UNITED STATES
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) January 26, 1998
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
_______________________________________________________________________
(Former Name or Former Address, if Changed Since Last Report)
<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.
99 The 1997 consolidated financial
statements of the Company and
Subsidiary, together with the
report thereon of Price Waterhouse
dated January 16, 1998; 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)
/S/ D. R. WRAASE
By ___________________________
Dennis R. Wraase
Senior Vice President and
Chief Financial Officer
January 26, 1998
DATE
-3-
<PAGE>
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
- ------------------ ---------------------
The computations of the coverage of fixed charges, before income taxes,
and the coverage of combined fixed charges and preferred dividends for
each of the years 1997 through 1993 on the basis of parent company operations
only, are as follows.
<CAPTION>
For The Year Ended December 31,
-------------------------------------------------------
1997 1996 1995 1994 1993
-------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Net income $164,749 $220,066 $218,788 $208,074 $216,478
Taxes based on income 97,487 135,011 129,439 116,648 107,223
-------------------------------------------------------
Income before taxes 262,236 355,077 348,227 324,722 323,701
-------------------------------------------------------
Fixed charges:
Interest charges 146,703 146,939 146,558 139,210 141,393
Interest factor in rentals 23,616 23,560 23,431 6,300 5,859
-------------------------------------------------------
Total fixed charges 170,319 170,499 169,989 145,510 147,252
-------------------------------------------------------
Income before income taxes and fixed charges $432,555 $525,576 $518,216 $470,232 $470,953
======== ======== ======== ======== ========
Coverage of fixed charges 2.54 3.08 3.05 3.23 3.20
==== ==== ==== ==== ====
Preferred dividend requirements $16,579 $16,604 $16,851 $16,437 $16,255
-------------------------------------------------------
Ratio of pre-tax income to net income 1.59 1.61 1.59 1.56 1.50
-------------------------------------------------------
Preferred dividend factor $26,361 $26,732 $26,793 $25,642 $24,383
-------------------------------------------------------
Total fixed charges and preferred dividends $196,680 $197,231 $196,782 $171,152 $171,635
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.20 2.66 2.63 2.75 2.74
==== ==== ==== ==== ====
</TABLE>
<PAGE>
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
- ------------------ ---------------------
The computations of the coverage of fixed charges, before income taxes,
and the coverage of combined fixed charges and preferred dividends for
each of the years 1997 through 1993 on a fully consolidated basis
are as follows.
<CAPTION>
For The Year Ended December 31,
-------------------------------------------------------
1997 1996 1995 1994 1993
-------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Net income $181,830 $236,960 $94,391 $227,162 $241,579
Taxes based on income 65,669 80,386 43,731 93,953 62,145
-------------------------------------------------------
Income before taxes 247,499 317,346 138,122 321,115 303,724
-------------------------------------------------------
Fixed charges:
Interest charges 216,156 231,029 238,724 224,514 221,312
Interest factor in rentals 23,687 23,943 26,685 9,938 9,257
-------------------------------------------------------
Total fixed charges 239,843 254,972 265,409 234,452 230,569
-------------------------------------------------------
Nonutility subsidiary capitalized interest (493) (649) (529) (521) (2,059)
-------------------------------------------------------
Income before income taxes and fixed charges $486,849 $571,669 $403,002 $555,046 $532,234
======== ======== ======== ======== ========
Coverage of fixed charges 2.03 2.24 1.52 2.37 2.31
==== ==== ==== ==== ====
Preferred dividend requirements $16,579 $16,604 $16,851 $16,437 $16,255
-------------------------------------------------------
Ratio of pre-tax income to net income 1.36 1.34 1.46 1.41 1.26
-------------------------------------------------------
Preferred dividend factor $22,547 $22,249 $24,602 $23,176 $20,481
-------------------------------------------------------
Total fixed charges and preferred dividends $262,390 $277,221 $290,011 $257,628 $251,050
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 1.86 2.06 1.39 2.15 2.12
==== ==== ==== ==== ====
</TABLE>
<PAGE>
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, 33-61379 and 333-33495) of Potomac
Electric Power Company of our report dated January 16, 1998
appearing on page 29 of Exhibit 99 of the Current Report on Form
8-K of Potomac Electric Power Company dated January 26, 1998.
/s/ PRICE WATERHOUSE LLP
Price Waterhouse LLP
Washington, D.C.
January 26, 1998
<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-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,464,272
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 392,600
<TOTAL-DEFERRED-CHARGES> 661,298
<OTHER-ASSETS> 1,189,387
<TOTAL-ASSETS> 6,707,557
<COMMON> 118,501
<CAPITAL-SURPLUS-PAID-IN> 1,010,209
<RETAINED-EARNINGS> 734,318
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,863,028
141,000
125,290
<LONG-TERM-DEBT-NET> 1,901,486
<SHORT-TERM-NOTES> 0<F1>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 131,375<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 51,069
985
<CAPITAL-LEASE-OBLIGATIONS> 160,406
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,312,146
<TOT-CAPITALIZATION-AND-LIAB> 6,707,557
<GROSS-OPERATING-REVENUE> 1,863,510
<INCOME-TAX-EXPENSE> 117,731
<OTHER-OPERATING-EXPENSES> 1,420,396
<TOTAL-OPERATING-EXPENSES> 1,538,127
<OPERATING-INCOME-LOSS> 325,383
<OTHER-INCOME-NET> (4,723)
<INCOME-BEFORE-INTEREST-EXPEN> 320,660
<TOTAL-INTEREST-EXPENSE> 138,830
<NET-INCOME> 181,830
16,579
<EARNINGS-AVAILABLE-FOR-COMM> 165,251
<COMMON-STOCK-DIVIDENDS> 196,615
<TOTAL-INTEREST-ON-BONDS> 132,600<F2>
<CASH-FLOW-OPERATIONS> 434,819
<EPS-PRIMARY> $1.39<F3>
<EPS-DILUTED> $1.38
<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, 1997.
<F3>Effective December 31, 1997, the Company adopted Statement of Financial
Accounting Standards No. 128 entitled "Earnings per Share." Accordingly,
the Company's Earnings per Share are as follows: Basic $1.39; Diluted $1.38.
</FN>
</TABLE>
POTOMAC ELECTRIC POWER COMPANY
------------------------------
AND
---
SUBSIDIARY
----------
Consolidated Financial Statements
---------------------------------
For the Year Ended December 31, 1997
------------------------------------
Item 7
Exhibit 99
Financial Information
- ---------------------
Potomac Electric Power Company and Subsidiary
Contents
- --------
Management's Discussion and Analysis of
Consolidated Results of Operations and
Financial Condition...................................... 2
Report of Independent Accountants.......................... 29
Consolidated Statements of Earnings........................ 30
Consolidated Balance Sheets................................ 31
Consolidated Statements of Cash Flows...................... 33
Notes to Consolidated Financial Statements................. 34
Selected Consolidated Financial Data....................... 70
1
Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
- ----------------------------------------------------
TERMINATION OF PROPOSED MERGER
- ------------------------------
On December 22, 1997, Potomac Electric Power Company (the
Company, PEPCO) and Baltimore Gas and Electric Company announced
the cancellation of their proposed merger (the Merger) to create
Constellation Energy Corporation. As a result, the Company
recorded a $52.5 million non-operating charge ($32.6 million net
of income tax or 28 cents per share) to write off its cumulative
deferred Merger-related costs. At December 31, 1996, deferred
costs related to the Merger totaled $29 million and are included
in "Other Deferred Charges" on the Consolidated Balance Sheet.
While all necessary regulatory approvals had been received,
the orders of both the Maryland and the District of Columbia
public service commissions contained financial conditions that
made it impossible for the two companies' investors to share in
the benefits of the proposed Merger. The regulatory plan proposed
by the companies had called for an equal sharing of the savings
between customers and shareholders. Both commission orders
returned more than the estimated total Merger savings to the
customers. The companies tried unsuccessfully to obtain timely
reconsideration of these conditions but concluded that a
favorable outcome could not be expected within a reasonable
period, if at all.
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 1997. Fuel and purchased energy,
capacity purchase payments and other operating expenses were 53%
of total revenue. The Company's wholly owned subsidiary, Potomac
Capital Investment Corporation (PCI), conducts nonutility
investment programs and businesses with the objective of
supplementing current utility earnings and building long-term
shareholder value.
2
The information set forth below discusses the results of
operations, capital resources and liquidity during the period
1995 through 1997 for the Company and PCI.
The Company's earnings for common stock during 1997 totaled
$165.3 million, as compared to $220.4 million in 1996. As set
forth below, utility earnings per share from operations decreased
from $1.72 in 1996 to $1.53 in 1997, excluding the December 1997
write-off of Merger related costs of 28 cents per share.
Consolidated earnings decreased from $1.86 to $1.39 in 1997. The
1995 nonutility subsidiary results reflect noncash, nonrecurring
charges of $1.04 related to PCI's May 1995 plan with respect to
the aircraft equipment leasing business.
- -----------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------
Utility Operations $1.53 $1.72 $1.70
Merger Costs (.28) - -
Nonutility Subsidiary .14 .14 (1.05)
----- ----- -----
Consolidated $1.39 $1.86 $ .65
===== ===== =====
- -----------------------------------------------------------------
The average number of common shares outstanding at December 31,
1997, was relatively unchanged from December 31, 1996.
FORWARD LOOKING STATEMENTS
- --------------------------
This Management's Discussion and Analysis of Consolidated Results
of Operations and Financial Condition contains forward looking
statements, as defined by the Private Securities Litigation Act
of 1995, with regard to matters that could have an impact on the
future operations, financial results or financial condition of
the Company. These statements are based on the current
expectations, estimates or projections of management and are not
guarantees of future performance. Actual results may differ
materially from those anticipated by the forward looking
statements, depending on the occurrence or nonoccurrence of
future events or conditions that are difficult to predict and
generally are beyond the control of the Company. All such
forward looking statements relating to the following matters are
qualified by the cautionary statements below and contained
elsewhere herein.
3
Growth in Demand, Sales and Capacity to Fulfill Demand
------------------------------------------------------
The actual growth in demand for and sales of electricity
within the Company's service territory may vary from the
statements made concerning the anticipated growth in demand
and sales, depending upon a number of factors, including
weather conditions, the competitive environment, general
economic conditions and the demographics of the Company's
service territory. Future construction expenditures
(including the need to construct additional generation
capacity) may vary from the projections, depending on the
accuracy of management's expectations regarding growth in
demand for and sales of electricity, regulatory developments
and the evolution of the competitive marketplace for
electricity.
Competition
-----------
Increased competition will have an impact on future results
of operations, which may be adverse, and will depend, among
other factors, upon governmental policies and regulatory
actions, including those of the Federal Energy Regulatory
Commission (FERC) and the District of Columbia and Maryland
public service commissions, future economic conditions and
the influence exerted by emerging market forces over the
structure of the electric industry.
4
UTILITY
- -------
RESULTS OF OPERATIONS
- ---------------------
Total Revenue
- -------------
The changes in total revenue are shown in the following table.
- -----------------------------------------------------------------
Increase (Decrease)
from Prior Year
1997 1996 1995
- -----------------------------------------------------------------
(Millions of Dollars)
Change in kilowatt-hour sales $ (8.6) $(11.5) $ 27.2
Change in base rate revenue (7.2) 27.0 42.8
Change in fuel adjustment clause
billings to cover cost of
fuel and interchange and
capacity purchase payments (9.2) (4.5) (39.3)
Change in other revenue 1.0 1.4 1.1
------- ------ ------
Change in Operating Revenue (24.0) 12.4 31.8
------- ------ ------
Change in interchange deliveries (122.8) 121.8 21.2
------- ------ ------
Change in Total Revenue $(146.8) $134.2 $ 53.0
======= ====== ======
- -----------------------------------------------------------------
The decrease in 1997 base rate revenue compared to 1996
primarily reflects a decrease of $7.3 million in the conservation
incentive provision of the Company's Demand Side Management (DSM)
surcharge in Maryland. The conservation incentive, totaling $1.6
million, was awarded for achieving specified 1996 Maryland energy
goals. The Company recorded an $8.9 million bonus in 1996 for
achieving specified 1995 energy goals.
The increase in base rate revenue in 1996 as compared to
1995 reflects the continued effects of a District of Columbia
rate increase of $27.9 million (effective July 1995) and an
increase of $17.7 million associated with the Company's DSM
surcharge in Maryland, which includes a $.2 million increase in
the conservation incentive provision of the tariff for achieving
specified 1995 Maryland energy goals.
5
The increase in base rate revenue in 1995 as compared to
1994 reflects the effect of a District of Columbia rate increase
of $27.9 million (effective July 1995) and the continued effect
of a 1994 rate increase in the District of Columbia. In
addition, 1995 base rate revenue reflects an increase of $28
million associated with the Company's DSM surcharge in Maryland,
which includes a $3.7 million increase in the conservation
incentive provision of the tariff for achieving specified 1994
Maryland energy goals.
The decrease in 1997 in revenue from interchange deliveries
reflects the change in the level of activity in purchase-for-
resale agreements under the Company's wholesale power sales
tariff, predominantly where the Company buys energy from one
party for the purpose of selling that energy to a third party.
Beginning in January 1997 through March 1997, and pursuant to
FERC's Order No. 888, the Company implemented an open access
transmission tariff (OATT) and terminated the purchase-for-resale
agreements. On April 1, 1997, the Pennsylvania-New Jersey-
Maryland Interconnection Association (PJM) implemented an OATT on
behalf of its transmission owners, replacing the Company's OATT.
The Company classifies revenue from service agreements under
these tariffs as "Other operating revenue". In addition,
interchange deliveries include revenue from bilateral energy
transactions and the sale of short-term generating capacity. The
increases in 1996 and 1995 in revenue from interchange deliveries
reflect the growth in the number of companies involved in power
sales tariff interchange transactions, and changes in levels and
pricing of energy delivered to PJM. The benefits derived from
interchange deliveries, the allocated amounts of capacity sales
in the District of Columbia (approximately 40%) and revenue under
the OATT are passed through to the Company's customers through a
fuel adjustment clause.
6
Kilowatt-hour Sales
- -------------------
- -----------------------------------------------------------------
1997 1996
vs. vs.
1997 1996 1995 1996 1995
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
By Customer Type
Residential 6,552 6,869 6,707 (4.6)% 2.4%
Commercial 11,811 11,712 11,861 .8 (1.3)
U.S. Government 3,934 3,902 3,998 .8 (2.4)
D.C. Government 850 847 879 .4 (3.6)
Wholesale 2,561 2,570 2,465 (.4) 4.3
------ ------ ------
Total energy sales 25,708 25,900 25,910 (.7) -
====== ====== ======
Interchange
Energy deliveries 822 7,063 1,784 (88.4) -
====== ====== ======
By Geographic Area
Maryland, including
wholesale 15,601 15,763 15,594 (1.0) 1.1
District of Columbia 10,107 10,137 10,316 (.3) (1.7)
------ ------ ------
Total energy sales 25,708 25,900 25,910 (.7) -
====== ====== ======
- -----------------------------------------------------------------
Kilowatt-hour sales decreased .7% in 1997 resulting from
decreases in cooling degree hours of 5% and 21% from the 1996 and
20-year average, respectively, partially offset by a .8% increase
in customers. Kilowatt-hour sales in 1996 remained relatively
unchanged from 1995. Kilowatt-hour sales were affected by a .6%
increase in the average number of customers and increased usage
of electricity during the blizzard-like conditions in the first
quarter of 1996, and were partially offset by decreased usage of
electricity during the cooler than average summer months of 1996.
Cooling degree hours in 1996 were 19% and 17% below the 1995 and
20-year average, respectively. 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.
The 1997 summer peak demand of 5,689 megawatts occurred on
June 25, 1997. This compares with the 1996 summer peak demand of
5,288 megawatts, and the all-time summer peak demand of 5,769
megawatts which occurred in July 1991. The Company's present
7
generation capability, excluding short-term capacity
transactions, is 6,806 megawatts. In addition, the Company had
approximately 265 megawatts available from its dispatchable
Energy Use Management (EUM) programs to meet the 1997 summer peak
demand. Based on average weather conditions, the Company
estimates that its peak demand will grow at a compound annual
rate of approximately 1.5%, reflecting continuing success with
DSM and EUM programs and anticipated service area growth trends.
The 1996-1997 winter season peak demand of 4,632 megawatts was
7.5% 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
- -----------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------
(Millions of Dollars)
Fuel expense $319.6 $327.8 $355.4
------ ------ ------
Purchased energy
PJM 86.6 114.6 79.4
Other 114.0 221.4 114.2
------ ------ ------
Total purchased energy 200.6 336.0 193.6
------ ------ ------
Fuel and purchased energy $520.2 $663.8 $549.0
====== ====== ======
Capacity purchase payments $150.9 $125.8 $125.8
====== ====== ======
- -----------------------------------------------------------------
Net System Generation and Purchased Energy were as follows.
- -----------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
Net system generation 18,322 18,041 19,234
====== ====== ======
Purchased energy 9,371 16,157 9,755
====== ====== ======
- -----------------------------------------------------------------
8
Although net generation increased by 1.6% during 1997, fuel
expense decreased due to the timing of fuel billed to customers
through the Company's fuel rates. The 1996 decrease in fuel
expense reflects a decrease of 6.2% in net generation, partially
offset by an increase in the system average fuel cost summarized
below.
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)
1997 89.1 6.4 4.5 $1.65 $3.80 $2.87 $1.84
1996 89.7 6.9 3.4 1.62 3.55 2.92 1.80
1995 85.4 6.1 8.5 1.60 3.22 2.10 1.74
- -----------------------------------------------------------------
The increase of approximately 2% in the 1997 system average
unit fuel cost compared with the 1996 system average resulted
primarily from an increased unit cost of coal. The 1996 system
average unit fuel cost increased by approximately 3% which was
primarily the result of the increase in the cost of residual oil
and an increase in the percent of residual oil contribution to
the fuel mix. The Company's major cycling and certain peaking
units can burn either natural gas or oil, adding flexibility in
selecting the most cost-effective fuel mix. The increase in the
percent of gas burned in 1997 reflects the decreased price of gas
and the decreased usage of higher-cost oil. The decrease in the
percent of gas burned in 1996 reflects the increased price of gas
and the increased usage of lower-cost coal.
The Company's generating and transmission facilities are
interconnected with those of other transmission owners in the PJM
power pool and other utilities. Historically, the pricing of
most PJM-dispatched internal economy energy transactions was
based upon "split savings" whereby such energy was priced 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 April 1997, PJM
implemented a "bid-based" energy market, where companies offer
energy at prices based on cost, and transactions occur at the
market's marginal clearing price.
9
On November 25, 1997, the FERC conditionally approved a PJM
restructuring plan which, among other things, established an
independent system operator (ISO). The ISO began operation on
January 1, 1998, and is responsible for system operations and
regional transmission planning. PJM's revised transmission
tariff will become effective on April 1, 1998. The Commission
indicated that the independent body that operates the ISO may
also operate the PJM power exchange. Transmission is now priced
at a single rate based on the cost of the transmission system
where the generating capacity is delivered, instead of the prior
practice of paying separate rates for each transmission system
used. The Commission also approved locational marginal pricing
for transmission congestion control. The Commission delineated
the principles necessary for forming ISO's in its Order No. 888
issued in April 1996. (See Restructuring of the Bulk Power
Market discussion below).
In addition to interchange with PJM, the Company is actively
participating in the emerging bilateral energy sales marketplace.
The Company's wholesale power sales tariff allows both sales from
Company-owned generation and sales of energy purchased by the
Company from other market participants. Over 40 utilities and
marketers have executed service agreements allowing them to
arrange purchases under this tariff. The Company has also
executed service agreements allowing it to purchase energy under
other market participants' power sales tariffs. These agreements
greatly expand the opportunities for economic transactions.
The Company continues to purchase energy from Ohio Edison
under the Company's 1987 long-term capacity purchase agreements
with Ohio Edison and Allegheny Energy, Inc. (AEI, formerly
Allegheny Power System). Pursuant to this agreement, the Company
is purchasing 450 megawatts of capacity and associated energy
through the year 2005. In August 1996, the Company began
purchasing energy from the Panda-Brandywine, L.P. (Panda)
facility, pursuant to a 25-year power purchase agreement for 230
megawatts of capacity supplied by a gas-fueled combined-cycle
cogenerator. Capacity payments under this agreement commenced in
January 1997. The Company also purchases energy from the
Northeast Maryland Waste Disposal Authority under an avoided
cost-based purchase agreement. In November 1997, the Company
agreed to purchase the 32-megawatt rated capacity of this
facility for the period November 1, 1997 to December 31, 1998.
This purchase facilitated the sale of 35 megawatts of capacity to
Northeastern Utility Service Company (NUSCO). The capacity
expense under these agreements, including an allocation of a
portion of Ohio Edison's fixed operating and maintenance costs,
was $145.2 million for 1997 and is estimated at $143 million for
1998. Commitments under these agreements are estimated at $198
million for 1999, $201 million for 2000, and $207 million for
2001 and 2002. The District of Columbia fuel rate includes a
provision for the current recovery of purchased capacity costs as
well as a provision for the credit for capacity sales. In
10
Maryland, purchased capacity costs are recovered in base rates.
Accordingly, the Company will seek recovery of future changes in
the levels of these costs through a base rate application to the
Maryland Commission.
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 approximately $5.5 million per year. The
Company's power sales tariff also allows for the sale of
generating capacity on a short-term basis. The Company sold
capacity to PECO Energy Company in the amount of 150 megawatts
during January 1997 and 100 megawatts for the period February
through May 1997. In addition, the Company is selling capacity
to Delmarva Power & Light Company in the amount of 100 megawatts
for the period June 1, 1997, through May 31, 1998; and to GPU,
Inc. in the amount of 130 megawatts for the period August 1,
1997, through December 31, 1997. The Company is also selling 35
megawatts of capacity to NUSCO for the period November 1, 1997
through December 31, 1998. This sale was facilitated by the
purchase of 32 megawatts of capacity from the Northeast Maryland
Waste Disposal Authority. Revenues from capacity and energy
transactions totaled approximately $11.1 million, $151.4 million
and $22.9 million in 1997, 1996 and 1995, respectively, and are
included as components of interchange deliveries.
As electricity becomes more actively traded as a commodity,
the bulk power market is developing methods for traders to hedge
against price volatility. New York Mercantile Exchange (NYMEX)
futures contracts for electricity began trading in 1996 for
delivery at the California-Oregon border and at Palo Verde
Substation in Arizona. The NYMEX has approved a futures contract
with PJM delivery, and is preparing to submit the contract to the
Commodities Futures Trading Commission for approval. This
futures contract, anticipated to begin in 1998, will have a
greater relevance to transactions in the mid-Atlantic
marketplace. In addition, some market participants are using
customized instruments to hedge prices for both capacity and
energy. Such instruments include forward contracts to fix
prices, options to set ceilings or floors on prices and
contracts-for-differences to exchange variable prices for a fixed
price. The proposed mid-Atlantic energy market is expected to
feature a secondary market in transmission congestion hedging.
In the future, the Company expects to participate in the hedging
markets as part of its strategy to control costs and avoid
unreasonable risks. In some instances, as part of its overall
bulk power marketing activity, the Company may offer to sell
hedging instruments.
11
Other Operation and Maintenance Expenses
- ----------------------------------------
Other operation and maintenance expenses totaled $315.5 million
for 1997. These expenses increased by $.7 million (.2%) in 1997,
principally due to increases in electric plant maintenance
expense, partially offset by reduced labor and benefits costs.
These expenses decreased by $2 million (.6%) in 1996, including
the $1.8 million and $.9 million paid on January 5, 1996, and
June 7, 1996, respectively, to union members as part of the 1995
Labor Agreement between the Company and Local 1900 of the
International Brotherhood of Electrical Workers. These expenses
increased by $18.2 million (6.1%) in 1995, including $15.2
million related to the December 1994 sale and leaseback of the
Company's control center system. The Company's budget and cost
control disciplines have resulted in a 16% decline in the number
of Company employees since 1994. In addition, utility operating
results for 1995 were 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
has provided annual savings in operating and construction costs
of approximately $15 million.
The Company has implemented, through an internal Task Force,
a 4-phase approach to accommodate the year 2000. The phases
being addressed are: Corporate Application Compliance which
includes all large core business systems; Business Partners'
Systems and Vendor System Verification which is intended to
ensure all suppliers are in compliance with year 2000 processing;
End-user Computing Systems which are all systems which are not
considered core business systems but contain date calculations;
and Non-Information Technology Processes that include all
operating and control systems. The Task Force has developed a
database to identify and track the progress of work on each
phase. The preliminary target date for overall completion of
these phases is mid 1999. The Company is required to charge to
expense, as incurred, internal and external costs specifically
associated with modifying internal-use computer software for the
year 2000, in accordance with a July 1996 pronouncement of the
Emerging Issues Task Force of the Financial Accounting Standards
Board. The costs of expected modifications to be made,
principally in the next two years, will be approximately $10
million. The cost or consequences of a material incomplete or
untimely resolution of the year 2000 problem could adversely
affect future operations, financial results or financial
condition of the Company.
12
Depreciation and Amortization Expense, Income Taxes and
Other Taxes
- -------------------------------------------------------
Depreciation and amortization expense increased by $9 million
(4%) in 1997 due to additional investment in property and plant.
Depreciation and amortization expense increased by $17.5 million
(8.5%) and $25.5 million (14.2%) in 1996 and 1995, 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 decrease in
income taxes in 1997 reflects lower taxable operating income.
The increase in income taxes in 1996 and 1995, reflects higher
taxable operating income. Other taxes increased by $1.4 million
(.7%) in 1997, and decreased by $2.3 million (1.2%) and $3.4
million (1.6%) in 1996 and 1995, respectively. The increase in
1997 reflects increases and partially offsetting decreases in the
levels of plant investment and operating revenue, respectively,
upon which taxes are based. The decreases in 1996 and 1995
reflect the reduction in county fuel-energy tax rates.
Other Income, Allowance for Funds Used During Construction and
Capital Cost Recovery Factor, and Utility Interest Charges
- --------------------------------------------------------------
Other income reflects net earnings (loss) from PCI of $17.1
million in 1997, $16.9 million in 1996 and $(124.4) million in
1995. 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. As discussed above, in December 1997, the Company
wrote off cumulative deferred Merger related costs totaling $52.5
million. Other income includes, in "Other, net", credits of
$19.9 million for income taxes associated with the Merger write-
off. Other income also reflects credits for the equity
components of the Allowance for Funds Used During Construction
(AFUDC) accrued on the Company's Construction Work In Progress
expenditures not in rate base and the Capital Cost Recovery
Factor (CCRF) accrued on certain pollution control expenditures
related to Clean Air Act (CAA) compliance. AFUDC equity totaled
$1 million in 1997, $1.4 million in 1996 and $1.5 million in
1995; CCRF equity credits totaled $5.7 million in 1997, $5.2
million in 1996 and $4.7 million in 1995. CCRF accruals on
unamortized District of Columbia DSM costs not in rate base,
totaling $5.4 million in 1997, $4.1 million in 1996 and $4.8
million in 1995, are also reflected in "Other, net".
Utility interest charges were relatively stable during the
three-year period 1995 through 1997, notwithstanding changes in
the levels of borrowing. Short-term borrowing costs have
remained relatively low. The average cost of outstanding long-
term utility debt declined from 7.56% at the beginning of 1995 to
7.33% at the end of 1997. Utility interest charges were offset
13
by both the debt component of AFUDC which totaled $3.8 million in
1997, $3.9 million in 1996 and $7.5 million in 1995; and by the
debt component of Clean Air Act CCRF which totaled $4.1 million
in 1997, $3.6 million in 1996 and $3.3 million in 1995.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's total investment in property and plant, at original
cost, was $6.5 billion at year-end 1997. Investment in property
and plant construction, net of AFUDC and CCRF, was $610.8 million
for the period 1995 through 1997.
Internally generated cash from utility operations, after
dividends, totaled $503.7 million for the period 1995 through
1997. Sales of First Mortgage Bonds, Medium-Term Notes and
Common Stock during the period 1995 through 1997 provided a total
of $474.9 million. During the years 1995 through 1997, the
Company retired $296.8 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 1998 through
2000, capital resources of $201 million ($52 million in 1998)
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 $805 million is
expected to be available from depreciation and amortization
charges and income tax deferrals over the three-year period of
which approximately $270 million is the 1998 portion.
In October 1997, the Company sold $175 million principal
amount of First Mortgage Bonds. Proceeds were applied to refund
short-term debt incurred to finance ongoing construction and
operating activities and to pay at maturity, in July and August
1997, $50 million principal amount of medium-term notes; and to
pay at maturity $50 million principal amount of First Mortgage
Bonds due February 15, 1998. 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.
Total annualized interest costs for all utility long-term
debt outstanding at December 31, 1997, was $132.6 million,
compared with $133 million and $127.9 million at December 31,
1996 and 1995, respectively.
The Company reduced its Maryland fuel rate by 9.5% effective
August 28, 1997. Included in the reduction was an adjustment for
a deferred fuel amortization charge to refund over a twelve month
period approximately $20.7 million of previously overrecovered
fuel costs incurred through June 30, 1997. The Maryland
14
Commission order approving the reduction became final on December
13, 1997. The Company expects to apply for an increase in the
Maryland fuel rate in early 1998.
Dividends on common stock were $196.6 million in 1997 and
1996 and $196.5 million in 1995. The Company's current annual
dividend on common stock is $1.66 per share. The dividend rate
is determined by the Company's Board of Directors and takes into
consideration, among other factors, current and possible future
developments which may affect the Company's income and cash flow
levels. Although the Company has no current plans to change the
dividend, there can be no assurance that the $1.66 dividend rate
will be in effect in the future.
Dividends on preferred stock were $16.6 million in 1997 and
1996 and $16.9 million in 1995. The embedded cost of preferred
stock was 6.44% at December 31, 1997, 6.41% at December 31, 1996
and 6.43% at December 31, 1995.
The Company's capitalization ratios (excluding nonutility
subsidiary debt), at December 31, 1997, are presented below.
- -----------------------------------------------------------------
Excluding Including
Amounts Due Amounts Due
In One Year In One Year
- -----------------------------------------------------------------
Long-term debt 47.2% 45.1%
Redeemable serial preferred stock 3.5 3.3
Serial preferred stock 3.1 3.0
Common equity 46.2 44.2
Short-term debt and amounts due in
one year - 4.4
----- -----
Total capitalization 100.0% 100.0%
===== =====
- -----------------------------------------------------------------
Year-end 1997 outstanding utility short-term indebtedness
totaled $131.4 million compared with $131.4 million and $258.5
million at the end of 1996 and 1995, respectively.
The Company maintains 100% line of credit back-up in the
amount of $180 million, for its outstanding commercial promissory
notes, which was unused during 1997, 1996 and 1995.
Conservation
- ------------
The Company's DSM and EUM programs 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. To reduce the near-term upward
15
pressure on customer rates and bills, the Company has, since
1994, phased out several conservation programs and reduced rebate
levels for others. 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.
In a June 1995 order, the District of Columbia Public
Service Commission adopted a DSM spending cap for the four-year
period 1995 through 1998. The Company continues to manage its
existing portfolio of DSM programs to ensure that the costs of
these programs do not exceed the spending limit. Remaining
allowable expenditures under the DSM spending cap totaled $10
million at December 31, 1997.
Investment in District of Columbia DSM programs totaled
approximately $5 million in 1997. These DSM 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 DSM costs prudently incurred since June 30,
1993; prior to this decision, DSM 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 CAA Amendments of
1990. The conservation component is scheduled to be updated
annually in the spring of each year, while the CAA component is
updated quarterly. In June 1997, the Company filed an
Application for Authority with the District of Columbia Public
Service Commission requesting approval for an updated
conservation component reflecting recoverable DSM costs expended
during 1995 and 1996. The Application, which superseded an
Application filed in June 1996, proposed a rate which would
increase annual revenue by approximately $9 million. No action
has been taken by the District of Columbia Public Service
Commission on the revised surcharge rate.
During 1997, the Company invested approximately $24 million
in Maryland DSM programs. The Company recovers the costs of
Maryland DSM programs through a base rate surcharge which
amortizes costs over a five-year period and permits the Company
to earn a return on its DSM investment while receiving
compensation for lost revenue. In addition, when energy savings
exceed annual goals, the Company earns a bonus. The Company was
awarded a bonus of $1.6 million in 1997, based on 1996
performance, which followed bonuses of $8.9 million in 1996,
based on 1995 performance, and $8.7 million in 1995, based on
1994 performance. Maryland DSM program goals for 1996 were
reduced to reflect lower DSM expenditures, consequently, the
performance bonus in 1997 was significantly lower than amounts
awarded for performance in prior years.
16
In 1997, approximately 160,000 customers participated in
continuing EUM 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 usage 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 derived from time-
of-use rates.
It is estimated that peak load reductions of nearly 725
megawatts have been achieved to date from DSM and EUM programs
and that additional peak load reductions of approximately 300
megawatts will be achieved in the next five years. The Company
also estimates that, in 1997, energy reductions of approximately
1.7 billion kilowatt-hours have been realized through operation
of its DSM and EUM programs. During the next five years, the
Company's projected costs for conservation programs that
encourage the efficient use of electric energy and reduce the
need to build new generating facilities total $136 million ($36
million in 1998).
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC and CCRF, totaled $217
million in 1997 and are projected to total $845 million for the
five-year period 1998 through 2002, which includes approximately
$75 million of CAA expenditures. In 1998, construction
expenditures are projected to total $175 million, which includes
$10 million of estimated CAA expenditures. The Company plans to
finance its construction program primarily through funds provided
by operations.
The Company has been purchasing energy from a 32-megawatt
municipally financed resource recovery facility in Montgomery
County, Maryland, which began commercial operation in August
1995. In November 1997, the Company agreed to purchase the 32-
megawatt rated capacity of the facility for the period November
1, 1997 to December 31, 1998. This purchase facilitated the sale
of 35 megawatts to NUSCO. In addition, the Company has a 25-year
agreement with Panda for a 230-megawatt gas-fueled combined-cycle
cogeneration project in Prince George's County, Maryland. This
facility achieved full commercial operation in October 1996. In
October 1997, the Company restructured its agreement with Panda
to resolve certain disputes regarding capacity and energy payment
rates for the facility. In exchange for an adjustment in
capacity payment rates and a reduction in the present value of
capacity payments over the term of the agreement, the Company
accrued a one-time payment to Panda of approximately $3.9 million
at December 31, 1997. Other features of the settlement allow
Panda to broker sales of certain amounts of the Company's system
capacity from January 1998 through May 2000, and to broker or
sell energy from the Panda facility. Panda will pay the Company
17
for the right to broker capacity sales, as well as a fee based on
actual energy sales. 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.
CLEAN AIR ACT
- -------------
The Company has implemented cost-effective plans for complying
with Phase I of the Acid Rain portion of the 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 installed 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 $73 million over the next five years. If economical,
continued use of lower-sulfur coal, cofiring with natural gas and
the purchase of sulfur dioxide (SO2) emission allowances is
expected. Nitrogen oxides emissions reductions will be achieved
by installing new boiler burner controls and equipment at the
Company's Dickerson Generating Station. In addition to the Acid
Rain portion of the CAA, the State of Maryland and District of
Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level
ozone. Further, the U.S. Environmental Protection Agency (EPA)
has issued proposed rules for reducing interstate transport of
ozone. These provisions are likely to result in further nitrogen
oxides emissions reductions from the Company's boilers; however,
the extent of reductions and associated costs cannot be predicted
at this time.
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
Phases I and II 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 is being 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
18
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 (decreases) which became
effective during the period 1995 through 1997 are shown below.
- -----------------------------------------------------------------
District
of
Year Total Maryland Columbia Wholesale
- -----------------------------------------------------------------
(Millions of Dollars)
1997 $24.0 $24.0 $ - $ -
1996 (2.0) - - (2.0)
1995 30.2 - 27.9 2.3
----- ----- ----- -----
$52.2 $24.0 $27.9 $ 0.3
===== ===== ===== =====
- -----------------------------------------------------------------
Maryland
- --------
On November 25, 1997, pursuant to a settlement agreement, the
Maryland Public Service Commission authorized a $24 million, or
2.6%, increase in base rate revenues effective with bills
rendered on and after November 30, 1997. Of the $24 million
increase in base rates, approximately $12 million will replace
CCRF accrued on CAA expenditures and, therefore, will have no
effect on future net income levels. The increased rates afford
the Company the opportunity to recover capacity costs associated
with the Panda agreement previously approved by the Maryland
Commission. Capacity payments to Panda commenced in January 1997
and totaled $25.3 million in 1997, of which the Maryland portion
was approximately $13 million. In connection with the settlement
agreement, no determination was made with respect to rate of
return for purposes of setting rates; however, a rate of return
of 9% will be used by the Company, beginning in December 1997,
for purposes of computing AFUDC and CCRF.
Effective June 6, 1997, the Maryland DSM surcharge tariff
was lowered, which will reduce annual revenues by approximately
$17 million, reflecting the Company's efforts to narrow
conservation program offerings and limit conservation spending.
The surcharge includes provisions for the recovery of lost
revenue, amortization of pre-1997 actual program expenditures
plus the initial amortization of 1997 projected program costs, a
CCRF on unamortized program balances and an incentive of $1.6
million awarded for achieving specified 1996 energy goals.
19
Previously, incentives of $8.9 million and $8.7 million were
awarded for achieving 1995 and 1994 energy goals, respectively.
Maryland energy goals for 1996 had been reduced to reflect lower
DSM expenditures, consequently, the performance bonus awarded in
1997 was lower than those awarded in prior years.
District of Columbia
- --------------------
The District of Columbia Public Service Commission authorized a
$27.9 million, or 3.8%, increase in base rate revenue effective
in July 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 DSM 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 DSM program expenditures, through a billing
surcharge. Costs will be amortized over 10 years, with a return
on unamortized amounts by means of a CCRF computed at the
authorized rate of return. The initial rate, which reflects
actual costs expended from July 1993 through December 1994,
resulted in additional annual revenue of approximately $15
million. 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. In June 1997, the
Company filed an Application for Authority with the Commission to
revise its ECRR. In the Application, which superseded an
Application filed in June 1996, the proposed rate seeks recovery
of actual costs expended during 1995 and 1996, and is expected to
increase annual revenue by approximately $9 million. No action
has been taken by the Commission on the revised ECRR. Subsequent
rate updates are scheduled to 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 for
the period 1995-1998 (amounts spent in excess of the annual
surcharge recovery limit, but within the four-year spending cap,
are deferred for future recovery). Remaining allowable
expenditures under the spending cap totaled $10 million at
December 31, 1997. Pre-July 1993 DSM costs receive base rate
treatment.
20
Wholesale
- ---------
The Company has a 10-year full service power supply contract with
the 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.
Pursuant to an agreement with SMECO for the years 1996 through
1998, a rate reduction of $2 million from the 1995 rate level
became effective January 1, 1996, and an additional $2.5 million
rate reduction became effective January 1, 1998. SMECO has
agreed not to give the Company a notice of reduction or
termination of service 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 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 EUM 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.
Pursuant to an August 1995 order in a generic proceeding
dealing with electric industry structure and the advent of
competition, the Maryland Public Service 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 with difficult-
to-find solutions.
In October 1996, the Maryland Commission reopened the
generic proceeding to review regulatory and competitive issues
affecting the electricity industry. The Commission cited the
evolving nature of the electric industry as the basis for
continuing its investigation. The Commission also directed its
Staff to submit a report containing, among other things,
recommendations regarding regulatory and competitive issues
facing the electric industry in Maryland. In May 1997, the
Commission Staff issued a report proposing a three-step process
21
for implementing customer choice, affording all Maryland
customers the option of choosing their supplier of electricity by
April, 2001.
On December 3, 1997, the Maryland Commission issued an Order
outlining steps toward a competitive electric generation market.
On December 31, 1997, the Commission issued a second Order that
established later dates for the phased-in implementation of
competition and also suspended all other dates in its December 3,
1997 Order, which scheduled various filings, hearings and
discussions concerning how competition would be implemented.
Pursuant to the revised order, competition will be phased in over
a two-year period beginning July 1, 2000. Customers representing
one-third of the electric load in a particular customer class
will be able to choose their electric generation supplier at that
time. On July 1, 2001, the eligible group increases to two-
thirds in any one customer class, and all customers will then
become eligible one year later.
Maryland utilities will be given the opportunity to recover
verifiable and prudently incurred stranded costs which cannot be
mitigated or reduced; utilities will be required to file a
breakdown of stranded costs including a proposed method for cost
recovery at a date to be set by the Commission. The Company has
not completed its analysis of possible stranded costs and
alternatives for mitigating or reducing such costs at the present
time. The Commission will consider proposals to establish a
competitive transition charge to address stranded costs. In
addition, the Commission recommended that the Maryland
legislature enact legislation to allow securitization of stranded
costs, where it can be shown that this financing procedure will
reduce costs for customers. Moreover, the Commission did not
order the divestiture or corporate unbundling of generating
assets; however, the Commission will consider these options as
part of its review of market power studies required to be filed
by Maryland electric utilities at a date to be set by the
Commission.
On January 2, 1998, the Company filed an application for
rehearing and clarification of the Commission's December 3, 1997
Order. It remains unclear whether the Commission has authority
to move forward without the explicit approval of the Maryland
legislature or whether full retail competition can occur without
Maryland legislative action concerning the many issues which are
integral to the Commission's plan. For example, the Commission
recognizes the need for tax reform to "level the playing field"
for Maryland utilities, and has requested the legislature to
enact the necessary legislation. Also, the Commission believes
that fuel adjustment clauses are incompatible with the workings
of a competitive generation market and has requested that
legislation be enacted to discontinue use of fuel adjustment
clauses in the future. Additionally, the Commission has
requested that the necessary legislation be enacted to permit
22
price cap regulation and to otherwise materially depart from cost
of service regulation with respect to the purchase and generation
of electricity. The Commission has not proposed any changes to
the form of regulation currently applicable to the recovery of
costs associated with the distribution of electricity.
Also, the Commission proposed the establishment of statewide
roundtables to address issues such as provision of metering and
billing services, consumer protection and DSM.
The Company reaffirms its full support for customer choice
for Maryland electric customers, and has provided key principles
to be used as guidelines for its introduction. These principles
include the concept that Maryland companies should not be put at
a competitive disadvantage by customer choice, that competition
should not be regulated, and that the benefits of customer choice
should not be oversold.
In late 1995 the District of Columbia Public Service
Commission initiated a proceeding to investigate issues regarding
electricity industry structure and competition. In September
1996, the Commission issued an order designating the issues to be
examined in the proceeding. Initial and reply comments regarding
the designated issues were filed with the Commission in early
1997. To date, no decisions have been rendered.
Based on the regulatory framework in which it operates, the
Company currently applies the provisions of Statement of
Financial Accounting Standards (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. 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. In addition, electric
plant in service includes a regulatory asset related to capital
leases, which are treated as operating leases for ratemaking
purposes, of approximately $29 million and $21 million at
December 31, 1997 and 1996, respectively.
Under traditional regulation, utilities were provided an
opportunity to earn a fair return on invested capital in exchange
for a commitment to serve all customers within a designated
service territory. To further the goal of providing universal
access to safe and reliable electric service within this
23
regulated environment, regulatory decisions led to costs and
commitments by utilities that may not be entirely recovered
through market-based revenues in a competitive environment.
Recovery and measurement of above-market, or "stranded" costs in
a future competitive environment, will be subject to regulatory
proceedings. Potential above-market costs include, but are not
limited to, costs associated with generation facilities that are
fixed and unavoidable, including future costs related to plant
removal; above-market costs associated with purchase power
obligations; and regulatory assets and obligations incurred in
accordance with SFAS No. 71. The Company fully expects to be
provided an opportunity to recover its stranded costs.
RESTRUCTURING OF THE BULK POWER MARKET
- --------------------------------------
In April 1996, the FERC issued its Final Rulemaking Orders No.
888 and No. 889. Both rulemakings address achieving greater
competition in the wholesale energy market through open access to
transmission on a comparable basis. The Commission required that
power pools such as PJM must also comply with these Orders.
Order No. 888 required utilities to file open access transmission
tariffs. Order No. 889 directed utilities to establish or
participate in an Open Access Same-Time Information System
(OASIS) where transmission owners post certain transmission
availability, pricing and service information on an open-access
communications medium such as the Internet. On January 3, 1997,
the Company's OASIS became operational. Subsequently, on April
1, 1997, PJM implemented an OASIS on behalf of the PJM
transmission owners which replaced the Company's OASIS. Order
No. 889 also required the Company to establish a code of conduct
that complies with FERC's prescribed standards to separate
utilities' transmission system operations and wholesale marketing
functions. The Company's filed code of conduct became effective
on January 3, 1997.
On November 25, 1997, FERC conditionally approved a PJM
restructuring plan, establishing an independent system operator
(ISO) to administer transmission service under a PJM control area
poolwide transmission tariff and provide open access transmission
service on a pool-wide basis. The ISO, which began operation on
January 1, 1998, is responsible for system operations and
regional transmission planning. In addition, the Commission
decided that the independent body that operates the ISO may also
operate the PJM power exchange. The Commission approved the
plan's use of single, non-pancaked transmission rates to access
the eight transmission systems which make up PJM. Each
transmission owner within PJM has its own transmission rate,
whereby the transmission customer will pay a single rate based on
the cost of the transmission system where the generating capacity
is delivered. This PJM rate design has been in effect since
April, 1997. The Commission also approved, effective April 1,
1998, locational marginal pricing for allocating scarce
24
transmission capability. This method is based on price
differences in energy at the various locations on the
transmission system. The Company was instrumental in pursuing
this restructuring plan.
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. The PJM members have
transformed the previous coordinated cost-based pool dispatch
into a bid-based regional energy market operating under a
standard of transmission service comparability. Benefits and/or
costs derived from the PJM market are passed through to the
Company's customers through fuel adjustment clauses and,
accordingly, will not have a material effect on the operating
results of the Company.
NEW ACCOUNTING STANDARDS
- ------------------------
See the discussion included in Note (1) of the Notes to
Consolidated Financial Statements, Summary of Significant
Accounting Policies.
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 1997, the
Company participated 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.
25
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's earnings for 1997 were $17.1 million ($.14 per share),
compared with net earnings of $16.9 million ($.14 per share) in
1996 and a net loss of $124.4 million ($1.05 per share) in 1995.
During 1997, PCI sold its remaining aircraft held for disposal,
resulting in a $2 million pre-tax ($1.3 million after-tax) charge
to earnings. As a result of joint venture operations during
1997, PCI's obligation for previously accrued deferred income
taxes was reduced, resulting in after-tax earnings of $7.4
million after provision for transaction costs. PCI's earnings
for 1997 also include capital gains totaling $4.5 million, net of
tax, related primarily to tender offers accepted by PCI which
reduced the cost basis of its preferred stock portfolio by $83
million since year end 1996. Proceeds were used to pay down debt
which resulted in a decrease in interest expense from 1996.
On December 18, 1997, PCI and RCN Telecom Services, Inc.
(RCN) of Princeton, New Jersey signed the definitive agreements
forming a joint venture known as Starpower Communications, L.L.C.
to provide a package of local and long distance telephone, cable
television, high speed Internet and other telecommunications
services to residents and businesses in the Washington, D.C./
Baltimore/Northern Virginia metropolitan region. The joint
venture is equally owned and managed by PCI and RCN. PCI and RCN
each will invest up to $150 million over a three-year period to
build out, market and provide these services over an advanced
fiber optic network. PCI's investment in the joint venture will
be funded through cash from operations and borrowings under its
Medium-Term Note facility. PCI expects that the joint venture
will incur operating losses initially, as it develops and expands
its network and customer base. Start-up costs incurred by PCI
relating to the telecommunications business have been expensed.
In 1997, PCI generated income primarily from its leasing
activities and securities investments. Income from leasing
activity, which includes rental income, gains on asset sales,
interest income and fees totaled $75.6 million in 1997, compared
to $91.7 million in 1996 and $100.6 million in 1995. The
decrease in income from leasing activity during 1997 was
primarily due to aircraft sales, resulting in lower rental
income. The decrease in 1996 compared to 1995 was primarily the
result of non-recurring fee income earned in 1995. PCI's
marketable securities portfolio contributed pre-tax income of
$28.6 million in 1997, $33.7 million in 1996 and $36.1 million in
1995. The decreases in income from marketable securities were
primarily due to decreases in dividend income as a result of
26
reductions in the preferred stock portfolio since 1995. Income
from marketable securities included net realized gains of $6.9
million in 1997, $3.6 million in 1996 and $.4 million in 1995.
Other income totaled $20.9 million in 1997 compared with a
loss of $10.4 million in 1996 and a loss of $2.3 million in 1995.
The increase in other income for 1997 was primarily the result of
$22.5 million in revenue earned from investments made by PEPCO
Enterprises, Inc. (PEI), a wholly-owned operating subsidiary
which the Company contributed to PCI in the second quarter of
1996. Through PEI, PCI has business interests and investments in
the energy industry, including liquefied natural gas peak storage
and pipeline facilities, and an underground cable construction
and maintenance company. PCI's other principal operating
subsidiaries are Pepco Communications L.L.C., which targets the
telecommunications business sector and holds a 50% interest in
Starpower Communications, and Pepco Services, Inc. which is an
energy services company primarily targeting large commercial and
industrial energy users inside and outside PEPCO's retail service
territory. Other income also includes pre-tax writedowns of $29
million ($18.8 million after-tax) taken in 1996 related to PCI's
investments in solar energy projects, real estate and oil and
natural gas, and pre-tax writedowns taken in the fourth quarter
1997 related to real estate of $10 million ($6.5 million after-
tax).
Expenses before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $139.9 million, $152.7 million and $344.6
million for years ended 1997, 1996 and 1995, respectively. The
decrease in expenses before income taxes for 1997 compared to
1996 and 1995 was primarily due to a $2 million pre-tax loss on
assets held for disposal in 1997 compared to a $12.7 million pre-
tax loss in 1996 and a $170.1 million pre-tax loss in 1995.
Interest expense also decreased over the three-year period due to
a decrease in debt outstanding as proceeds from the sales of
aircraft and marketable securities were used to pay down debt.
The decrease in expenses before income taxes in 1997 was
partially offset by operating expenses of $21.8 million for PEI
and other new business entities.
PCI had income tax credits of $31.9 million in 1997, $54.6
million in 1996 and $85.7 million in 1995. The decrease in
income tax credits was primarily due to the $170.1 million
aircraft writedown taken in May 1995 and deferred tax reversals
of $30.8 million in 1996 compared to $10.1 million of deferred
tax reversals in 1997.
27
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
PCI has a $302.5 million securities portfolio, consisting
primarily of fixed-rate electric utility preferred stocks.
During 1997, PCI reduced the cost basis of its marketable
securities portfolio by $83 million primarily as the result of
calls and acceptance of tender offers (approximately $118.1
million) offset by purchases of $35.1 million. The reduced size
of the preferred stock portfolio lessens the impact of future
fluctuations in interest rates. Proceeds from securities
activity during 1997 were used to pay down short-term debt.
During the first quarter of 1997, PCI received $25.8 million in
cash proceeds from the sale of notes receivable from World
Airways and recorded an after-tax charge to earnings of $.4
million. PCI also received $15.7 million in cash proceeds for
the early redemption of a note receivable related to the 1996
sale of an aircraft engine leasing subsidiary. During the third
quarter of 1997, PCI received $12.9 million for the sale of notes
receivable from Continental Airlines and recorded an after-tax
gain of $.9 million. The sale and early redemption of the notes
further reduce PCI's exposure to the ongoing credit risk
associated with the airline industry as well as the inherent
uncertainty regarding the future value of the aircraft which
secured the repayment of the notes.
PCI had short-term debt outstanding of $7.7 million at
December 31, 1997, compared to $51.7 million at December 31,
1996. During 1997, PCI issued $40 million in long-term debt,
including non-recourse debt, and debt repayments totaled $205.8
million. At December 31, 1997, PCI had $196 million available
under its Medium-Term Note Program and $400 million of unused
bank credit lines.
28
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 subsidiary at December
31, 1997 and 1996, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 1997, 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 16, 1998
29
<TABLE>
Consolidated Statements of Earnings
Potomac Electric Power Company and Subsidiary
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
For the year ended December 31,
1997 1996 1995
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Revenue (Note 2)
Operating revenue $ 1,810,829 $ 1,834,857 $ 1,822,432
Interchange deliveries 52,681 175,454 53,670
----------- ----------- -----------
Total Revenue 1,863,510 2,010,311 1,876,102
----------- ----------- -----------
Operating Expenses
Fuel 319,619 327,792 355,453
Purchased energy 200,562 335,978 193,592
----------- ----------- -----------
Fuel and purchased energy 520,181 663,770 549,045
Capacity purchase payments (Note 13) 150,912 125,786 125,769
Other operation 220,289 223,326 224,030
Maintenance 95,252 91,524 92,859
Depreciation and amortization 232,042 223,016 205,490
Income taxes (Note 4) 117,731 134,085 128,460
Other taxes (Note 5) 201,720 200,365 202,708
----------- ----------- -----------
Total Operating Expenses 1,538,127 1,661,872 1,528,361
----------- ----------- -----------
Operating Income 325,383 348,439 347,741
----------- ----------- -----------
Other (Loss) Income
Nonutility subsidiary (Note 15)
Income 125,140 114,966 134,493
Loss on assets held for disposal (2,022) (12,744) (170,078)
Expenses, including interest and income taxes (106,037) (85,328) (88,812)
----------- ----------- -----------
Net earnings (loss) from nonutility subsidiary 17,081 16,894 (124,397)
Allowance for other funds used during construction
and capital cost recovery factor 6,708 6,572 6,155
Write-off of merger costs (Note 13) (52,533) - -
Other, net 24,021 4,458 682
----------- ----------- -----------
Total Other (Loss) Income (4,723) 27,924 (117,560)
----------- ----------- -----------
Income Before Utility Interest Charges 320,660 376,363 230,181
----------- ----------- -----------
Utility Interest Charges
Interest on debt 146,703 146,939 146,558
Allowance for borrowed funds used during construction
and capital cost recovery factor (7,873) (7,536) (10,768)
----------- ----------- -----------
Net Utility Interest Charges 138,830 139,403 135,790
----------- ----------- -----------
Net Income 181,830 236,960 94,391
Dividends on Preferred Stock 16,579 16,604 16,851
----------- ----------- -----------
Earnings for Common Stock $ 165,251 $ 220,356 $ 77,540
=========== =========== ===========
Earnings Per Common Share (Note 7) $1.39 $1.86 $.65
Fully Diluted Earnings Per Common Share (Note 7) $1.38 $1.82 $.65
Cash Dividends Per Common Share $1.66 $1.66 $1.66
30
</TABLE>
<TABLE>
Consolidated Balance Sheets
Potomac Electric Power Company and Subsidiary
<CAPTION>
- ---------------------------------------------------------------------------------------------
December 31,
Assets 1997 1996
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Property and Plant - at original cost (Notes 6 and 10)
Electric plant in service $ 6,392,750 $ 6,232,049
Construction work in progress 94,309 62,469
Electric plant held for future use 4,231 4,152
Nonoperating property 22,824 22,921
----------- -----------
6,514,114 6,321,591
Accumulated depreciation (2,027,780) (1,898,342)
----------- -----------
Net Property and Plant 4,486,334 4,423,249
----------- -----------
Current Assets
Cash and cash equivalents 5,630 2,174
Customer accounts receivable, less allowance for uncollectible
accounts of $2,102 and $1,298 116,554 128,600
Other accounts receivable, less allowance for uncollectible
accounts of $300 32,256 38,490
Accrued unbilled revenue (Note 1) 69,259 70,214
Prepaid taxes 33,740 34,202
Other prepaid expenses 7,599 4,613
Material and supplies - at average cost
Fuel 59,434 68,232
Construction and maintenance 68,128 69,541
----------- -----------
Total Current Assets 392,600 416,066
----------- -----------
Deferred Charges
Income taxes recoverable through future rates, net (Note 4) 238,125 238,467
Conservation costs, net 221,528 233,793
Unamortized debt reacquisition costs 52,745 55,552
Other 148,900 159,139
----------- -----------
Total Deferred Charges 661,298 686,951
----------- -----------
Nonutility Subsidiary Assets
Cash and cash equivalents 422 804
Marketable securities (Notes 11 and 15) 302,522 377,237
Investment in finance leases (Note 15) 463,592 484,972
Operating lease equipment, net of accumulated depreciation
of $153,541 and $117,705 (Note 15) 163,289 199,124
Assets held for disposal - 10,300
Receivables, less allowance for uncollectible
accounts of $6,000 64,243 87,745
Other investments 162,865 193,002
Other assets 10,392 12,436
----------- -----------
Total Nonutility Subsidiary Assets 1,167,325 1,365,620
----------- -----------
Total Assets $ 6,707,557 $ 6,891,886
=========== ===========
31
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
December 31,
Capitalization and Liabilities 1997 1996
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Capitalization
Common equity (Note 7)
Common stock, $1 par value - authorized 200,000,000 shares,
issued 118,500,891 and 118,500,037 shares $ 118,501 $ 118,500
Premium on stock and other capital contributions 1,025,167 1,025,187
Capital stock expense (14,958) (14,780)
Retained income 734,318 760,285
----------- -----------
Total Common Equity 1,863,028 1,889,192
Preference stock, cumulative, $25 par value -
authorized 8,800,000 shares, no shares issued or outstanding - -
Serial preferred stock (Notes 8 and 11) 125,290 125,298
Redeemable serial preferred stock (Notes 9 and 11) 141,000 142,500
Long-term debt (Notes 10 and 11) 1,901,486 1,767,598
----------- -----------
Total Capitalization 4,030,804 3,924,588
----------- -----------
Other Non-Current Liabilities
Capital lease obligations (Note 13) 160,406 162,936
----------- -----------
Total Other Non-Current Liabilities 160,406 162,936
----------- -----------
Current Liabilities
Long-term debt and preferred stock redemption
due within one year 52,054 152,445
Short-term debt (Note 12) 131,375 131,390
Accounts payable and accrued payroll 118,428 117,810
Capital lease obligations due within one year 20,772 20,772
Taxes accrued 29,158 23,362
Interest accrued 38,307 38,117
Customer deposits 24,838 24,119
Other 67,455 59,016
----------- -----------
Total Current Liabilities 482,387 567,031
----------- -----------
Deferred Credits
Income taxes (Note 4) 1,029,318 973,642
Investment tax credits (Note 4) 57,308 60,958
Other 19,034 35,658
----------- -----------
Total Deferred Credits 1,105,660 1,070,258
----------- -----------
Nonutility Subsidiary Liabilities
Long-term debt (Notes 10 and 11) 830,458 996,232
Short-term notes payable (Note 12) 7,685 51,650
Deferred taxes and other (Note 4) 90,157 119,191
----------- -----------
Total Nonutility Subsidiary Liabilities 928,300 1,167,073
----------- -----------
Commitments and Contingencies (Note 13)
Total Capitalization and Liabilities $ 6,707,557 $ 6,891,886
=========== ===========
32
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
Potomac Electric Power Company and Subsidiary
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
For the year ended December 31,
1997 1996 1995
- -----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities
Income from utility operations $ 164,749 $ 220,066 $ 218,788
Adjustments to reconcile income to net cash
from operating activities:
Depreciation and amortization 232,042 223,016 205,490
Deferred income taxes and investment tax credits 60,544 81,496 51,774
Deferred conservation costs (34,543) (49,404) (104,796)
Allowance for funds used during construction
and capital cost recovery factor (14,581) (14,108) (16,923)
Changes in materials and supplies 10,211 (4,073) 12,418
Changes in accounts receivable and accrued unbilled revenue 19,235 10,539 (15,822)
Changes in accounts payable 6,388 13,624 (14,419)
Changes in other current assets and liabilities (2,459) 5,859 (1,484)
Changes in deferred merger costs 29,009 (24,213) (4,796)
Net other operating activities (54,836) (24,461) (40,868)
Nonutility subsidiary:
Net earnings (loss) 17,081 16,894 (124,397)
Deferred income taxes (63,759) (36,398) (49,697)
Loss on assets held for disposal 2,022 12,744 170,078
Changes in other assets and net other operating activities 63,716 36,258 83,509
----------- ----------- -----------
Net Cash From Operating Activities 434,819 467,839 368,855
----------- ----------- -----------
Investing Activities
Total investment in property and plant (231,744) (194,036) (230,675)
Allowance for funds used during construction
and capital cost recovery factor 14,581 14,108 16,923
----------- ----------- -----------
Net investment in property and plant (217,163) (179,928) (213,752)
Nonutility subsidiary:
Purchase of marketable securities (35,103) (19,680) (35,221)
Proceeds from sale or redemption of marketable securities 125,000 167,528 27,846
Investment in leased equipment (7,480) (3,056) (154,766)
Proceeds from sale or disposition of leased equipment 28,484 3,658 -
Proceeds from sale of assets 7,300 34,154 5,966
Purchase of other investments (20,603) (22,998) (3,818)
Proceeds from sale or distribution of other investments 18,730 33,867 15,614
Investment in promissory notes - (4,245) (7,955)
Proceeds from promissory notes 64,108 16,675 7,977
----------- ----------- -----------
Net Cash (Used by) From Investing Activities (36,727) 25,975 (358,109)
----------- ----------- -----------
Financing Activities
Dividends on common stock (196,615) (196,612) (196,469)
Dividends on preferred stock (16,579) (16,604) (16,851)
Issuance of common stock - - 4,580
Redemption of preferred stock (1,500) - (78)
Issuance of long-term debt 182,267 99,500 188,594
Reacquisition and retirement of long-term debt (151,462) (26,320) (117,465)
Short-term debt, net (15) (127,075) 68,865
Other financing activities (1,375) (5,358) (23,611)
Nonutility subsidiary:
Issuance of long-term debt 40,000 183,000 182,000
Repayment of long-term debt (205,774) (237,102) (275,021)
Short-term debt, net (43,965) (171,703) 174,950
----------- ----------- -----------
Net Cash Used by Financing Activities (395,018) (498,274) (10,506)
----------- ----------- -----------
Net Increase (Decrease) In Cash and Cash Equivalents 3,074 (4,460) 240
Cash and Cash Equivalents at Beginning of Year 2,978 7,438 7,198
----------- ----------- -----------
Cash and Cash Equivalents at End of Year (Note 14) $ 6,052 $ 2,978 $ 7,438
=========== =========== ===========
33
</TABLE>
Notes to Consolidated Financial Statements
- ------------------------------------------
(1) Summary of Significant Accounting Policies
------------------------------------------
Potomac Electric Power Company (the Company, PEPCO) 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), the Company's
wholly owned subsidiary, was formed in 1983 to provide a vehicle
to conduct the Company's ongoing nonutility investment programs
and businesses. Effective April 30, 1996, the Company
reorganized its nonutility subsidiaries whereby PEPCO
Enterprises, Inc. became a subsidiary of PCI. 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 is also involved
with activities, through its subsidiaries, which provide
telecommunication and energy services. In addition, PCI 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 the Statement of Financial Accounting
Standards (SFAS) No. 71 entitled "Accounting for the Effects of
Certain Types of Regulation" in accounting for capital leases and
for certain deferred charges and credits to be recognized in
future customer billings pursuant to regulatory authorization,
principally 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.
34
Certain prior year amounts have been reclassified to conform
to the current year presentation.
A description of significant accounting policies follows.
Principles of Consolidation
- ---------------------------
The consolidated financial statements combine the financial
results of the Company and 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 of energy, and resales of purchased energy, to
other utilities and to power marketers. 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 is scheduled to be updated annually on June 1 to
recover 1995 and subsequent conservation expenditures, including
a capital cost recovery factor (CCRF) to enable the Company to
earn a return on 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 CCRF,
35
incentives, applicable taxes and estimated lost revenue. The
Maryland surcharge is established annually in a collaborative
process with the recovery of lost revenue subject to a quarterly
earnings test.
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 1997, 1996 and 1995.
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. Unamortized conservation costs totaled
36
$82 million in Maryland and $140 million in the District of
Columbia at December 31, 1997, and $96 million in Maryland and
$138 million in the District of Columbia at December 31, 1996.
Allowance for Funds Used During Construction and Capital
Cost Recovery Factor
- --------------------------------------------------------
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
jurisdictional AFUDC capitalization rates are determined as
prescribed by the FERC. The effective capitalization rates were
approximately 7.6% in 1997, 7.4% in 1996 and 7.9% in 1995,
compounded semiannually.
In Maryland, the Company accrues a CCRF on the retail
jurisdictional portion of certain pollution control expenditures
related to compliance with the Clean Air Act (CAA). The base for
calculating this return is the amount by which the Maryland
jurisdictional CAA expenditure balance exceeds the CAA balance
being recovered in base rates. The CCRF rate for Maryland is 9%.
In the District of Columbia, the carrying costs of CAA
expenditures not in rate base are recovered through a base rate
surcharge.
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.
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.
37
New Accounting Standards
- ------------------------
Effective December 31, 1997, the Company adopted SFAS No. 128
entitled "Earnings per Share" which was issued by the Financial
Accounting Standards Board (FASB) in February 1997. Although
SFAS No. 128 replaces the presentation of primary earnings per
share (EPS) with a presentation of basic EPS, it had no impact on
the calculation of the Company's EPS. SFAS No. 128 also requires
dual presentation of basic and diluted EPS on the face of the
statement of earnings and requires a reconciliation of the
numerator and denominator used in the basic and fully diluted EPS
computations. See the Notes to Consolidated Financial
Statements, (7) Common Equity.
SFAS No. 129 entitled "Disclosure of Information about
Capital Structure", issued by the FASB in February 1997, is also
effective for calendar year 1997 financial statements. SFAS No.
129 consolidates disclosures required by several existing
pronouncements. The Company's disclosures are already in
compliance with such pronouncements and, accordingly, SFAS No.
129 does not require any change to existing disclosures.
In June 1997, the FASB issued SFAS No. 130 entitled
"Reporting Comprehensive Income" which became effective January
1, 1998. SFAS No. 130 establishes standards for reporting and
display of comprehensive income and its components. All items
that are required to be recognized under accounting standards as
components of comprehensive income must be reported in a
financial statement that is displayed with the same prominence as
other financial statements. The Company's principal components
of comprehensive income are net income, and unrealized gains and
losses on marketable securities.
In June 1997, the FASB also issued SFAS No. 131 entitled
"Disclosures about Segments of an Enterprise and Related
Information" which will become effective for the Company's 1998
calendar year financial statements and will impact quarterly
reporting beginning in the first quarter of 1999. The Company
does not expect adoption of this pronouncement to have a
significant impact on its reporting and disclosure requirements.
38
(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 more
than 80 electric utilities, independent power producers, power
marketers, cooperatives and municipals which operate on a fully
integrated basis.
Total revenue for each year was comprised as shown below.
- -----------------------------------------------------------------
1997 1996 1995
--------------------------------------------------
Amount % Amount % Amount %
- -----------------------------------------------------------------
(Thousands of Dollars)
Sales of
Electricity
Residential $ 524,695 29.2 $ 548,108 30.1 $ 543,532 30.0
Commercial 851,375 47.3 852,497 46.7 848,892 46.8
U.S.
Government 249,341 13.9 250,422 13.7 252,144 13.9
D.C.
Government 51,089 2.8 51,565 2.8 52,105 2.9
Wholesale 123,300 6.8 122,149 6.7 117,117 6.4
---------- ----- --------- ----- ---------- -----
Total 1,799,800 100.0 1,824,741 100.0 1,813,790 100.0
===== ===== =====
Other electric
revenue 11,029 10,116 8,642
---------- ---------- ----------
Operating
revenue 1,810,829 1,834,857 1,822,432
Interchange
deliveries 52,681 175,454 53,670
---------- ---------- ----------
Total Revenue $1,863,510 $2,010,311 $1,876,102
========== ========== ==========
- -----------------------------------------------------------------
Sales of electricity include base rate revenue and fuel rate
revenue. Fuel rate revenue was $509.1 million in 1997, $521.9
million in 1996 and $526.6 million in 1995.
39
The Company's Maryland fuel rate is based on historical net
fuel, interchange and emission allowance costs and does not
include capacity costs associated with power purchases. 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 Company reduced its Maryland fuel rate by 9.5% effective
August 28, 1997. Included in the reduction was an adjustment for
a deferred fuel amortization charge to refund over a twelve month
period approximately $20.7 million of previously overrecovered
fuel costs incurred through June 30, 1997. The Maryland
Commission order approving the reduction became final on December
13, 1997.
The District of Columbia fuel rate is based upon an average
of historical and projected net fuel, net interchange, emission
allowance costs and purchased capacity net of capacity sales, 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 net
interchange costs for each billing month. The difference between
the estimated costs and the actual applicable fuel and net
interchange costs incurred each month is reflected as an
adjustment to the fuel rate in the succeeding month.
Interchange deliveries include power sales tariff
transactions, predominantly those where the Company buys energy
from one party for the purpose of selling that energy to a third
party. The benefits derived from 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 subsidiary. 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 $11.6 million in
1997, $14.2 million in 1996 and $13.9 million in 1995. The net
periodic pension cost was computed as follows.
- -----------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------
(Thousands of Dollars)
Service cost-benefits earned $11,400 $11,400 $ 9,900
Interest cost on projected
benefit obligation 32,400 30,600 28,400
Actual return on Program assets (64,900) (38,200) (51,900)
Differences between actual
and expected return on
Program assets and net
amortization 32,700 10,400 27,500
------- ------- -------
Pension cost $11,600 $14,200 $13,900
======= ======= =======
- ----------------------------------------------------------------
41
Program assets are stated at fair value and were comprised
of approximately 47% and 53% of cash equivalents and fixed income
investments and the balance in equity investments at December 31,
1997 and 1996, respectively. The following table sets forth the
Program's funded status and amounts included in Other Deferred
Charges on the Consolidated Balance Sheets.
- -----------------------------------------------------------------
1997 1996
- -----------------------------------------------------------------
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Program benefits:
Vested benefits $(364,200) $(322,000)
Nonvested benefits (49,300) (49,400)
--------- ---------
Accumulated benefit obligation $(413,500) $(371,400)
========= =========
Actuarial present value of projected
benefit obligation $(495,600) $(438,100)
Program assets at fair value 468,800 402,500
--------- ---------
Projected benefit obligation in excess of
Program assets (26,800) (35,600)
Unrecognized actuarial loss 77,400 68,700
Unrecognized prior service cost 13,500 14,900
Unrecognized net obligation at
January 1, 1987, being recognized
over 18 years 300 300
--------- ---------
Prepaid pension expense $ 64,400 $ 48,300
========= =========
- -----------------------------------------------------------------
Measurement of the actuarial present value of the projected
benefit obligation was based on assumed weighted average discount
rates of 7% and 7.5%, in 1997 and 1996, respectively. The
weighted average rate of increase in future compensation levels
was 4% in 1997 and 1996. The assumed long-term rate of return on
Program assets was 9% in 1997 and 1996. The Company also
sponsors defined contribution savings plans covering all eligible
employees. Under these plans, the Company makes contributions on
behalf of participants. Company contributions to the plans
totaled $6 million in 1997, 1996 and 1995.
42
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. Health maintenance organization arrangements are
available, or a 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
benefits of these plans if they retire under the provisions of
the Company's 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
$11.1 million, $10.9 million and $9 million in 1997, 1996 and
1995, respectively. The following table sets forth the
components of the postretirement expense.
- -----------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------
(Thousands of Dollars)
Service cost-benefits attributable
to service during the year $ 3,600 $ 2,800 $ 2,300
Interest cost on accumulated
postretirement benefit obligation 5,300 5,300 4,500
Actual loss (return) on plan assets (2,300) (1,300) (1,900)
Amortization of transition
obligation 2,100 2,100 2,100
Difference between actual and
expected return on plan assets
and net amortization 2,400 2,000 2,000
------- ------- -------
Net postretirement benefit cost $11,100 $10,900 $ 9,000
======= ======= =======
- -----------------------------------------------------------------
43
The following table sets forth the accumulated post-retirement
benefit obligation reconciled to the amounts recognized on the
Consolidated Balance Sheets.
- -----------------------------------------------------------------
1997 1996
- -----------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation to
Retirees and dependents $(44,000) $(44,100)
Active employees fully eligible (8,800) (7,900)
Active employees not fully
eligible (29,200) (21,100)
-------- --------
Total accumulated postretirement
benefit obligation (82,000) (73,100)
Plan assets at fair value 13,600 9,800
-------- --------
Accumulated postretirement benefit
obligation in excess of plan assets (68,400) (63,300)
Unrecognized transition obligation 31,600 33,700
Unrecognized actuarial loss 36,700 30,800
-------- --------
Prepaid (Accrued) postretirement
benefit cost $ (100) $ 1,200
======== ========
- -----------------------------------------------------------------
The Company's obligation at December 31, 1997 and 1996, was
based on a discount rate of 7% and 7.5%, respectively, and a
weighted average rate of increase in future compensation levels
of 4%. The assumed health-care cost trend rate is 7.0% which
declines to 5.5% after a three-year period. A one percentage
point increase in the health-care cost trend rate would increase
the Accumulated Postretirement Benefit Obligation by $4 million
to approximately $86 million and the sum of the service cost and
interest cost for 1997 by approximately $.7 million.
In January 1997 and 1996, the Company funded the 1997 and
1996 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 1998, the 1998 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 1997 and 1996.
44
<TABLE>
(4) Income Taxes
------------
The provisions 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
- ---------------------------
- -----------------------------------------------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility current tax expense
Federal $ 32,252 $ 47,235 $ 68,492
State and local 4,691 6,281 9,173
----------- --------- ---------
Total utility current tax expense 36,943 53,516 77,665
----------- --------- ---------
Utility deferred tax expense
Federal 56,278 74,762 48,339
State and local 7,916 10,383 7,084
Investment tax credits (3,650) (3,649) (3,649)
----------- --------- ---------
Total utility deferred tax expense 60,544 81,496 51,774
----------- --------- ---------
Total utility income tax expense 97,487 135,012 129,439
----------- --------- ---------
Nonutility subsidiary current tax expense
Federal 30,421 (18,252) (35,592)
Nonutility subsidiary deferred tax expense
Federal (62,271) (36,373) (50,116)
----------- --------- ---------
Total nonutility subsidiary income tax expense (credit) (31,850) (54,625) (85,708)
----------- --------- ---------
Total consolidated income tax expense 65,637 80,387 43,731
Income taxes included in other income (52,094) (53,698) (84,729)
----------- --------- ---------
Income taxes included in utility operating expenses $ 117,731 $ 134,085 $ 128,460
=========== ========= =========
45
</TABLE>
<TABLE>
<CAPTION>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
- -----------------------------------------------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Income before income taxes $ 247,500 $ 317,347 $ 138,122
=========== ========= =========
Utility income tax at federal statutory rate $ 91,783 $ 124,277 $ 121,879
Increases (decreases) resulting from
Depreciation 10,853 9,867 9,173
Removal costs (5,902) (3,574) (7,204)
Allowance for funds used during construction 859 691 595
Other (4,432) (3,117) (1,613)
State income taxes, net of federal effect 8,194 10,749 10,648
Tax credits (3,868) (3,881) (4,039)
----------- --------- ---------
Total utility income tax expense 97,487 135,012 129,439
----------- --------- ---------
Nonutility subsidiary income tax at federal statutory rate (5,169) (13,206) (73,537)
Increases (decreases) resulting from
Dividends received deduction (5,419) (7,114) (8,524)
Reversal of previously accrued deferred taxes (10,125) (30,804) -
Other (11,137) (3,501) (3,647)
----------- --------- ---------
Total nonutility subsidiary income tax expense (credit) (31,850) (54,625) (85,708)
----------- --------- ---------
Total consolidated income tax expense 65,637 80,387 43,731
Income taxes included in other income (52,094) (53,698) (84,729)
----------- --------- ---------
Income taxes included in utility operating expenses $ 117,731 $ 134,085 $ 128,460
=========== ========= =========
</TABLE>
<TABLE>
<CAPTION>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
At December 31,
------------------------
1997 1996
------------------------
(Thousands of Dollars)
<S> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax basis differences $ 869,343 $ 821,656
Rapid amortization of certified pollution control
facilities 25,445 24,816
Deferred taxes on amounts to be collected through
future rates 90,154 90,284
Property taxes 13,525 12,664
Deferred fuel (7,369) (14,663)
Prepayment premium on debt retirement 19,962 21,025
Deferred investment tax credit (21,697) (23,079)
Contributions in aid of construction (30,054) (28,719)
Contributions to pension plan 18,157 16,170
Conservation costs (demand side management) 48,041 41,106
Other 21,683 21,653
----------- ---------
Total utility deferred tax liabilities (net) 1,047,190 982,913
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 17,872 9,271
----------- ---------
Total utility deferred tax liabilities (net) - noncurrent $ 1,029,318 $ 973,642
=========== =========
Nonutility subsidiary deferred tax liabilities (assets)
Finance leases $ 119,448 $ 144,667
Operating leases 28,823 57,006
Reversal of previously accrued taxes related
to partnerships (5,215) (7,455)
Alternative minimum tax (97,109) (97,109)
Other (45,732) (36,041)
----------- ---------
Total nonutility subsidiary deferred tax liabilities (net),
(included in Deferred taxes and other) $ 215 $ 61,068
=========== =========
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, 1997
and 1996.
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 subsidiary file a consolidated federal
income tax return. The Company's federal income tax liabilities
for all years through 1993 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.
(5) Other Taxes
-----------
Taxes, other than income taxes, charged to utility operating
expenses for each period are shown below.
- -----------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------
(Thousands of Dollars)
Gross receipts $ 95,753 $ 96,147 $ 95,158
Property 71,438 69,234 64,991
Payroll 10,469 10,673 11,269
County fuel-energy 15,448 15,448 21,887
Environmental, use and
other 8,612 8,863 9,403
-------- -------- --------
$201,720 $200,365 $202,708
======== ======== ========
- -----------------------------------------------------------------
47
(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. In 1997, the owners collectively
arranged for long-term tax-exempt financing, pursuant to an
agreement with the Indiana County Industrial Development
Authority relating to certain pollution control facilities
constructed at the Conemaugh Station. The Company's share of
this financing totaled $8.1 million. 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 $89.9 million at December 31, 1997, and
$88.7 million at December 31, 1996, includes $.3 million and $.7
million of Construction Work in Progress, respectively.
48
<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, 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
Net income before net earnings
from nonutility subsidiary - - - 220,066
Nonutility subsidiary:
Net earnings - - - 16,894
Marketable securities net
unrealized loss, net of tax - - - (5,755)
Dividends:
Preferred stock - - - (16,604)
Common stock - - - (196,612)
Conversion of preferred stock 3,239 3 25 -
Conversion of debentures 2,221 2 58 -
Other capital contributions - - 16 -
----------- ---------- ----------- ----------
Balance, December 31, 1996 118,500,037 118,500 1,025,187 760,285
Net income before net earnings
from nonutility subsidiary - - - 164,749
Nonutility subsidiary:
Net earnings - - - 17,081
Marketable securities net
unrealized gain, net of tax - - - 5,397
Dividends:
Preferred stock - - - (16,579)
Common stock - - - (196,615)
Conversion of preferred stock 854 1 6 -
Other capital contributions - - (26) -
----------- ---------- ----------- ----------
Balance, December 31, 1997 118,500,891 $ 118,501 $ 1,025,167 $ 734,318
=========== ========== =========== ==========
49
</TABLE>
<TABLE>
Reconciliations of the numerator and denominator for earnings per common
share and fully diluted earnings per common share are shown below.
<CAPTION>
------------- --------------- ---------
Income Shares Per Share
(Numerator) (Denominator) Amount
------------ -------------- ---------
(Thousands except Per Share Data)
<S> <C> <C> <C>
1995 Earnings Per Share Reconciliation:
Net income $94,391
Preferred dividends (16,851)
------------ -------------- ---------
Earnings per common share $77,540 118,412 $0.65
Convertible debentures - <F1> - <F1>
Convertible preferred stock 16 38
------------ -------------- ---------
Fully diluted earnings per common share $77,556 118,450 $0.65
============ ============== =========
1996 Earnings Per Share Reconciliation:
Net income $236,960
Preferred dividends (16,604)
------------ -------------- ---------
Earnings per common share $220,356 118,497 $1.86
Convertible debentures 6,416 5,811
Convertible preferred stock 15 35
------------ -------------- ---------
Fully diluted earnings per common share $226,787 124,343 $1.82
============ ============== =========
1997 Earnings Per Share Reconciliation:
Net income $181,830
Preferred dividends (16,579)
------------ -------------- ---------
Earnings per common share $165,251 118,500 $1.39
Convertible debentures 6,353 5,757
Convertible preferred stock 14 34
------------ -------------- ---------
Fully diluted earnings per common share $171,618 124,291 $1.38
============ ============== =========
<FN>
<F1> These amounts are not reflected in the computation of diluted EPS
because the effects are antidilutive and would increase diluted EPS.
</FN>
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, 1997, 35,046 shares of common stock were
reserved for issuance upon the conversion of convertible
preferred stock, 2,769,412 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.
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, 1997.
51
(8) Serial Preferred Stock
----------------------
The Company has authorized 11,095,501 shares of cumulative $50
par value Serial Preferred Stock. At December 31, 1997 and 1996,
there were outstanding 5,345,499 shares and 5,375,646 shares,
respectively. The various series of Serial Preferred Stock
outstanding [excluding 2,839,696 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 1997 1996
- -----------------------------------------------------------------
(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,
5,803 and 5,950 shares,
respectively $50.00 290 298
Auction Series A, 1,000,000 shares $50.00 50,000 50,000
-------- --------
$125,290 $125,298
======== ========
- -----------------------------------------------------------------
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,
1997, 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 147 shares in 1997, 556 shares in 1996 and 1,676 shares
in 1995.
Dividends on the Serial Preferred Stock, Auction Series A,
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 4.374% ($2.187) for the period December
1, 1997 through February 28, 1998. The average annual dividend
rates were 4.221% ($2.1105) in 1997 and 4.153% ($2.0765) in 1996.
52
(9) Redeemable Serial Preferred Stock
---------------------------------
The outstanding series of $50 par value Redeemable Serial
Preferred Stock are shown below.
- -----------------------------------------------------------------
December 31,
1997 1996
- -----------------------------------------------------------------
(Thousands of Dollars)
$3.37 Series of 1987, 839,696 and
869,696 shares $ 41,985 $ 43,485
$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
-------- --------
141,985 143,485
Redemption Requirement due within one
year (985) (985)
-------- --------
$141,000 $142,500
======== ========
- ----------------------------------------------------------------
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 $51.13, which is reduced to 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,
which 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 2002 with respect to
the Redeemable Serial Preferred Stock are $1 million in 1998,
$1.5 million annually in 1999 and 2000, $9.8 million in 2001 and
$12.3 million in 2002.
54
<TABLE>
(10) Long-Term Debt
<CAPTION>
Details of long-term debt are shown below.
- ------------------------------------------------------------------------------------------------------
Interest December 31,
Rate Maturity 1997 1996
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
First Mortgage Bonds
Fixed Rate Series:
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 100,000 100,000
6-1/4% October 15, 2007
PUT date October 15, 2004 175,000 -
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 16,000
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 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 1,516,800 1,341,800
Convertible Debentures
5% September 1, 2002 115,000 115,000
7% January 15, 2018 63,905 65,367
Medium-Term Notes
Fixed Rate Series:
6.66% to 6.73% May 1997 - 100,000
9.08% July and August 1997 - 50,000
6.53% December 17, 2001 100,000 100,000
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
Variable Rate Series:
Adjustable rate June 1, 2027 8,090 -
---------- ----------
Total Medium Term Notes 283,090 425,000
---------- ----------
Total Utility Long-Term Debt 1,978,795 1,947,167
Net unamortized discount (26,240) (28,109)
Current portion (51,069) (151,460)
---------- ----------
Net Utility Long-Term Debt $1,901,486 $1,767,598
========== ==========
Nonutility Subsidiary Long-Term Debt
Varying rates through 2011 $ 830,458 $ 996,232
========== ==========
55
</TABLE>
Utility Long-Term Debt
- ----------------------
The outstanding First Mortgage 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.
In October 1997, the Company issued $175 million principal
amount of 6-1/4% 10 PUT 7-Year First Mortgage Bonds maturing in
2007. Each new bond will be repayable on October 15, 2004, at
the option of the holder, at 100% of its principal amount,
together with accrued and unpaid interest. The proceeds were
used to refund short-term debt incurred to finance ongoing
construction and operating activities and to pay at maturity, in
July and August 1997, $50 million principal amount of medium-term
notes; and to pay at maturity $50 million principal amount of
First Mortgage Bonds due February 15, 1998.
The interest rate on the $50 million Adjustable Rate series
First Mortgage Bonds is adjusted annually on December 1, based
upon the 10-year "constant maturity" United States Treasury bond
rate for the preceding three-month period ended October 31, plus
a market based adjustment factor. Effective December 1, 1997,
the applicable interest rate is 7.38%. The applicable interest
rate was 7.867% at December 1, 1996, and 7.443% at December 1,
1995.
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, 1997, are $50 million in
1998, $45 million in 1999, $100 million in 2000, $165 million in
2001 and $190 million in 2002.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at December 31, 1997, consisted of $778.3 million
of recourse debt from institutional lenders maturing at various
dates between 1998 and 2003. The interest rates of such
borrowings ranged from 5% to 10.1%. The weighted average
interest rate was 7.48% at December 31, 1997, 7.44% at December
31, 1996, and 7.66% at December 31, 1995. Annual aggregate
principal repayments are $300.8 million in 1998, $170 million in
1999, $122.5 million in 2000, $71.5 million in 2001 and $93
million in 2002.
56
Long-term debt also includes $52.2 million of non-recourse
debt, $29.4 million of which is 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 $22.8 million is related to PCI's
majority-owned real estate partnerships of which $15.1 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 $7.7 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, 1997,
and 1996 are shown below.
<CAPTION>
- ------------------------------------------------------------------------------------------------
December 31,
1997 1996
- ------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Utility
Capitalization and Liabilities
Serial preferred stock $ 125,290 127,251 125,298 113,285
Redeemable serial
preferred stock $ 141,000 142,612 142,500 146,491
Long-term debt
First mortgage bonds $1,452,420 1,507,515 1,327,389 1,319,976
Medium-term notes $ 281,155 289,950 272,788 274,242
Convertible debentures $ 167,911 172,400 167,421 171,880
Nonutility Subsidiary
Assets
Marketable securities $ 302,522 302,522 377,237 377,237
Notes receivable $ 23,125 19,549 72,251 71,593
Liabilities
Long-term debt $ 830,458 840,974 996,232 1,011,814
- ------------------------------------------------------------------------------------------------
58
</TABLE>
The methods and assumptions below were used to estimate, at
December 31, 1997 and 1996, 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 Serial Preferred Stock,
including Redeemable Serial Preferred Stock, excluding amounts
due within one year, was based on quoted market prices or
discounted cash flows using current rates of preferred stock with
similar terms.
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 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 5.3% to 6.3%.
The Company maintains a minimum 100% line of credit back-up,
in the amount of $180 million, for its outstanding commercial
promissory notes, which was unused during 1997, 1996 and 1995.
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, in the amount of $400 million, for its
outstanding commercial promissory notes, which was unused during
1997, 1996 and 1995.
(13) Commitments and Contingencies
-----------------------------
Termination of Proposed Merger
- ------------------------------
On December 22, 1997, the Company and Baltimore Gas and Electric
Company announced the cancellation of their proposed merger (the
Merger) to create Constellation Energy Corporation. As a result,
the Company recorded a $52.5 million non-operating charge ($32.6
million net of income tax or 28 cents per share) to write off its
cumulative deferred Merger-related costs. At December 31, 1996,
deferred costs related to the Merger totaled $29 million and are
included in "Other Deferred Charges" on the Consolidated Balance
Sheet.
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 six 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 $17.1 million in
1997, $16.2 million in 1996 and $15.6 million in 1995. The
approximate annual commitments under all operating leases,
reduced by rentals to be received under subleases are $13.3
million in 1998, $7.7 million in 1999, $5.7 million in 2000, $4.3
million in 2001, $1.1 million in 2002 and a total of $5.1 million
in the years thereafter.
The Company leases its consolidated control center, an
integrated energy management system used by the Company's power
dispatchers to centrally control the operation of the Company's
generating units, transmission system and distribution system.
60
The lease 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. Accordingly, electric plant in
service includes a regulatory asset of approximately $21 million
and $14 million at December 31, 1997 and 1996, respectively.
Fuel Contracts
- --------------
The Company has numerous longer-term coal contracts, expiring
primarily in the period ranging from late-1998 to mid-1999, 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
1998. The Company will purchase the balance of its coal
requirements 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 Allegheny Energy, Inc. (AEI, formerly Allegheny Power
System) commenced June 1, 1987, and are expected to continue at
the 450 megawatt level through 2005. Under the terms of the
agreements with Ohio Edison and AEI, 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 Company also has a 25-year agreement with Panda
Brandywine, L.P. (Panda) for 230 megawatts of capacity supplied
by a gas-fueled combined-cycle cogenerator, which achieved full
commercial operation in October 1996. The Company began
purchasing energy from the Panda facility in August 1996 and
capacity payments under this agreement commenced in January 1997.
In November 1997, the Company agreed to purchase 32 megawatts of
capacity from the Montgomery County Resource Recovery Facility
for the period November 1, 1997 to December 31, 1998. This
purchase facilitated the sale of 35 megawatts of capacity to
Northeast Utilities Service Company. The capacity commitments
under these agreements, including a share of Ohio Edison's fixed
61
operating and maintenance cost, are estimated at $143 million for
1998, $198 million for 1999, $201 million for 2000, $207 million
for 2001 and 2002 and $1.4 billion in the years thereafter.
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
approximately $5.5 million per year. 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. Accordingly, electric plant in service includes a
regulatory asset of approximately $8 million and $7 million at
December 31, 1997 and 1996, respectively.
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.
On October 6, 1997, the Company received notice from the
U.S. Environmental Protection Agency (EPA) that it, along with 68
other parties, may be a Potentially Responsible Party (PRP) under
the Comprehensive Environmental Response Compensation and
Liability Act (CERCLA or Superfund) at the Butler Mine Tunnel
Superfund site in Pittstown Township, Luzerne County,
Pennsylvania. The site is a mine drainage tunnel with an outfall
on the Susquehanna River where oil waste was disposed via a
borehole in the tunnel. The letter notifying the Company of its
potential liability also contained a request for a reimbursement
of approximately $.8 million for response costs incurred by EPA
at the site. The letter requested that the Company submit a good
faith proposal to conduct or finance the remedial action
contained in a July 1996 Record of Decision (ROD). The EPA
estimates the present cost of the remedial action to be $3.7
million. 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.
62
In December 1995, the Company received notice from the EPA
that it is a PRP 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.
Evidence 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.
In October 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.
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
to the issuance of a ROD by the EPA, including legal fees, are
currently estimated to be $7.5 million. The Company has paid $.9
million as of December 31, 1997. The report included a number of
possible remedies, the estimated costs of which range from $2
million to $90 million. In July 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.
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
63
Case". The Company (and other defendants) were brought into
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 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 initial
filings in 1993, approximately 50 individual suits have been
filed against 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. Through December 31, 1997, approximately 400 of the
individual plaintiffs have dismissed their claims against the
Company. No payments were made by the Company in connection with
the dismissals. While the aggregate amount specified in the
remaining suits would exceed $400 million, 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.
64
Labor Agreement
- ---------------
In January 1998, the Company's current 1993 Labor Agreement with
Local 1900 of the International Brotherhood of Electrical Workers
(IBEW) was extended until June 1, 1999. This extension provides
for a 2.5% lump-sum payment to all members of Local 1900 upon
ratification of the agreement by the union. All other provisions
of the 1993 agreement remain the same.
(14) Supplemental Disclosure of Cash Flow Information
------------------------------------------------
Listed below is supplemental disclosure of cash flow information.
- -----------------------------------------------------------------
1997 1996 1995
- -----------------------------------------------------------------
(Thousands of Dollars)
Cash paid for:
Interest, net of capitalized
interest (including nonutility
subsidiary interest of $71,492,
$83,389 and $93,672) $202,754 $216,967 $223,789
Income taxes $ 12,475 $ 28,555 $ 44,725
- -----------------------------------------------------------------
For purposes of the consolidated financial statements, cash
and cash equivalents include cash on hand, money market funds and
commercial paper with original maturities of three months or
less.
65
(15) Selected Nonutility Subsidiary Financial Information
----------------------------------------------------
Selected financial information of the Company's consolidated,
wholly owned nonutility investment subsidiary, Potomac Capital
Investment Corporation (PCI) and its subsidiaries, is presented
below. Subsidiary equity at December 31, 1997, and December 31,
1996, was $227 million and $196.3 million, respectively. These
amounts include $6.5 million and $1.1 million of unrealized
appreciation, at December 31, 1997 and 1996, respectively,
relating to the marketable securities portfolio on an after-tax
basis.
- -----------------------------------------------------------------
For the year ended
December 31,
1997 1996 1995
- -----------------------------------------------------------------
(Thousands of Dollars)
Income
Leasing activities $ 75,584 $ 91,661 $ 100,640
Marketable securities 28,641 33,690 36,121
Other 20,915 (10,385) (2,268)
-------- --------- --------
125,140 114,966 134,493
-------- --------- --------
Expenses
Interest 68,959 83,442 91,637
Administrative and general 13,489 15,529 10,479
Depreciation and operating 55,439 40,982 72,404
Loss on assets held for
disposal 2,022 12,744 170,078
Income tax credit (31,850) (54,625) (85,708)
-------- --------- ---------
108,059 98,072 258,890
-------- --------- ---------
Net earnings (loss) from
nonutility subsidiary $ 17,081 $ 16,894 $(124,397)
======== ========= =========
66
Marketable Securities
- ---------------------
PCI's marketable securities, primarily preferred stocks with
mandatory redemption features, are classified as available-for-
sale for financial reporting purposes. Net unrealized gains or
losses on such securities are reflected, net of tax, in
stockholder's equity. The net unrealized gains (losses) on
marketable securities, which relate primarily to mandatory
redeemable preferred stock, are shown below:
December 31, December 31,
1997 1996
------------ ------------
(Thousands of Dollars)
Market value $302,522 $ 377,237
Cost 292,580 375,598
--------- ---------
Net unrealized gain $ 9,942 $ 1,639
========= =========
Included in net unrealized gains and losses are gross
unrealized gains of $13.9 million and gross unrealized losses of
$4 million at December 31, 1997, and gross unrealized gains of
$9.9 million and gross unrealized losses of $8.3 million at
December 31, 1996.
In determining gross realized gains and losses on sales or
maturities of securities, specific identification is used. Gross
realized gains were $7.5 million and $4.7 million for 1997 and
1996, respectively. Gross realized losses were $.6 million and
$1.1 million for 1997 and 1996, respectively.
At December 31, 1997, the contractual maturities for
mandatory redeemable preferred stock are $4.7 million within one
year, $118.8 million from one to five years, $81.4 million from
five to 10 years and $87.7 million for over 10 years.
67
Leasing Activities
- ------------------
PCI's net investment in finance leases is summarized below.
- -----------------------------------------------------------------
December 31,
1997 1996
- -----------------------------------------------------------------
(Thousands of Dollars)
Rents receivable $664,211 $711,961
Estimated residual values 87,965 102,590
Less: Unearned and deferred income (288,584) (329,579)
-------- --------
Investment in finance leases 463,592 484,972
Less: Deferred taxes arising from
finance leases (119,448) (144,667)
-------- --------
Net investment in finance leases $344,144 $340,305
======== ========
- -----------------------------------------------------------------
Minimum lease payments receivable from finance leases of
aircraft and generating facilities for each of the years 1998
through 2002 are $33 million, $34.5 million, $37.3 million, $36.7
million, and $34.9 million, respectively. Net income from
leveraged leases was $16.4 million in 1997, $22.5 million in 1996
and $11 million in 1995.
Rent payments receivable from aircraft equipment operating
leases for each of the years 1998 through 2002 are $37 million in
1998, $35.5 million in 1999, $30 million in 2000, $22.5 million
in 2001 and $3.5 million in 2002.
68
<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>
1997
Operating Revenue $ 374,486 439,555 618,218 378,570 1,810,829
Total Revenue $ 389,060 450,971 633,042 390,437 1,863,510
Operating Expenses $ 346,838 370,351 466,542 354,396 1,538,127
Operating Income $ 42,222 80,620 166,500 36,041 325,383
Net Income (Loss) $ 22,982 50,124 135,985 (27,261) 181,830
Earnings (Loss) for Common Stock $ 18,837 45,987 131,828 (31,401) 165,251
Earnings (Loss) per Common Share $ .16 .39 1.11 (.27) 1.39
Fully Diluted Earnings (Loss) per Common Share $ .16 .38 1.07 (.27) 1.38
Dividends per Share $ .415 .415 .415 .415 1.66
1996
Operating Revenue $ 385,272 462,705 614,357 372,523 1,834,857
Total Revenue $ 436,593 501,780 658,225 413,713 2,010,311
Operating Expenses $ 392,566 406,437 491,963 370,906 1,661,872
Operating Income $ 44,027 95,343 166,262 42,807 348,439
Net Income $ 14,734 72,253 138,687 11,286 236,960
Earnings for Common Stock $ 10,574 68,116 134,536 7,130 220,356
Earnings per Common Share $ .09 .57 1.14 .06 1.86
Fully Diluted Earnings per Common Share $ .09 .56 1.09 .06 1.82
Dividends per Share $ .415 .415 .415 .415 1.66
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
Fully Diluted (Loss) Earnings per Common Share $ (.07) (.52) 1.15 .04 .65
Dividends per Share $ .415 .415 .415 .415 1.66
The Company's sales of electric energy are seasonal and, accordingly,
comparisons by quarter within a year are not meaningful.
The totals of the four quarterly earnings per share and fully diluted
earnings per share may not equal the earnings per share and fully
diluted earnings per share for the year due to changes in the number of
common shares outstanding during the year and, with respect to the
fully diluted earnings per share, changes in the amount of dilutive
securities.
69
</TABLE>
<TABLE>
Stock Market Information
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1997 High Low 1996 High Low
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1st Quarter $26 $23-7/8 1st Quarter $27-3/8 $24-1/2
2nd Quarter $24-7/8 $21-1/8 2nd Quarter $26-5/8 $24-3/8
3rd Quarter $23-3/4 $21 3rd Quarter $26-3/4 $24
4th Quarter $26 $21 4th Quarter $27-3/8 $23-5/8
(Close $25-13/16) (Close $25-3/4)
Shareholders at December 31, 1997: 81,229
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993 1992 1987
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands except Per Share Data)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenue $1,810,829 1,834,857 1,822,432 1,790,600 1,702,442 1,562,167 1,332,109
Total Revenue $1,863,510 2,010,311 1,876,102 1,823,074 1,725,205 1,601,558 1,384,239
Operating Expenses $1,538,127 1,661,872 1,528,361 1,498,581 1,400,543 1,322,105 1,122,083
Net Earnings (Loss) from
Nonutility Subsidiary $ 17,081 16,894 (124,397) 19,088 25,101 28,161 32,150
Income Before Cumulative Effect of
Accounting change $ 181,830 236,960 94,391 227,162 241,579 200,760 208,222
Cumulative Effect of Accounting
Change, Net of Income Taxes $ - - - - - 16,022 -
Net Income $ 181,830 236,960 94,391 227,162 241,579 216,782 208,222
Earnings for Common Stock $ 165,251 220,356 77,540 210,725 225,324 202,390 199,175
Average Common Shares Outstanding 118,500 118,497 118,412 118,006 115,640 112,390 94,438
Earnings (Loss) Per Common Share
Utility Operations $ 1.25 <F2> 1.72 1.70 1.63 1.73 1.55 <F1> 1.77
Nonutility Subsidiary $ 0.14 .14 (1.05) .16 .22 .25 .34
Consolidated $ 1.39 1.86 .65 1.79 1.95 1.80 <F1> 2.11
Fully Diluted Earnings (Loss)
Per Common Share
Utility Operations $ 1.24 <F2> 1.69 1.70 1.60 1.70 1.54 <F1> 1.77
Nonutility Subsidiary $ 0.14 .13 (1.05) .15 .21 .24 .34
Consolidated $ 1.38 1.82 .65 1.75 1.91 1.78 <F1> 2.11
Cash Dividends Per Common Share $ 1.66 1.66 1.66 1.66 1.64 1.60 1.30
Investment in Property and Plant $6,514,114 6,321,591 6,161,103 5,974,170 5,701,550 5,404,265 3,699,957
Net Investment in Property
and Plant $4,486,334 4,423,249 4,400,311 4,334,399 4,167,551 3,967,898 2,678,921
Utility Assets $5,540,232 5,526,266 5,503,087 5,327,606 5,036,737 4,515,403 3,111,280
Nonutility Subsidiary Assets $1,167,325 1,365,620 1,615,063 1,674,289 1,665,132 1,663,508 598,688
Total Assets $6,707,557 6,891,886 7,118,150 7,001,895 6,701,869 6,178,911 3,709,968
Long-Term Utility Obligations
(including redeemable preferred
stock) $2,042,486 1,910,098 1,960,562 1,866,962 1,736,621 1,727,609 1,171,925
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<FN>
<F1>Includes $.14 as the cumulative effect of an accounting change for unbilled revenue.
<F2>Includes ($.28) as the net effect of the write-off of Merger costs.
</FN>
70
</TABLE>
