 2,600
------- ------- -------
Pension cost $13,900 $14,300 $13,700
======= ======= =======
- -----------------------------------------------------------------
41
Program assets are stated at fair value and were comprised
of approximately 60% and 70% of cash equivalents and fixed income
investments and the balance in equity investments at December 31,
1995 and 1994, respectively. The following table sets forth the
Program's funded status and amounts recognized on the
Consolidated Balance Sheets.
- -----------------------------------------------------------------
1995 1994
- -----------------------------------------------------------------
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Program benefits:
Vested benefits $(295,700) $(252,300)
Nonvested benefits (44,000) (30,000)
--------- ---------
Accumulated benefit obligation $(339,700) $(282,300)
========= =========
Actuarial present value of projected
benefit obligation $(399,400) $(338,600)
Program assets at fair value 360,500 289,100
--------- ---------
Projected benefit obligation in excess of
Program assets (38,900) (49,500)
Unrecognized actuarial loss 55,600 35,600
Unrecognized prior service cost 16,300 17,600
Unrecognized net obligation at
January 1, 1987, being recognized
over 18 years 300 400
--------- ---------
Prepaid pension expense $ 33,300 $ 4,100
========= =========
- -----------------------------------------------------------------
The assumed weighted average discount rate and weighted
average rate of increase in future compensation levels used in
determining the actuarial present value of the projected benefit
obligation were 7.5% and 4% in 1995 and 8.5% and 4.5% in 1994,
respectively. The assumed long-term rate of return on Program
assets was 9% in 1995 and 1994.
In addition to providing pension benefits, the Company
provides certain health care and life insurance benefits for
retired employees and inactive employees covered by disability
plans. The health care plan pays stated percentages of most
necessary medical expenses incurred by these employees, after
subtracting payments by Medicare or other providers and after a
stated deductible has been met. The life insurance plan pays
benefits based on base salary at the time of retirement and age
at the date of death. Participants become eligible for the
42
benefits of these plans if they retire under the provisions of
the Company's General Retirement Program with 10 years of service
or become inactive employees under the Company's disability
plans. The Company is amortizing the unrecognized transition
obligation measured at January 1, 1993 over a 20-year period.
Postretirement benefit expense included in net income was $9
million, $8.7 million and $9.3 million in 1995, 1994 and 1993,
respectively. The following table sets forth the components of
the postretirement expense.
- -----------------------------------------------------------------
1995 1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Service cost-benefits attributable
to service during the year $ 2,300 $ 2,600 $ 2,500
Interest cost on accumulated
postretirement benefit obligation 4,500 4,200 4,400
Actual (return) loss on plan assets (1,900) 200 (400)
Amortization of transition
obligation 2,100 2,500 2,800
Difference between actual and
expected return on plan assets
and net amortization 2,000 (800) -
------- ------- -------
Net postretirement benefit cost $ 9,000 $ 8,700 $ 9,300
======= ======= =======
- -----------------------------------------------------------------
43
The following table sets forth the accumulated
postretirement benefit obligation reconciled to the amounts
recognized on the Consolidated Balance Sheets.
- -----------------------------------------------------------------
1995 1994
- -----------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation to
Retirees and dependents $(40,100) $(34,600)
Active employees fully eligible (9,300) (10,600)
Active employees not fully
eligible (15,200) (14,800)
-------- --------
Total accumulated postretirement
benefit obligation (64,600) (60,000)
Plan assets at fair value 7,800 4,500
-------- --------
Accumulated postretirement benefit
obligation in excess of plan assets (56,800) (55,500)
Unrecognized transition obligation 35,800 45,200
Unrecognized actuarial loss 23,100 11,100
-------- --------
Prepaid postretirement benefit
cost $ 2,100 $ 800
======== ========
- -----------------------------------------------------------------
The Company's obligation at December 31, 1995 and 1994 was
based on discount rates of 7.5% and 8.5%, respectively, and
weighted average rates of increase in future compensation levels
of 4% and 4.5%, respectively. The assumed health-care cost trend
rate is 7.5% which declines to 5.5% after a four year period. A
one percentage point increase in the health-care cost trend rate
would increase the Accumulated Postretirement Benefit Obligation
by $3.1 million to approximately $67.7 million and the sum of the
service cost and interest cost for 1995 by approximately $.4
million.
In January 1995 and 1994, the Company funded the 1995 and
1994 portions of its estimated liability for postretirement
medical and life insurance costs through the use of an Internal
Revenue Code (IRC) 401 (h) account, within the Company's pension
plan, and an IRC 501 (c)(9) Voluntary Employee Beneficiary
Association (VEBA). The Company plans to fund the 401(h) account
and the VEBA annually. In January 1996, the 1996 portion of the
Company's estimated liability will be funded. Assets were
comprised of cash equivalents, fixed income investments and
equity investments and the assumed return on plan assets was 9%
in 1995 and 1994.
44
<TABLE>
(4) Income Taxes
------------
The provision for income taxes, reconciliation of consolidated income tax expense
and components of consolidated deferred tax liabilities (assets) are set forth below.
<CAPTION>
Provisions for Income Taxes
- ---------------------------
- ---------------------------------------------------------------------------------------------------
1995 1994 1993
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility current tax expense
Federal $ 68,492 $ 63,395 $ 69,007
State and local 9,173 8,612 9,801
--------- --------- ---------
Total utility current tax expense 77,665 72,007 78,808
--------- --------- ---------
Utility deferred tax expense
Federal 48,339 42,070 26,784
State and local 7,084 6,221 5,100
Investment tax credits (3,649) (3,650) (3,469)
--------- --------- ---------
Total utility deferred tax expense 51,774 44,641 28,415
--------- --------- ---------
Total utility income tax expense 129,439 116,648 107,223
--------- --------- ---------
Nonutility subsidiary current tax expense
Federal (35,592) (29,315) (13,022)
--------- --------- ---------
Nonutility subsidiary deferred tax expense
Federal (50,116) 6,758 (31,360)
State and local - (138) (696)
--------- --------- ---------
Total nonutility subsidiary deferred tax expense (50,116) 6,620 (32,056)
--------- --------- ---------
Total nonutility subsidiary income tax expense (85,708) (22,695) (45,078)
--------- --------- ---------
Total consolidated income tax expense 43,731 93,953 62,145
Income taxes included in other income (84,729) (25,906) (48,031)
--------- --------- ---------
Income taxes included in utility operating expenses $ 128,460 $ 119,859 $ 110,176
========= ========= =========
45
</TABLE>
<TABLE>
<CAPTION>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
- ---------------------------------------------------------------------------------------------------
1995 1994 1993
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Income before income taxes $ 138,122 $ 321,115 $ 303,724
========= ========= =========
Utility income tax at federal statutory rate $ 121,879 $ 113,653 $ 113,295
Increases (decreases) resulting from
Depreciation 9,173 8,022 5,096
Removal costs (7,204) (4,086) (4,385)
Allowance for funds used during construction 595 (2,411) (3,852)
Other (1,613) (4,175) (6,477)
State income taxes, net of federal effect 10,648 9,683 9,686
Tax credits (4,039) (4,038) (3,873)
Cumulative effect of tax rate change - - (2,267)
--------- --------- ---------
Total utility income tax expense 129,439 116,648 107,223
--------- --------- ---------
Nonutility subsidiary income tax at federal statutory rate (73,537) (1,262) (6,992)
Increases (decreases) resulting from
Dividends received deduction (8,524) (8,487) (7,672)
Reversal of previously accrued deferred taxes - (8,206) (35,904)
Other (3,647) (4,602) (408)
State income taxes, net of federal effect - (138) (696)
Cumulative effect of tax rate change - - 6,594
--------- --------- ---------
Total nonutility subsidiary income tax expense (85,708) (22,695) (45,078)
--------- --------- ---------
Total consolidated income tax expense 43,731 93,953 62,145
Income taxes included in other income (84,729) (25,906) (48,031)
--------- --------- ---------
Income taxes included in utility operating expenses $ 128,460 $ 119,859 $ 110,176
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
At December 31,
----------------------
1995 1994
----------------------
(Thousands of Dollars)
<S> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax basis differences $ 773,323 $ 723,248
Rapid amortization of certified pollution control
facilities 26,640 29,018
Deferred taxes on amounts to be collected through
future rates 92,472 95,465
Property taxes 11,808 11,212
Deferred fuel (7,154) 177
Prepayment premium on debt retirement 22,080 21,537
Deferred investment tax credit (24,464) (25,922)
Contributions in aid of construction (27,206) (24,954)
Contributions to pension plan 10,859 -
Other 25,124 25,454
--------- ---------
Total utility deferred tax liabilities (net) 903,482 855,235
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 10,938 6,779
--------- ---------
Total utility deferred tax liabilities (net) - noncurrent $ 892,544 $ 848,456
========= =========
Nonutility subsidiary deferred tax liabilities (assets)
Finance leases $ 149,103 134,925
Operating leases 66,802 117,782
Reversal of previously accrued taxes related
to partnerships (11,593) (16,385)
Alternative minimum tax (84,512) (77,167)
Other (16,840) (24,477)
--------- ---------
Total nonutility subsidiary deferred tax liabilities (net),
(included in Deferred taxes and other) $ 102,960 $ 134,678
========= =========
46
</TABLE>
The utility net deferred tax liability represents the tax
effect, at presently enacted tax rates, of temporary differences
between the financial statement and tax bases of assets and
liabilities. The portion of the utility net deferred tax
liability applicable to utility operations, which has not been
reflected in current service rates, represents income taxes
recoverable through future rates, net and is recorded as a
Deferred Charge on the balance sheet. No valuation allowance for
deferred tax assets was required or recorded at December 31, 1995
and 1994.
The Tax Reform Act of 1986 repealed the Investment Tax
Credit (ITC) for property placed in service after December 31,
1985, except for certain transition property. ITC previously
earned on utility property continues to be normalized over the
remaining service lives of the related assets.
The Company and its subsidiaries file a consolidated federal
income tax return. The Company's federal income tax liabilities
for all years through 1991 have been finally determined. The
Company is of the opinion that the final settlement of its
federal income tax liabilities for subsequent years will not have
a material adverse effect on its financial position.
47
(5) Other Taxes
-----------
Taxes, other than income taxes, charged to utility operating
expenses for each period are shown below.
- ----------------------------------------------------------------
1995 1994 1993
- ----------------------------------------------------------------
(Thousands of Dollars)
Gross receipts $ 95,158 $ 93,549 $ 88,044
Property 64,991 60,443 58,193
Payroll 11,269 11,063 10,534
County fuel-energy 21,887 30,842 34,614
Environmental, use and
other 9,403 10,183 9,867
-------- -------- --------
$202,708 $206,080 $201,252
======== ======== ========
- -----------------------------------------------------------------
48
(6) Jointly Owned Generating Facilities
-----------------------------------
The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located near Johnstown, Pennsylvania,
consisting of two baseload units totaling 1,700 megawatts. The
Company and other utilities own the station as tenants in common
and share costs and output in proportion to their ownership
shares. Each owner has arranged its own financing relating to
its share of the facility. The Company's share of the operating
expenses of the station is included in the Consolidated
Statements of Earnings. The Company's investment in the
Conemaugh facility of $85.7 million at December 31, 1995 and
$81.1 million at December 31, 1994, includes $1.3 million and
$9.5 million of Construction Work in Progress, respectively.
49
<TABLE>
(7) Common Equity
Changes in common stock, premium on stock and retained income are summarized
below.
<CAPTION>
- ---------------------------------------------------------------------------------------
Common Stock Premium Retained
Shares Par Value on Stock Income
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance, December 31, 1992 114,296,443 $ 114,296 $ 919,089 $ 802,774
Net income before net earnings
from nonutility subsidiary - - - 216,478
Nonutility subsidiary:
Net earnings - - - 25,101
Marketable equity securities
valuation allowance, net of tax - - - 1,172
Dividends:
Preferred stock - - - (16,255)
Common stock - - - (189,837)
Conversion of convertible
debentures 3,480 4 93 -
Conversion of preferred stock 5,534 6 42 -
Loss on acquisition of preferred
stock - - (24) -
Other capital contributions - - 69 -
Sale of common stock through
Shareholder Dividend
Reinvestment Plan 1,638,227 1,638 42,655 -
Issuance of common stock to
Employee Savings Plans 362,468 362 9,277 -
Sale of common stock through
public offerings 1,491,500 1,492 40,577 -
----------- ---------- ---------- ----------
Balance, December 31, 1993 117,797,652 117,798 1,011,778 839,433
Net income before net earnings
from nonutility subsidiary - - - 208,074
Nonutility subsidiary:
Net earnings - - - 19,088
Marketable securities net
unrealized loss, net of tax - - - (23,879)
Dividends:
Preferred stock - - - (16,437)
Common stock - - - (195,755)
Conversion of preferred stock 3,845 4 29 -
Gain on acquisition of preferred
stock - - 109 -
Other capital reductions - - (66) -
Sale of common stock through
Shareholder Dividend
Reinvestment Plan 355,198 355 6,603 -
Issuance of common stock to
Employee Savings Plans 91,408 91 2,236 -
----------- ---------- ---------- ----------
Balance, December 31, 1994 118,248,103 118,248 1,020,689 830,524
Net income before net loss
from nonutility subsidiary - - - 218,788
Nonutility subsidiary:
Net loss - - - (124,397)
Marketable securities net
unrealized gain, net of tax - - - 30,701
Dividends:
Preferred stock - - - (16,851)
Common stock - - - (196,469)
Conversion of preferred stock 9,730 10 74 -
Gain on acquisition of preferred
stock - - 5 -
Other capital reductions - - (23) -
Sale of common stock through
Shareholder Dividend
Reinvestment Plan 158,501 159 2,881 -
Issuance of common stock to
Employee Savings Plans 78,243 78 1,462 -
----------- ---------- ---------- ----------
Balance, December 31, 1995 118,494,577 $ 118,495 $1,025,088 $ 742,296
=========== ========== ========== ==========
50
</TABLE>
The Company's Shareholder Dividend Reinvestment Plan (DRP)
provides that shares of common stock purchased through the plan
may be original issue shares or, at the option of the Company,
shares purchased in the open market. The DRP permits additional
cash investments by plan participants limited to one investment
per month of not less than $25 and not more than $5,000.
As of December 31, 1995, 39,139 shares of common stock were
reserved for issuance upon the conversion of convertible
preferred stock, 2,771,633 and 3,392,500 shares were reserved for
conversion of the 7% and 5% convertible debentures, respectively,
2,324,721 shares were reserved for issuance under the DRP and
1,221,624 shares were reserved for issuance under the Employee
Savings Plans. Under the Stock Option Agreement with Baltimore
Gas and Electric Company, 23,579,900 shares could become
issuable, contingent upon specific events associated with
termination of the Merger Agreement. See Note (13) Commitments
and Contingencies for additional information.
Certain provisions of the Company's corporate charter,
relating to preferred and preference stock, would impose
restrictions on the payment of dividends under certain
circumstances. No portion of retained income was so restricted
at December 31, 1995.
51
(8) Serial Preferred Stock
----------------------
The Company has authorized 11,126,222 shares of cumulative $50
par value Serial Preferred Stock. At December 31, 1995 and 1994,
there were outstanding 5,376,202 shares and 5,379,433 shares,
respectively. The various series of Serial Preferred Stock
outstanding (excluding 2,869,696 shares of Redeemable Serial
Preferred Stock - See Note 9) and the per share redemption price
at which each series may be called by the Company are as follows.
- -----------------------------------------------------------------
Redemption December 31,
Price 1995 1994
- -----------------------------------------------------------------
(Thousands of
Dollars)
$2.44 Series of 1957, 300,000 shares $51.00 $15,000 $15,000
$2.46 Series of 1958, 300,000 shares $51.00 15,000 15,000
$2.28 Series of 1965, 400,000 shares $51.00 20,000 20,000
$3.82 Series of 1969, 500,000 shares $51.00 25,000 25,000
$2.44 Convertible Series of 1966,
6,506 and 8,182 shares,
respectively $50.00 325 409
Auction Series A, 1,000,000 shares $50.00 50,000 50,000
-------- --------
$125,325 $125,409
======== ========
- -----------------------------------------------------------------
The $2.44 Convertible Series of 1966 is convertible into
common stock of the Company at a price based upon a formula that
is subject to adjustment in certain events. At December 31,
1995, 5.88 shares of common stock could be obtained upon the
conversion of each share of convertible preferred stock at the
then effective conversion price of $8.51 per share of common
stock. The number of shares of this series converted into common
stock was 1,676 shares in 1995, 656 shares in 1994 and 948 shares
in 1993.
Dividends on the Serial Preferred Stock, Auction Series A,
are cumulative and are based on the rate determined by auction
procedures prior to each dividend period. The maximum rate can
range from 110% to 200% of the applicable "AA" Composite
Commercial Paper Rate. The annual dividend rate is 4.335%
($2.1675) for the period December 1, 1995 through February 29,
1996. The average annual dividend rates were 4.638% ($2.319) in
1995 and 3.55% ($1.775) in 1994.
52
(9) Redeemable Serial Preferred Stock
---------------------------------
The outstanding series of $50 par value Redeemable Serial
Preferred Stock are shown below.
- -----------------------------------------------------------------
December 31,
1995 1994
- -----------------------------------------------------------------
(Thousands of Dollars)
$3.37 Series of 1987, 869,696 and
871,251 shares, respectively $ 43,485 $ 43,563
$3.89 Series of 1991, 1,000,000 shares 50,000 50,000
$3.40 Series of 1992, 1,000,000 shares 50,000 50,000
-------- --------
$143,485 $143,563
======== ========
- ----------------------------------------------------------------
The shares of the $3.37 (6.74%) Series are subject to
mandatory redemption, at par, through the operation of a sinking
fund. Beginning June 1993, not less than 30,000 nor more than
60,000 shares will be redeemed annually. The option to redeem in
excess of 30,000 shares annually is not cumulative; however,
shares which are acquired or redeemed by the Company other than
through the operation of the sinking fund may, at the option of
the Company, be applied toward the satisfaction of sinking fund
requirements. Presently, the shares are callable for redemption
at a per share price of $52.25, which is reduced in succeeding
years, equaling par value beginning June 1, 2002.
The shares of the $3.89 (7.78%) Series are subject to
mandatory redemption, at par, through the operation of a sinking
fund which will redeem not less than 165,000 nor more than
330,000 shares annually, beginning June 1, 2001 and 175,000
shares on June 1, 2006. The option to redeem in excess of
165,000 shares annually is not cumulative. The shares may be
called for redemption at any time at a per share price of $53.89;
however, the shares are not redeemable prior to June 1, 1996,
through certain refunding operations. The redemption price is
reduced in succeeding years, equaling $50.98 beginning June 1,
2003.
53
The shares of the $3.40 (6.80%) Series are subject to
mandatory redemption, at par, through the operation of a sinking
fund which will redeem 50,000 shares annually, beginning
September 1, 2002 with the remaining shares redeemed on September
1, 2007. The shares are not redeemable prior to September 1,
2002; thereafter, the shares are redeemable at par.
In the event of default with respect to dividends, or
sinking fund or other redemption requirements relating to the
serial preferred stock, no dividends may be paid, nor any other
distribution made, on common stock. Payments of dividends on all
series of serial preferred or preference stock, including series
which are redeemable, must be made concurrently.
The sinking fund requirements through 2000 with respect to
the Redeemable Serial Preferred Stock are $1 million in 1997 and
$1.5 million annually thereafter.
54
<TABLE>
(10) Long-Term Debt
<CAPTION>
Details of long-term debt are shown below.
- ------------------------------------------------------------------------------------------------------
Interest December 31,
Rate Maturity 1995 1994
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
First Mortgage Bonds
Fixed Rate Series:
5% December 15, 1995 $ - $ 40,000
5-5/8% December 31, 1997 - 16,000
4-3/8% February 15, 1998 50,000 50,000
4-1/2% May 15, 1999 45,000 45,000
9% April 15, 2000 100,000 100,000
5-1/8% April 1, 2001 15,000 15,000
5-7/8% May 1, 2002 35,000 35,000
6-5/8% February 15, 2003 40,000 40,000
5-5/8% October 15, 2003 50,000 50,000
6-1/2% September 15, 2005 100,000 -
6-1/2% March 15, 2008 78,000 78,000
5-7/8% October 15, 2008 50,000 50,000
5-3/4% March 15, 2010 16,000 -
8-5/8% August 15, 2019 - 59,800
9% June 1, 2021 100,000 100,000
6% September 1, 2022 30,000 30,000
6-3/8% January 15, 2023 37,000 37,000
7-1/4% July 1, 2023 100,000 100,000
6-7/8% September 1, 2023 100,000 100,000
5-3/8% February 15, 2024 42,500 42,500
5-3/8% February 15, 2024 38,300 38,300
6-7/8% October 15, 2024 75,000 75,000
7-3/8% September 15, 2025 75,000 -
8-1/2% May 15, 2027 75,000 75,000
7-1/2% March 15, 2028 40,000 40,000
Variable Rate Series:
Adjustable rate December 1, 2001 50,000 50,000
---------- ----------
Total First Mortgage Bonds 1,341,800 1,266,600
Convertible Debentures
5% September 1, 2002 115,000 115,000
7% January 15, 2018 66,747 68,412
Medium-Term Notes
6.25% May 28, 1996 25,000 25,000
6.66% to 6.73% May 1997 100,000 100,000
9.08% July and August 1997 50,000 50,000
7.46% to 7.60% January 2002 40,000 40,000
7.64% January 17, 2007 35,000 35,000
6.25% January 20, 2009 50,000 50,000
7% January 15, 2024 50,000 50,000
---------- ----------
Total Utility Long-Term Debt 1,873,547 1,800,012
Net unamortized discount (30,190) (31,168)
Current portion (26,280) (45,445)
---------- ----------
Net Utility Long-Term Debt $1,817,077 $1,723,399
========== ==========
Nonutility Subsidiary Long-term Debt
Varying rates through 2011 $1,047,484 $1,140,505
========== ==========
55
</TABLE>
Utility Long-Term Debt
- ----------------------
The outstanding First Mortgage Bonds (bonds) are secured by a
lien on substantially all of the Company's property and plant.
Additional bonds may be issued under the mortgage as amended and
supplemented in compliance with the provisions of the indenture.
During 1995, the Company issued $100 million of 6-1/2% First
Mortgage Bonds, $75 million of 7-3/8% First Mortgage Bonds and
$16 million of 5-3/4% First Mortgage Bonds with various
maturities. A portion of the proceeds from these financings was
used to redeem $75.8 million of higher cost or shorter maturity
First Mortgage Bonds, to satisfy current long-term debt
maturities of $40 million and to refund short-term debt.
The interest rate on the $50 million Adjustable Rate series
First Mortgage Bonds is adjusted annually on December 1, based
upon 116% of the 10-year "constant maturity" United States
Treasury bond rate for the preceding three-month period ended
October 31. Effective December 1, 1995, the applicable interest
rate is 7.443%. The applicable interest rate was 8.68% at
December 1, 1994 and 6.657% at December 1, 1993.
The 7% Convertible Debentures are convertible into shares of
common stock at a conversion price of $27 per share.
The 5% Convertible Debentures are convertible into shares of
common stock at a conversion rate of 29-1/2 shares for each
$1,000 principal amount.
The aggregate amounts of maturities for the Company's long-
term debt outstanding at December 31, 1995 are $26.3 million in
1996, $150 million in 1997, $50 million in 1998, $45 million in
1999 and $100 million in 2000.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at December 31, 1995 consisted of $981.3 million
of recourse debt from institutional lenders maturing at various
dates between 1996 and 2003. The interest rates of such
borrowings ranged from 5% to 10.1%. The weighted average
interest rate was 7.66% at December 31, 1995, 7.47% at December
31, 1994 and 7.45% at December 31, 1993. Annual aggregate
principal repayments are $230.5 million in 1996, $169.5 million
in 1997, $251.3 million in 1998, $140.5 million in 1999, $93
million in 2000 and $96.5 million thereafter.
56
Long-term debt also includes $66.2 million of non-recourse
debt, $42.6 million of which was secured by aircraft currently
under operating lease. The debt is payable in monthly
installments at rates of LIBOR (London Interbank Offered Rate)
plus 1.25% and LIBOR plus 1.375% with final maturity on March 15,
2002. Non-recourse debt of $23.6 million is related to PCI's
majority-owned real estate partnerships of which $15.4 million is
due in consecutive monthly installments with maturity on May 11,
2001, based on a 30-year amortization period at a fixed rate of
interest of 9.05%. The remaining non-recourse real estate debt
consists of $8.2 million payable in monthly installments at a
fixed rate of interest of 9.66% with final maturity on October 1,
2011.
57
<TABLE>
(11) Fair Value of Financial Instruments
- ----------------------------------------
The estimated fair values of the Company's financial instruments at December 31, 1995,
and 1994 are shown below.
<CAPTION>
- ------------------------------------------------------------------------------------------------
December 31,
1995 1994
- ------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Utility
Capitalization and Liabilities
Serial preferred stock $ 125,325 114,590 125,409 102,102
Redeemable serial
preferred stock $ 143,485 145,046 143,563 134,008
Long-term debt
First Mortgage Bonds $1,326,560 1,385,609 1,208,076 1,093,208
Medium-Term Notes $ 323,007 336,351 347,712 324,223
Convertible Debentures $ 167,510 174,054 167,611 146,098
Nonutility Subsidiary
Assets
Marketable securities $ 530,323 530,323 473,608 473,608
Notes receivable $ 62,175 63,184 61,278 58,616
Liabilities
Long-term debt $1,047,484 1,071,354 1,140,505 1,122,638
- ------------------------------------------------------------------------------------------------
58
</TABLE>
The methods and assumptions below were used to estimate, at
December 31, 1995 and 1994, the fair value of each class of
financial instruments shown above for which it is practicable to
estimate that value.
The fair value of the Company's long-term debt, which
includes First Mortgage Bonds, Medium-Term Notes and Convertible
Debentures, excluding amounts due within one year, was based on
the current market price, or for issues with no market price
available, was based on discounted cash flows using current rates
for similar issues with similar terms and remaining maturities.
The fair value of the Company's Serial Preferred Stock,
including Redeemable Serial Preferred Stock was based on quoted
market prices or discounted cash flows using current rates of
preferred stock with similar terms.
The fair value of PCI's Marketable Securities was based on
quoted market prices.
The fair value of PCI's Notes Receivable was based on
discounted future cash flows using current rates and similar
terms.
The fair value of PCI's long-term debt, including non-
recourse debt, was based on current rates offered to similar
companies for debt with similar remaining maturities.
The carrying amounts of all other financial instruments
approximate fair value.
(12) Short-Term Debt
---------------
The Company's short-term financing requirements have been
satisfied principally through the sale of commercial promissory
notes. Interest rates for the Company's short-term financing
during the year ranged from 5.7% to 6.1%.
The Company maintains a minimum 100% line of credit back-up
for its outstanding commercial promissory notes, which was unused
during 1995, 1994 and 1993.
59
Nonutility Subsidiary Short-Term Notes Payable
- ----------------------------------------------
The nonutility subsidiary's short-term financing requirements
have been satisfied principally through the sale of commercial
promissory notes.
The nonutility subsidiary maintains a minimum 100% line of
credit back-up for its outstanding commercial promissory notes,
which was unused during 1995, 1994 and 1993.
(13) Commitments and Contingencies
-----------------------------
Proposed Merger
- ---------------
On September 22, 1995, the Company entered into an Agreement and
Plan of Merger with Baltimore Gas and Electric Company (BGE).
This Agreement provides for a strategic business combination in
which each company will merge into Constellation Energy
Corporation (Constellation Energy), a newly formed company to
create an integrated, non-holding company structure (the Merger).
Each outstanding share of the Company's common stock will be
converted into the right to receive .997 of a share of common
stock of Constellation Energy and each outstanding share of BGE
common stock will be converted into the right to receive one
share of Constellation Energy's common stock. This transaction
is expected to qualify as a tax-free exchange of shares for the
holders of each company's common stock and as a pooling of
interests for accounting purposes. Constellation Energy will
serve a population of approximately 4.5 million with
approximately 1.8 million electric customers and over 530,000
natural gas customers. It is estimated that savings from the
combined utility systems will approximate $1.3 billion over 10
years, net of costs to achieve. The allocation of the net
savings between customers and shareholders of the Company will be
determined in regulatory proceedings. The Merger requires the
approval of shareholders of each company and certain regulatory
agencies including the Federal Energy Regulatory Commission, the
Public Service Commissions of Maryland and the District of
Columbia and the Nuclear Regulatory Commission. The approval
process is expected to take until the end of the first quarter of
1997 to complete.
If the Merger Agreement is terminated by either the Company
or BGE due to a material breach by the other party, the breaching
party must pay the non-breaching party, as liquidated damages,
$10 million in cash in respect of out-of-pocket expenses. The
Merger Agreement also requires payment of a termination fee of
$75 million in cash, plus $10 million in cash in respect of out-
of-pocket expenses, by one party to the other if the Merger
60
Agreement is terminated under certain circumstances including, if
either the Company or BGE terminates the Merger Agreement after
the Board of Directors of the other party withdraws or adversely
modifies its recommendation of the transaction. The termination
fees payable by the Company under these provisions and the
aggregate amount which could be payable by the Company upon a
required repurchase of an option (or shares of common stock
issued pursuant to the exercise of the option) granted by the
Company to BGE in connection with entry into the Merger Agreement
may not exceed $125 million in the aggregate.
The Company has approved a severance plan for all exempt and
non-bargaining unit employees who lose employment due to the
Merger. Employees who lose employment as a result of the Merger
will receive two weeks of pay per year of service, with a minimum
payment of eight weeks of pay. In addition, employees will
receive company-subsidized health and dental insurance for two
weeks for each year of service, with a minimum of eight weeks of
insurance coverage.
In December 1995, an extension of the current 1993 Labor
Agreement between the Company and Local 1900 of the International
Brotherhood of Electrical Workers was ratified by the Union
members. The 1995 Agreement extends the 1993 Agreement, which
was due to expire on June 1, 1996, for two years or until the
effective date of the Merger with BGE, whichever occurs first.
This Agreement provides severance benefits, previously approved
by the Company for exempt and non-bargaining unit employees, for
all union members and provides for a lump-sum payment of 2% of
base pay on January 5, 1996, a lump-sum payment of 1% of base pay
on June 7, 1996 and a lump-sum payment of 3% of base pay on June
6, 1997 or the effective date of the Merger, whichever occurs
first.
Leases
- ------
The Company leases its general office building and certain data
processing and duplicating equipment, motor vehicles,
communication system and construction equipment under long-term
lease agreements. The lease of the general office building
expires in 2002 and leases of equipment extend for periods of up
to 6 years. Charges under such leases are accounted for as
operating expenses or construction expenditures, as appropriate.
Rents, including property taxes and insurance, net of rental
income from subleases, aggregated approximately $15.6 million in
1995, $14.9 million in 1994 and $13.6 million in 1993. The
approximate annual commitments under all operating leases,
reduced by rentals to be received under subleases are $13.8
million in 1996, $7.7 million in 1997, $6.2 million in 1998, $5.6
million in 1999, $4.6 million in 2000 and a total of $10.8
million in the years thereafter.
61
The Company entered into a sale (at cost) and leaseback
agreement, in December 1994, for its control center system
(system). The system is an integrated energy management system
used by the Company's power dispatchers to centrally control the
operation of the Company's electric system, which consists of all
of its generating units, the transmission system and the
distribution system. The lease of the system is accounted for as
a capital lease, and was recorded at the present value of future
lease payments which totaled $152 million. The lease requires
semi-annual payments of $7.6 million over a 25-year period and
provides for transfer of ownership of the system to the Company
for $1 at the end of the lease term. Under SFAS No. 71, the
amortization of leased assets is modified so that the total of
interest on the obligation and amortization of the leased asset
is equal to the rental expense allowed for ratemaking purposes.
This lease has been treated as an operating lease for ratemaking
purposes.
Fuel Contracts
- --------------
The Company has numerous coal contracts with various expiration
dates through 2003 for aggregate annual deliveries of
approximately 3.2 million tons. Deliveries under these contracts
are expected to provide approximately 48% of the estimated system
coal requirements in 1996. Approximately 52% of the estimated
system coal requirements in 1996 will be purchased under shorter
term agreements and on a spot basis from a variety of suppliers.
Prices under the Company's coal contracts are generally
determined by reference to base amounts adjusted to reflect
provisions for changes in suppliers' costs, which in turn are
determined by reference to published indices and limited by
current market prices.
Capacity Purchase Agreements
- ----------------------------
The Company's long-term capacity purchase agreements with Ohio
Edison and APS commenced June 1, 1987 and are expected to
continue at the 450 megawatt level through 2005. Under the terms
of the agreement with Ohio Edison, the Company is required to
make capacity payments, subject to certain contingencies, which
include a share of Ohio Edison's fixed operating and maintenance
cost. The approximate monthly capacity commitment under this
agreement, excluding an allocation of fixed operating and
maintenance cost, is $18,060 per megawatt through 1998 and
$25,620 per megawatt from 1999 through 2005.
62
The Company began a 25-year purchase agreement in June 1990
with SMECO for 84 megawatts of capacity supplied by a combustion
turbine installed and owned by SMECO at the Company's Chalk Point
Generating Station. The Company is responsible for all costs
associated with operating and maintaining the facility. The
Company is accounting for this agreement as a capital lease,
recorded at fair market value which totaled $37.1 million at the
date construction was complete. The capacity payment to SMECO is
$462,000 per month. Under SFAS No. 71, amortization of leased
assets is modified so that the total of interest on the
obligation and amortization of the leased asset is equal to
rental expense allowed for ratemaking purposes. This agreement
has been treated as an operating lease for ratemaking purposes.
The Company has a 25-year agreement with Panda Energy
Corporation for 230 megawatts of capacity supplied by a gas-
fueled combined-cycle cogenerator which is scheduled for
operation in the fourth quarter of 1996. The agreement currently
requires capacity purchase payments to Panda Energy Corporation
of approximately $1.6 million per month from January 1, 1997
through December 31, 1998. Capacity payments in 1999 and 2000
are approximately $3 million per month and generally increase
thereafter peaking at approximately $4.5 million per month.
Environmental Contingencies
- ---------------------------
The Company is subject to contingencies associated with
environmental matters, principally related to possible
obligations to remove or mitigate the effects on the environment
of the disposal of certain substances at the sites discussed
below.
During 1993, the Company and two other potentially
responsible parties (PRP) completed a removal action at a site in
Harmony, West Virginia pursuant to an Administrative Order (AO)
issued by the U.S. Environmental Protection Agency (EPA).
Approximately $3 million (of which the Company has paid one-
third, subject to possible reallocation) was expended on the
removal action, which the EPA has stated is in compliance with
the AO. The Company and two other PRPs have entered into
settlements with third parties to recover approximately $2.4
million of this cost. EPA oversight costs, which are not
expected to be material, have not yet been assessed. While
compliance with the AO has been completed, the Company cannot
determine whether it will be subject to any future liability with
respect to this site.
In October 1994, a Remedial Investigation/Feasibility Study
(RI/FS) report was submitted to the EPA with respect to a site in
Philadelphia, Pennsylvania. Pursuant to an agreement among the
PRPs, the Company is responsible for 12% of the costs of the
RI/FS. Total costs of the RI/FS and associated activities prior
63
to the issuance of a Record of Decision (ROD) by the EPA,
including legal fees, are currently estimated to be $5.6 million.
The Company has paid $2.5 million as of December 31, 1995. The
report included a number of possible remedies, the estimated
costs of which range from $2 million to $90 million. On July 20,
1995, the EPA announced its proposed remedial action plan for the
site and indicated it will accept comments on the plan from any
interested parties. The EPA's estimate of the costs associated
with implementation of the plan is approximately $17 million.
The Company cannot predict whether the EPA will include the plan
in its ROD as proposed or make changes as a result of comments
received. In addition, the Company cannot estimate the total
extent of the EPA's administrative and oversight costs. To date,
the Company has accrued $1.7 million for its share of this
contingency.
On October 3, 1995, the Company received notice from the EPA
that it, along with several hundred other companies, may be a PRP
in connection with the Spectron Superfund Site located in Elkton,
Maryland. The site was operated as a hazardous waste disposal,
recycling, and processing facility from 1961 to 1988. A group of
PRPs allege, based on records they have collected, that the
Company's share of liability at this site is .0042%. The EPA has
also indicated that a de minimis settlement is likely to be
appropriate for this site. While the outcome of negotiations and
the ultimate liability with respect to this site cannot be
predicted, the Company believes that its liability at this site
will not have a material adverse effect on its financial position
or results of operations.
On December 5, 1995, the Company received notice from the
EPA that it is a PRP under the Comprehensive Environmental
Response Compensation and Liability Act (CERCLA or Superfund)
with respect to the release or threatened release of radioactive
and mixed radioactive and hazardous wastes at a site in Denver,
Colorado operated by RAMP Industries, Inc. A preliminary
investigation by the Company indicates that the Company's
connection to the site arises from an agreement with a vendor to
package, transport and dispose of two laboratory instruments
containing small amounts of radioactive material at a Nevada
facility. While the Company cannot predict its liability at this
site, the Company believes that it will not have a material
adverse effect on its financial position or results of
operations.
Litigation
- ----------
During 1993, the Company was served with Amended Complaints filed
in three jurisdictions (Prince George's County, Baltimore City,
and Baltimore County), in separate ongoing, consolidated
proceedings each denominated "In re: Personal Injury Asbestos
Case." The Company (and other defendants) were brought into
64
these cases on a theory of premises liability under which
plaintiffs argue that the Company was negligent in not providing
a safe work environment for employees of its contractors who
allegedly were exposed to asbestos while working on the Company's
property. Initially, a total of approximately four hundred and
forty-eight (448) individual plaintiffs added the Company to
their Complaints. While the pleadings are not entirely clear, it
appears that each plaintiff seeks $2 million in compensatory
damages and $4 million in punitive damages from each defendant.
In a related proceeding in the Baltimore City case, the Company
was served, in September 1993, with a third party complaint by
Owens Corning Fiberglass, Inc. (Owens Corning) alleging that
Owens Corning was in the process of settling approximately 700
individual asbestos-related cases and seeking a judgment for
contribution against the Company on the same theory of alleged
negligence set forth above in the plaintiffs' case.
Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed
a third party complaint against the Company, seeking contribution
for the same plaintiffs involved in the Owens Corning third party
complaint. Since the filings, a number of the individual suits
have been disposed of without any payment by the Company. The
third party complaints involving Pittsburgh Corning and Owens
Corning were dismissed by the Baltimore City Court during 1994
without any payment by the Company. While the aggregate amount
specified in the remaining suits would exceed $1 billion, the
Company believes the amounts are greatly exaggerated as were the
claims already disposed of. The amount of total liability, if
any, and any related insurance recovery cannot be precisely
determined at this time; however, based on information and
relevant circumstances known at this time, the Company does not
believe these suits will have a material adverse effect on its
financial position. However, an unfavorable decision rendered
against the Company could have a material adverse effect on
results of operations in the fiscal year in which a decision is
rendered.
The Company is involved in other legal and administrative
(including environmental) proceedings before various courts and
agencies with respect to matters arising in the ordinary course
of business. Management is of the opinion that the final
disposition of these proceedings will not have a material adverse
effect on the Company's financial position or results of
operations.
Nonutility Subsidiary
- ---------------------
In May 1995, PCI adopted a plan to exit the aircraft equipment
leasing business. The plan, which was developed following
comprehensive review, is designed to permit a withdrawal from the
aircraft leasing business on an orderly basis designed to
preserve value. Under the plan, PCI will make no new investments
to increase the size of the aircraft leasing portfolio. In
65
addition, thirteen aircraft have been designated for sale over 18
to 24 months from the date the plan was announced. These
aircraft are subject to short-term, usage-based leases, long-term
leases that will expire in the near term, or are not currently
under lease. The book value of these aircraft (which, prior to
adoption of the plan, was $295 million) was reduced to an
estimated net realizable value of approximately $105 million.
After taking into account the elimination of a previously
established reserve of approximately $22 million for future
repair and maintenance expenditures and other minor adjustments,
the result was an immediate non-cash charge to after-tax earnings
of approximately $110 million for the second quarter of 1995.
There will be no future depreciation of, or routine accrual for
repair and maintenance expenditures with respect to, these
aircraft. For accounting purposes, gains or losses from the sale
of individual aircraft will be deferred until completion of the
disposal process.
In accordance with the plan, PCI will continue to hold and
closely monitor the remainder of its aircraft leasing portfolio,
with the objective of identifying future opportunities for
disposition of these investments on favorable terms.
Depreciation on two wholly owned aircraft, six majority owned
aircraft and two aircraft held by partnerships, in which PCI has
a 50% interest, has been increased in order to achieve book
values at lease expiration that will correspond to their
respective anticipated residual values. The net effect of this
revised depreciation, coupled with the elimination of further
depreciation on the aircraft designated for sale, will result in
higher depreciation charges through 1997, and lower depreciation
charges thereafter, as compared to the depreciation charges PCI
would have incurred absent the plan. No adjustments were made to
the remainder of PCI's aircraft leasing portfolio, which consists
of twelve full or partial interests in aircraft under leveraged
leases or direct finance leases.
PCI will continue to market and sell the thirteen aircraft
designated for sale and will continue to closely monitor the
aircraft in its portfolio not designated for near term sale with
the objective of identifying future opportunities for sale or
other disposition on favorable terms. Satisfactory execution of
the entire plan may be affected by future aircraft market
conditions and events, which may have an impact on equipment
values and sales opportunities and, in the case of the portion of
the portfolio on long term lease, the creditworthiness of PCI's
lessees.
In April 1995, PCI reached agreement with Continental
providing for the deferral of approximately 40% of aggregate
monthly rentals from the four majority-owned and two jointly
owned DC-10-30 aircraft for a period of sixteen months,
commencing February 1995. The deferred amounts are to be repaid
over a three and one-half year period with 8% interest,
66
commencing June 1, 1996, at which time the aggregate deferred
amount will be approximately $20 million. As part of the
agreement, PCI obtained cross-default provisions in its
Continental leases and improvements in aircraft return
conditions.
During July 1995, Atlas Air, Inc. filed suit in New York
Superior Court requesting a declaratory judgment that the
duration of its lease of one B-747-200F aircraft from PCI may be
extended by Atlas, without PCI's consent, from December 1995
until as late as December 1999. On August 22, 1995, PCI filed
its answer to Atlas' complaint, stating that Atlas' position is
contrary to the plain meaning of the lease agreement and Atlas'
own prior course of conduct acknowledging the December 1995 lease
termination date. Cross-motions for summary judgment were filed,
and the Court ruled in Atlas favor on December 27, 1995. A new
and separate complaint, based on PCI's termination of the lease
agreement because of Atlas' failure to make certain lease
payments, was filed by PCI on December 29, 1995. The parties
have agreed to an expedited procedural schedule, and PCI's motion
for summary judgment was submitted on January 10, 1996.
Management is of the opinion that the outcome of this litigation
will not have a material adverse effect on its financial position
or results of operations.
67
(14) Supplemental Disclosure of Cash Flow Information
------------------------------------------------
Listed below is supplemental disclosure of cash flow information.
- -----------------------------------------------------------------
1995 1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Cash paid for:
Interest, net of capitalized
interest (including nonutility
subsidiary interest of $93,672,
$83,724 and $76,556) $223,789 203,013 206,955
Income taxes $ 44,725 51,368 67,741
Nonutility subsidiary noncash
transactions:
Consolidation of majority-owned
subsidiaries $ - - 35,320
- -----------------------------------------------------------------
For purposes of the consolidated financial statements, cash
and cash equivalents include cash on hand, money market funds and
commercial paper with maturities of three months or less.
68
(15) Selected Nonutility Subsidiary Financial Information
----------------------------------------------------
Selected financial information of the Company's principal
consolidated nonutility investment subsidiary, Potomac Capital
Investment Corporation (PCI) and its subsidiaries, is presented
below. Subsidiary equity at December 31, 1995 and December 31,
1994 was $168.4 million and $271.1 million, respectively. These
amounts include $6.8 million of unrealized appreciation and $23.9
million of unrealized depreciation, respectively, at December 31,
1995 and 1994 relating to the marketable securities portfolio on
an after-tax basis. PCI paid dividends to the parent Company of
$9 million in 1995 and $15 million in 1994.
- -----------------------------------------------------------------
For the year ended
December 31,
1995 1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Income
Leasing activities $ 100,640 $111,262 $114,226
Marketable securities 36,121 35,148 38,417
Other (2,268) 596 (13,302)
--------- -------- --------
134,493 147,006 139,341
--------- -------- --------
Loss on assets held for
disposal (170,078) - -
--------- -------- --------
Expenses
Interest 91,637 84,783 77,861
Administrative and general 10,479 10,259 14,640
Depreciation and operating 72,404 55,571 66,817
Income tax credit (85,708) (22,695) (45,078)
--------- -------- --------
88,812 127,918 114,240
--------- -------- --------
Net (loss) earnings from
nonutility subsidiary $(124,397) $ 19,088 $ 25,101
========= ======== ========
69
Marketable Securities
- ---------------------
PCI's marketable securities are classified as available-for-sale
for financial reporting purposes. Investment grade preferred
stocks with mandatory redemption features made up 96% of the
portfolio at December 31, 1995. Net unrealized gains and losses
on such securities are reflected, net of tax, in stockholder's
equity.
70
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------
December 31,
1995 1994
-----------------------------------------------------------------
Net
Market Unrealized Market
Cost Value Gain (Loss) Cost Value
- -------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Mandatory redeemable
preferred stock $ 519,488 $ 530,115 $ 10,627 $ 511,791 $ 473,608
Equity securities 341 208 (133) 3 -
---------- ---------- ----------- ---------- ----------
Total $ 519,829 $ 530,323 $ 10,494 $ 511,794 $ 473,608
========== ========== =========== ========== ==========
- -------------------------------------------------------------------------------------------
71
</TABLE>
Included in net unrealized gains and losses are gross
unrealized gains of $17.1 million and gross unrealized losses of
$6.6 million at December 31, 1995 and gross unrealized gains of
$1.8 million and gross unrealized losses of $40 million at
December 31, 1994.
In determining gross realized gains and losses on sales or
maturities of securities, specific identification is used. Gross
realized gains were $.8 million and $2.9 million for 1995 and
1994, respectively. Gross realized losses were $.4 million and
$2.1 million for 1995 and 1994, respectively.
Net recognized gains from marketable securities amounted to
$7 million in 1993.
At December 31, 1995, the contractual maturities for
mandatory redeemable preferred stock are $65.1 million within one
year, $93 million from one to five years, $115.8 million from
five to 10 years and $245.6 million for over 10 years.
72
Leasing Activities
- ------------------
PCI's net investment in finance leases are summarized below.
- -----------------------------------------------------------------
December 31,
1995 1994
- -----------------------------------------------------------------
(Thousands of Dollars)
Rents receivable $691,371 $517,052
Estimated residual values 153,815 153,814
Less: Unearned and deferred income (355,756) (260,539)
-------- --------
Investment in finance leases 489,430 410,327
Less: Deferred taxes arising from
finance leases (149,103) (134,925)
-------- --------
Net investment in finance leases $340,327 $275,402
======== ========
- -----------------------------------------------------------------
Minimum lease payments receivable from finance leases,
primarily aircraft, for each of the years 1996 through 2000 are
$32.3 million, $27.1 million, $31.2 million, $30 million and
$32.8 million, respectively. Net income from leveraged leases
was $11 million in 1995, $5.6 million in 1994 and $1.1 million in
1993.
Rent payments receivable from aircraft equipment operating
leases for each of the years 1996 through 2000 are $46.4 million
in 1996, $38.8 million in 1997, $31.4 million in 1998, $25.3
million in 1999 and $25.1 million in 2000.
In September 1995, PCI purchased from and leased back to an
Australian governmental entity two 350 megawatt (gross) coal-
fired electric generating units located in Queensland, Australia.
PCI's original equity investment totaled $96 million and is being
accounted for as a leveraged lease.
During 1994, PCI purchased from and leased back to a Dutch
electric utility company an approximate one-third undivided
interest in a recently-constructed 650 megawatt (gross) baseload,
coal and gas-fired power plant located in The Netherlands. PCI's
original equity investment totaled $60 million and is accounted
for as a leveraged lease.
73
<TABLE>
(16) Quarterly Financial Summary (Unaudited)
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter Total
- ---------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars except Per Share Data)
<S> <C> <C> <C> <C> <C>
1995
Operating Revenue $ 363,433 440,455 642,511 376,033 1,822,432
Total Revenue $ 364,909 445,359 663,584 402,250 1,876,102
Operating Expenses $ 334,091 354,120 480,348 359,802 1,528,361
Operating Income $ 30,818 91,239 183,236 42,448 347,741
Net (Loss) Income $ (3,972) (56,838) 145,947 9,254 94,391
(Loss) Earnings for Common Stock $ (8,213) (61,072) 141,747 5,078 77,540
(Loss) Earnings Per Common Share $ (.07) (.52) 1.20 .04 .65
Dividends Per Share $ .415 .415 .415 .415 1.66
1994
Operating Revenue $ 374,910 458,431 605,023 352,236 1,790,600
Total Revenue $ 393,044 467,451 607,476 355,103 1,823,074
Operating Expenses $ 355,708 370,439 447,020 325,414 1,498,581
Operating Income $ 37,336 97,012 160,456 29,689 324,493
Net Income $ 14,414 64,293 134,702 13,753 227,162
Earnings for Common Stock $ 10,268 60,224 130,576 9,657 210,725
Earnings Per Common Share $ .09 .51 1.11 .08 1.79
Dividends Per Share $ .415 .415 .415 .415 1.66
1993
Operating Revenue $ 331,236 416,152 610,540 344,514 1,702,442
Total Revenue $ 339,455 419,693 614,261 351,796 1,725,205
Operating Expenses $ 302,833 332,796 442,306 322,608 1,400,543
Operating Income $ 36,622 86,897 171,955 29,188 324,662
Net Income $ 13,044 77,022 144,671 6,842 241,579
Earnings for Common Stock $ 8,931 72,974 140,631 2,788 225,324
Earnings Per Common Share $ .08 .63 1.21 .02 1.95
Dividends Per Share $ .41 .41 .41 .41 1.64
The Company's sales of electric energy are seasonal and, accordingly,
comparisons by quarter within a year are not meaningful.
The total of the four quarterly earnings per share may not equal
the earnings per share for the year due to changes in the number of
common shares outstanding during the year.
74
</TABLE>
<TABLE>
Stock Market Information
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------------
1995 High Low 1994 High Low
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1st Quarter $20-1/8 $18-3/8 1st Quarter $26-5/8 $21-3/4
2nd Quarter $22-1/2 $18-1/2 2nd Quarter $23-1/2 $18-1/2
3rd Quarter $24-5/8 $20-1/2 3rd Quarter $21-1/2 $18-3/8
4th Quarter $26-1/4 $24 4th Quarter $19-3/4 $18-1/4
(Close $26-1/4) (Close $18-3/8)
Shareholders at December 31, 1995: 96,958
- ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991 1990 1985
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands except Per Share Data)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenue $1,822,432 1,790,600 1,702,442 1,562,167 1,552,066 1,411,713 1,315,699
Total Revenue $1,876,102 1,823,074 1,725,205 1,601,558 1,619,315 1,501,728 1,398,768
Operating Expenses $1,528,361 1,498,581 1,400,543 1,322,105 1,329,084 1,245,579 1,144,436
Net (Loss) Earnings from
Nonutility Subsidiary $ (124,397) 19,088 25,101 28,161 23,351 5,035 14,878
Income Before Cumulative Effect of
Accounting Change $ 94,391 227,162 241,579 200,760 210,164 170,234 183,618
Cumulative Effect of Accounting
Change, Net of Income Taxes $ - - - 16,022 - - -
Net Income $ 94,391 227,162 241,579 216,782 210,164 170,234 183,618
Earnings for Common Stock $ 77,540 210,725 225,324 202,390 197,866 159,636 169,093
Average Common Shares Outstanding 118,412 118,006 115,640 112,390 105,911 98,621 94,230
Earnings (Loss) Per Common Share
Utility Operations $ 1.70 1.63 1.73 1.55 <F1> 1.65 1.57 1.63
Nonutility Subsidiary $ (1.05) .16 .22 .25 .22 .05 .16
Consolidated $ .65 1.79 1.95 1.80 <F1> 1.87 1.62 1.79
Cash Dividends Per Common Share $ 1.66 1.66 1.64 1.60 1.56 1.52 1.08
Investment in Property
and Plant $6,161,103 5,974,170 5,701,550 5,404,265 5,084,964 4,695,966 3,339,911
Net Investment in Property
and Plant $4,400,311 4,334,399 4,167,551 3,967,898 3,743,709 3,434,678 2,454,559
Utility Assets $5,503,087 5,327,606 5,036,737 4,515,403 4,211,556 3,889,101 2,881,110
Nonutility Subsidiary Assets $1,615,063 1,674,289 1,665,132 1,663,508 1,679,079 1,387,247 366,704
Total Assets $7,118,150 7,001,895 6,701,869 6,178,911 5,890,635 5,276,348 3,247,814
Long-Term Utility Obligations
(including redeemable preferred
stock) $1,960,562 1,866,962 1,736,621 1,727,609 1,662,157 1,516,073 1,144,671
- ---------------------------------------------------------------------------------------------------------------------------------
<FN>
<F1>Includes $.14 as the cumulative effect of an accounting change for unbilled revenue.
</FN>
</TABLE>
