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 28, 1994
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) 872-2456
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.
99 The 1993 consolidated financial
statements of the Company and
Subsidiaries, together with the
report thereon of Price Waterhouse
dated January 21, 1994; and
Management's Discussion and
Analysis of Consolidated Results
of Operations and Financial
Condition as well as selected
financial data...................Filed herewith.
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned hereunto duly authorized.
Potomac Electric Power Company
(Registrant)
By /s/H. Lowell Davis
H. Lowell Davis
Vice Chairman and
Chief Financial Officer
January 28, 1994
DATE
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, excluding
the cumulative effect of the 1992 accounting change, before income
taxes, and the coverage of combined fixed charges and preferred
dividends for each of the years 1993 through 1991 on the basis of
parent company operations only, are as follows.
Year Ended Year
Ended Year Ended
December 31, December
31, December 31,
1993 1992
1991
------------
- ------------ ------------
<CAPTION>
<S> <C> <C>
<C>
Net income before cumulative effect
of accounting change $216,478,000
$172,599,000 $186,813,000
Taxes based on income 107,223,000
76,965,000 80,988,000
------------
- ------------ ------------
Income before taxes and cumulative effect
of accounting change 323,701,000
249,564,000 267,801,000
------------
- ------------ ------------
Fixed charges:
Interest charges 141,393,000
138,097,000 138,512,000
Interest factor in rentals 5,859,000
6,140,000 5,690,000
------------
- ------------ ------------
Total fixed charges 147,252,000
144,237,000 144,202,000
------------
- ------------ ------------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $470,953,000
$393,801,000 $412,003,000
============
============ ============
Coverage of fixed charges 3.20
2.73 2.86
====
==== ====
Preferred dividend requirements $16,255,000
$14,392,000 $12,298,000
------------
- ------------ ------------
Ratio of pre-tax income to net income 1.50
1.45 1.43
----
- ---- ----
Preferred dividend factor $24,383,000
$20,868,000 $17,586,000
------------
- ------------ ------------
Total fixed charges and preferred dividends $171,635,000
$165,105,000 $161,788,000
============
============ ============
Coverage of combined fixed charges
and preferred dividends 2.74
2.39 2.55
====
==== ====
</TABLE>
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, excluding
the cumulative effect of the 1992 accounting change, before income
taxes, and the coverage of combined fixed charges and preferred
dividends for each of the years 1990 and 1989 on the basis of
parent company operations only, are as follows.
Year Ended Year
Ended
December 31, December
31,
1990 1989
------------
- ------------
<CAPTION>
<S> <C> <C>
Net income before cumulative effect
of accounting change $165,199,000
$183,487,000
Taxes based on income 70,962,000
92,593,000
------------
- ------------
Income before taxes and cumulative effect
of accounting change 236,161,000
276,080,000
------------
- ------------
Fixed charges:
Interest charges 127,386,000
113,305,000
Interest factor in rentals 4,237,000
4,338,000
------------
- ------------
Total fixed charges 131,623,000
117,643,000
------------
- ------------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $367,784,000
$393,723,000
============
============
Coverage of fixed charges 2.79
3.35
====
====
Preferred dividend requirements $10,598,000
$9,235,000
------------
- ------------
Ratio of pre-tax income to net income 1.43
1.50
----
- ----
Preferred dividend factor $15,155,000
$13,853,000
------------
- ------------
Total fixed charges and preferred dividends $146,778,000
$131,496,000
============
============
Coverage of combined fixed charges
and preferred dividends 2.51
2.99
====
====
</TABLE>
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, excluding
the cumulative effect of the 1992 accounting change, before income
taxes, and the coverage of combined fixed charges and preferred
dividends for each of the years 1993 through 1991 on a fully
consolidated basis are as follows.
Year Ended Year
Ended Year Ended
December 31, December
31, December 31,
1993 1992
1991
------------
- ------------ ------------
<CAPTION>
<S> <C> <C>
<C>
Net income before cumulative effect
of accounting change $241,579,000
$200,760,000 $210,164,000
Taxes based on income 62,145,000
79,481,000 80,737,000
------------
- ------------ ------------
Income before taxes and cumulative effect
of accounting change 303,724,000
280,241,000 290,901,000
------------
- ------------ ------------
Fixed charges:
Interest charges 221,312,000
226,453,000 225,323,000
Interest factor in rentals 9,257,000
6,599,000 6,080,000
------------
- ------------ ------------
Total fixed charges 230,569,000
233,052,000 231,403,000
------------
- ------------ ------------
Nonutility subsidiary capitalized interest (2,059,000)
(2,200,000) (6,542,000)
------------
- ------------ ------------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $532,234,000
$511,093,000 $515,762,000
============
============ ============
Coverage of fixed charges 2.31
2.19 2.23
====
==== ====
Preferred dividend requirements $16,255,000
$14,392,000 $12,298,000
------------
- ------------ ------------
Ratio of pre-tax income to net income 1.26
1.40 1.38
----
- ---- ----
Preferred dividend factor $20,481,000
$20,149,000 $16,971,000
------------
- ------------ ------------
Total fixed charges and preferred dividends $251,050,000
$253,201,000 $248,374,000
============
============ ============
Coverage of combined fixed charges
and preferred dividends 2.12
2.02 2.08
====
==== ====
</TABLE>
<TABLE>
Item 7 Exhibit 12 Computation of Ratios
---------- ---------------------
The computations of the coverage of fixed charges, excluding
the cumulative effect of the 1992 accounting change, before income
taxes, and the coverage of combined fixed charges and preferred
dividends for each of the years 1990 and 1989 on a fully
consolidated basis are as follows.
Year Ended Year
Ended
December 31, December
31,
1990 1989
------------
- ------------
<CAPTION>
<S> <C> <C>
Net income before cumulative effect
of accounting change $170,234,000
$214,587,000
Taxes based on income 63,360,000
99,766,000
------------
- ------------
Income before taxes and cumulative effect
of accounting change 233,594,000
314,353,000
------------
- ------------
Fixed charges:
Interest charges 199,469,000
165,709,000
Interest factor in rentals 4,559,000
4,705,000
------------
- ------------
Total fixed charges 204,028,000
170,414,000
------------
- ------------
Nonutility subsidiary capitalized interest -
-
------------
- ------------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $437,622,000
$484,767,000
============
============
Coverage of fixed charges 2.14
2.84
====
====
Preferred dividend requirements $10,598,000
$9,235,000
------------
- ------------
Ratio of pre-tax income to net income 1.37
1.46
----
- ----
Preferred dividend factor $14,519,000
$13,483,000
------------
- ------------
Total fixed charges and preferred dividends $218,547,000
$183,897,000
============
============
Coverage of combined fixed charges
and preferred dividends 2.00
2.64
====
====
</TABLE>
Item 7
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Prospectuses constituting part of the Registration Statements
on Form S-8 (Number 33-36798) and on Form S-3 (Numbers 33-
48524, 33-58810 and 33-50377) of Potomac Electric Power
Company of our report dated January 21, 1994 appearing on
page 60 of Exhibit 99 of the Current Report on Form 8-K of
Potomac Electric Power Company dated January 28, 1994.
/s/ Price Waterhouse
Price Waterhouse
Washington, D.C.
January 28, 1994
Item 7
Exhibit 99
Financial Information
- ---------------------
Potomac Electric Power Company and Subsidiaries
Contents
- --------
Management's Discussion and Analysis of
Consolidated Results of Operations and
Financial Condition...................................... 2
Consolidated Statements of Earnings........................ 22
Consolidated Balance Sheets................................ 23
Consolidated Statements of Cash Flows...................... 25
Notes to Consolidated Financial Statements................. 26
Selected Consolidated Financial Data....................... 59
Report of Independent Accountants.......................... 60
1
Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
- ----------------------------------------------------
GENERAL
- -------
As an investor-owned electric utility, Potomac Electric Power
Company (the Company, PEPCO) 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 48% of the Company's total revenue
in 1993. Fuel and purchased energy, capacity purchase payments
and other operating expenses were 52% of total revenue. The
Company's principal wholly-owned subsidiary, Potomac Capital
Investment Corporation (PCI), conducts nonutility investment
programs with the objective of supplementing current utility
earnings and building long-term shareholder value.
The information set forth below discusses the results of
operations, capital resources and liquidity during the period
1991 through 1993 for the Company and PCI.
The Company's earnings for common stock during 1993 totaled
$225.3 million, as compared to $202.4 million in 1992. The 1992
earnings for common stock included the $16 million cumulative
effect of the accounting change for unbilled revenues. See the
discussion included in Note (1) of the Notes to Consolidated
Financial Statements, Summary of Significant Accounting Policies.
With a 1993 increase of 3.3 million in the average number of
common shares outstanding, earnings per share for common stock
increased from $1.80 in 1992 (including $.14 for the accounting
change) to $1.95 for 1993. Earnings for 1993 reflect the effect
on electricity sales and revenues of warmer than average weather
during the 1993 summer cooling season, and the effects of the
1992 and 1993 base rate increases in Maryland and the 1992 base
rate increase in the District of Columbia.
2
UTILITY
- -------
Results of Operations
- ---------------------
Total Revenue
- -------------
The changes in total revenue are shown in the following table.
- -----------------------------------------------------------------
Increase (Decrease)
from Prior Year
1993 1992 1991
- -----------------------------------------------------------------
(Millions of Dollars)
Change in kilowatt-hour sales $ 87.0 $(39.1) $ 61.1
Change in base rate revenues 45.4 71.8 51.2
Change in fuel adjustment clause
billings to cover cost of
fuel and interchange 8.0 (19.2) 22.5
Change in other revenue (.1) (3.4) 5.6
------ ----- -----
Change in Operating Revenue 140.3 10.1 140.4
------ ------ ------
Change in interchange deliveries (16.7) (27.9) (22.8)
------ ------ ------
Change in Total Revenue $123.6 $(17.8) $117.6
====== ====== ======
- -----------------------------------------------------------------
The $45.4 million change in 1993 base rate revenues compared
to 1992 reflects the effects of Maryland rate increases of $7.3
million (effective June 1993) and $27 million (effective November
1993) and the continued effect of 1992 rate increases in both of
the Company's retail jurisdictions. Also, 1993 revenues reflect
warmer than average weather during the summer billing months of
June through October, when base rates are high to encourage
customer conservation and peak load shifting. Base rate revenues
for 1992 compared to 1991 were increased by approximately $9
million from a gross receipts tax rate increase implemented in
the District of Columbia in July 1991, and in effect throughout
1992, and approximately $14 million from higher fuel and energy
taxes in Montgomery County, Maryland; also by a $30.4 million
District of Columbia rate increase (effective July 1992) and a
$25.3 million Maryland rate increase, of which $18 million became
effective in December 1992. Mild weather during the peak period
summer billing months June through October had an adverse effect
3
on 1992 revenues. Base rate revenues for 1991 compared to 1990
were increased by approximately $11 million as the result of a
higher gross receipts tax rate in the District of Columbia and
$12 million from higher fuel and energy taxes in Montgomery
County, Maryland; also by a $19.7 million Maryland rate increase
(effective June 1991) and by a $19.7 million District of Columbia
rate increase (effective October 1991). Decreases in revenue from
interchange deliveries for 1993, 1992 and 1991 reflect a decline
in energy delivered to the Pennsylvania-New Jersey-Maryland (PJM)
Interconnection. Interchange deliveries continue to be a
component of the Company's fuel rates.
Kilowatt-hour Sales
- -------------------
- -----------------------------------------------------------------
1993 1992
over over
1993 1992 1991 1992 1991
- ------------------------------------------------------- ---------
(Millions of Kilowatt-hours)
By Customer Type
Residential 6,727 6,142 6,488 9.5% (5.3)%
Commercial 11,751 11,391 11,321 3.2 .6
U.S. Government 3,986 3,948 4,016 1.0 (1.7)
D.C. Government 903 873 862 3.4 1.3
Wholesale 2,327 2,130 2,109 9.2 1.0
------ ------ ------
Total energy sales 25,694 24,484 24,796 4.9 (1.3)
====== ====== ======
Interchange
Energy deliveries 483 771 1,773 (37.4) (56.5)
====== ====== ======
By Geographic Area
Maryland, including
wholesale 15,319 14,441 14,601 6.1 (1.1)
District of Columbia 10,375 10,043 10,195 3.3 (1.5)
------ ------ ------
Total energy sales 25,694 24,484 24,796 4.9 (1.3)
====== ====== ======
- -----------------------------------------------------------------
The increase in kilowatt-hour sales in 1993 reflects
increased customer usage during the summer cooling season due to
warmer than average weather. Cooling degree hours during 1993
were 97% above those in 1992 and 22% above the 20-year average.
The decrease in kilowatt-hour sales in 1992, the first decline in
sales since 1974, was primarily due to decreased customer usage,
especially by residential customers, during the summer cooling
4
season due to cooler than average weather. Cooling degree hours
during the 1992 summer billing months (June through October) were
41% below the corresponding period in 1991 and 35% below the
20-year average weather for this period.
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 sales growth over the last three years is below the
previous rates of growth due to the effects of the recession on
the Company's service territory and the operation of the
Company's conservation and energy use management programs.
The Company's 1993 summer peak demand was 5,754 megawatts,
3.8% higher than the 1992 peak demand of 5,546 megawatts and .3%
below the all-time summer peak demand of 5,769 megawatts which
occurred in July 1991. The Company's present generation
capability, including capacity purchase contracts, is 6,576
megawatts. To meet the 1993 summer peak demand, the Company had
201 megawatts available from its dispatchable energy use
management programs. Based on average weather conditions, the
Company estimates that its peak demand will grow at a compound
annual rate of approximately 1%, reflecting continuing emphasis
on conservation and energy use management programs and
anticipated service area growth trends. A new winter peak demand
of 5,010 megawatts was established in January 1994, which was
11.1% above the previous all-time winter peak demand of 4,511
megawatts which occurred in December 1989.
Operating Expenses
- ------------------
Fuel, Purchased Energy and Capacity Purchase Payments
- -----------------------------------------------------
1993 1992 1991
- -----------------------------------------------------------------
(Millions of Dollars)
Fuel expense $354.3 $345.5 $387.1
------ ------ ------
Purchased energy
PJM receipts 108.9 94.6 62.9
Other purchases 64.5 72.0 113.6
------ ------ ------
Total purchased energy 173.4 166.6 176.5
------ ------ ------
Fuel and purchased energy $527.7 $512.1 $563.6
====== ====== ======
Capacity purchase payments $ 96.3 $ 95.5 $ 94.8
====== ====== ======
- -----------------------------------------------------------------
5
Net System Generation and Purchased Energy were as follows:
- -----------------------------------------------------------------
1993 1992 1991
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
Net system generation 19,145 18,274 20,296
====== ====== ======
Purchased energy 8,448 8,251 7,856
====== ====== ======
- -----------------------------------------------------------------
The 1993 increase in fuel expense primarily reflects a 4.8%
increase in net generation resulting from the increase in
kilowatt-hour sales. The Company's ability to purchase low-cost
economy energy from PJM helped keep the increase in fuel expense
to a minimum. The 1992 and 1991 decreases in fuel expense
primarily reflect decreases in net generation and increased
purchases of low-cost economy energy from PJM.
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)
1993 79.4 17.4 3.2 $1.72 $2.55 $2.88 $1.90
1992 82.9 12.6 4.5 1.72 2.50 2.32 1.85
1991 81.7 13.4 4.9 1.78 2.76 2.18 1.93
- -----------------------------------------------------------------
The system average unit fuel costs continued a generally
downward trend over the 1991-1993 period. The increase of
approximately 3% in the 1993 system average unit fuel cost
compared with the 1992 system average resulted from increased use
of major cycling and peaking generation units which burn higher
cost fuels. The Company's major cycling and certain peaking
units can burn natural gas or oil, adding flexibility in
selecting the most cost-effective fuel mix. In addition, the new
Dickerson combustion turbine units resulted in the displacement
of generation from older, less cost-effective units.
6
The Company's generating and transmission facilities are
interconnected with the other members of PJM and other utilities.
The pricing of most PJM internal economy energy transactions is
based upon "split savings" so that the price of such energy is
halfway between the cost that the purchaser would incur if the
energy were supplied by its own sources and the cost of
production to the company actually supplying the energy.
In addition to PJM interchange activity, the Company has
interconnection agreements with Allegheny Power System (APS) and
Virginia Power. These agreements provide a mechanism and the
flexibility to purchase power from these parties or from others
with whom they are interconnected on an as-needed basis in
amounts mutually agreed to from time-to-time pursuant to
negotiated rates, terms and conditions. "Other Purchases" above
includes the cost of this energy together with purchases of
energy from Ohio Edison under the Company's 1987 long-term
capacity purchase agreements with Ohio Edison and APS.
The capacity purchase payments referred to in the table
above include capacity costs incurred under agreements with Ohio
Edison and Southern Maryland Electric Cooperative, Inc. (SMECO),
which compare favorably with other long-term capacity and energy
alternatives.
Pursuant to the Company's long-term capacity purchase
agreements with Ohio Edison and APS, the Company is purchasing
450 megawatts of capacity and associated energy through the year
2005. The cost of capacity under these agreements increased from
$12,380 per megawatt, per month, in 1993 to $18,060 per megawatt,
per month, effective January 1, 1994, plus an allocation of fixed
operating and maintenance expenses, with provision for escalation
in 1999.
The Company began a 25-year purchase agreement in 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
capacity payment to SMECO is approximately $462,000 per month.
Other Operation and Maintenance Expenses
- ----------------------------------------
Other operation and maintenance expenses totaled $301.5 million
for 1993. These expenses increased by $6.2 million (2.1%), $8.1
million (2.8%) and $11.8 million (4.3%) in 1993, 1992 and 1991,
respectively. The relative stability in other operation and
maintenance expense was achieved through the Company's budget and
cost control disciplines, which have resulted in a decline in the
7
number of Company employees and other programs to curb increases
in expenses. For 1993, other operation expense included $9.3
million for the accrual of postretirement expenses other than
pensions, pursuant to Statement of Financial Accounting Standards
(SFAS) No. 106. See the discussion of New Accounting Standards
below.
Depreciation and Amortization Expense, Income Taxes and
Other Taxes
- -------------------------------------------------------
Depreciation and amortization expense increased by $13.8 million
(9.2%), $15.4 million (11.5%) and $10.5 million (8.5%) in 1993,
1992 and 1991, respectively, due to additional investment in
property and plant and amortization of increased amounts of
conservation program costs. Income taxes increased due to the
higher federal income tax rate which became effective in 1993 and
higher taxable income. Other taxes increased by $7.1 million
(3.6%), $27.7 million (16.6%) and $32.6 million (24.4%) in 1993,
1992 and 1991, respectively. The increases reflect changes in
the levels of operating revenues and plant investment upon which
taxes are based. The substantial 1992 and 1991 increases
resulted from increases in gross receipts and fuel and energy tax
rates.
Other Income, Net Utility Interest Charges and Allowance
for Funds Used During Construction
- --------------------------------------------------------
Other income reflects the net earnings from the Company's
nonutility subsidiary of $25.1 million in 1993, $28.2 million in
1992 and $23.4 million in 1991. See the Nonutility Subsidiary
discussion below and the discussion included in Note (14) of the
Notes to Consolidated Financial Statements, Selected Nonutility
Subsidiary Financial Information. Other income also reflects
accrued capital cost recovery factor amounts in "Other, net" of
$8 million and $2.9 million in 1993 and 1992, respectively, and
$2.8 million in 1993 from the adoption of SFAS No. 109. See the
discussion of New Accounting Standards below.
Net utility interest charges were relatively stable during
the three-year period 1991 through 1993, notwithstanding
increased levels of borrowing. Short-term borrowing costs have
remained relatively low and, with the refinancing of higher cost
issues, the average cost of outstanding long-term utility debt
declined from 8.24% at the beginning of 1991 to 7.68% at the end
of 1993. Allowance For Funds Used During Construction (AFUDC)
credits, which decreased in 1993 and 1992, and increased in 1991,
relate to portions of the Company's Construction Work In Progress
investment. See the Construction and Capacity Additions
discussion below.
8
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's total investment in property and plant, at original
cost, was $5.7 billion at year-end 1993. Investment in property
and plant construction, net of AFUDC, was $1 billion for the
period 1991 through 1993.
Internally generated cash from utility operations, after
dividends, totaled $287.8 million for the period 1991 through
1993. Sales of First Mortgage Bonds, Medium-Term Notes,
Convertible Debentures, Serial Preferred Stock and Common Stock
during the period 1991 through 1993 provided a total of $1.4
billion. During the years 1991 through 1993, the Company retired
$779.9 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 1994 through 1996, capital resources of $71
million 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 $735
million is expected to be available from depreciation and
amortization charges and income tax deferrals over the three-year
period.
During 1993, the Company sold $530 million principal amount
of First Mortgage Bonds, $96 million of Common Stock and short-
term borrowings increased by $233 million. Proceeds were used to
meet construction requirements of $300 million and scheduled debt
maturities, sinking fund requirements and the refinancing of
higher cost debt totaling $628.4 million. On January 12, 1994,
the Company sold, at par, $50 million of 6-1/4% Medium-Term Notes
due in 2009 and, at 98.494%, $50 million of 7% Medium-Term Notes
due in 2024. See the discussion included in Notes (7) and (10)
of the Notes to Consolidated Financial Statements, Common Equity
and Long-Term Debt, respectively, for details of these securities
transactions.
Reflecting the refinancings of debt and the respective
principal amounts outstanding, total annualized interest costs
for all utility long-term debt outstanding at December 31, 1993
was $114 million, compared with $131.9 million and $126.4 million
at December 31, 1992 and 1991, respectively.
Dividends on preferred stock were $16.3 million in 1993,
$14.4 million in 1992 and $12.3 million in 1991. The embedded
cost of preferred stock declined from 6.53% at December 31, 1990,
to 6.2% at December 31, 1993.
9
The Company's capitalization ratios (excluding nonutility
subsidiary debt), at December 31, 1993, are presented below.
- -----------------------------------------------------------------
Excluding Including
Amounts Due Amounts Due
In One Year In One Year
- -----------------------------------------------------------------
Long-term debt 41.7% 38.5%
Redeemable serial preferred stock 3.8 3.6
Serial preferred stock 3.3 3.0
Common equity 51.2 47.3
Short-term debt and amounts due in
one year - 7.6
----- -----
Total capitalization 100.0% 100.0%
===== =====
- -----------------------------------------------------------------
Year-end 1993 outstanding utility short-term indebtedness
totaled $294.6 million compared with $61.6 million and $86.8
million at the end of 1992 and 1991, respectively. At year-end
1993, the formula adopted by the Securities and Exchange
Commission would have permitted the Company to issue, without
registration, a total of $426 million in commercial promissory
notes.
The Company has, with respect to its utility operations, $90
million in revolving credit agreements with 11 banks and
conventional bank line of credit agreements of $215.5 million
with 21 banks. There were no outstanding borrowings under these
arrangements during 1993, 1992 and 1991.
Construction and Capacity Additions
- -----------------------------------
Construction expenditures, excluding AFUDC, are projected to
total $1.3 billion for the five-year period 1994 through 1998,
which includes $203 million of estimated Clean Air Act
expenditures. Making use of the flexibilities in its long-term
construction plan, the Company reduced projected expenditures for
the five years 1994 through 1998 by a total of $315 million from
amounts previously planned. The construction reductions and
deferrals were associated with lower rates of projected growth
in usage of electricity resulting in large part from implementing
economical conservation programs. The Company plans to finance
its construction program through funds provided by operations
and external financing.
10
On June 1, 1993, the Company placed in service the second
element of a combined-cycle unit, consisting of a 139-megawatt
combustion turbine generating unit, at the Dickerson Generating
Station located in Montgomery County, Maryland. The first 139-
megawatt combustion turbine generating unit was placed in service
on June 1, 1992. The total cost of the two combustion turbine
units currently in service was $162 million. These generating
units are primarily fueled by natural gas but can also burn No. 2
fuel oil. The Dickerson project plan provides for two
combined-cycle units with the capability of adding a coal
gasification facility, should future unit price differentials
among coal, oil and gas make gasification economically
attractive. The Company's construction schedule is flexible in
order to accommodate changes in future growth and the addition of
nonutility generation. Currently, no additional units are
scheduled for the Dickerson combined-cycle project until after
the year 2003.
In 1991, the Company signed an agreement with Panda Energy
Corporation for a 230-megawatt gas-fueled combined-cycle
cogeneration project in Prince George's County, Maryland, which
is scheduled for service in 1996. The project is currently
before the Maryland Public Service Commission for issuance of a
certificate of convenience and necessity. In addition, the
Company has signed a contract for a 40-megawatt resource recovery
facility which is now under construction in Montgomery County,
Maryland. In November 1993, after failing to obtain final
building permits from the District of Columbia, Dominion Energy
terminated its contract to build a 56-megawatt combined-cycle
cogeneration facility at Georgetown University. The Company
currently projects that contracted nonutility generation and the
Company's commitment to conservation and energy use management
will provide adequate reserve margins to meet customers' needs
for the next decade.
Although it is not possible to forecast specific impacts of
the National Energy Act legislation enacted during 1992, the
Company has substantial flexibility to anticipate and deal with
changing conditions and increased competition in the generation
and transmission of electricity. Since the early 1980s, the
Company has pursued strategies which achieve flexibility through
conservation and energy use management, extension of the useful
life of generating equipment, cost-effective purchase of capacity
and energy and preservation of scheduling flexibility to add new
generating capacity in relatively small increments to meet
changing requirements. The Company is a low-cost energy producer
with customer prices which compare favorably with regional and
national averages.
11
Conservation and Energy Use Management
- --------------------------------------
The Company's conservation and energy use management 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. The
Company offers an extensive array of comprehensive conservation
programs for its customers in the District of Columbia and
Maryland.
The Company's programs for residential customers include
various types of incentives to encourage the design of
energy-efficient homes and the purchase and installation of
energy-efficiency measures. These incentives include customer
rebates for energy efficient appliances, bonuses to contractors
who build homes that meet high energy-efficiency standards;
coupons which offer significant discounts to customers who
purchase energy-efficient lights and water heater conservation
measures and, commencing in 1993, a program to directly install,
at no cost to the customer, lighting and water heater tank wraps
in single-family, apartment and condominium residences. During
1993, the Company also initiated an appliance recycling program
for customers, by offering payments for inefficient, but still
functioning, refrigerators, air conditioners and freezers.
The Company's programs for commercial customers offer a
variety of approaches to encourage conservation, including design
consultation and technical assistance at no fee, equipment
rebates to developers and designers, cash incentives to customers
who install energy-efficiency measures ranging from lighting to
efficient motors and equipment, and, for small commercial
customers, direct installation of efficient lighting and other
measures at no-cost to the customer. During 1993, as part of the
Custom Rebate program, the Company encouraged customers with
older chillers to replace them with new high efficiency chillers.
Also, the Company began offering loans on a pilot basis to
commercial customers for efficiency improvements.
The Company continues to aggressively identify, design, and
test additional energy efficient conservation measures and
technologies.
The Company receives rate recognition for the cost of its
conservation programs in its Maryland jurisdiction through a rate
surcharge which permits the Company to earn a return on its
conservation investment while receiving compensation for lost
revenues. The cost recovery mechanism also allows the Company to
earn a performance bonus for exceeding established goals. The
surcharge is adjusted periodically to reflect the Company's
growing conservation commitment.
12
The District of Columbia Public Service Commission has
established a comprehensive framework which provides for a return
on conservation investments, the receipt of compensation for lost
revenues and incentives for achieving demand side management
goals. The Company has proposed, in connection with its pending
District of Columbia rate case, a surcharge mechanism similar to
the Maryland surcharge and, with respect to future lost revenues,
an adjustment mechanism which reconciles or decouples sales and
revenues.
During 1993, the Company also continued to operate and
expand its energy use management programs. In 1993,
approximately 134,000 customers participated in programs which
cycle air conditioners and water heaters during peak periods. In
addition, the Company operates a commercial load program which
provides incentives to customers for reducing energy use during
peak periods. Time-of-use rates have been in effect since the
early 1980s and currently approximately 60% of the Company's
revenues are based on time-of-use rates.
It is estimated that peak load reductions of approximately
390 megawatts have been achieved to date from conservation and
energy use management programs and that additional peak load
reductions of over 500 megawatts will be achieved in the next
five years. The Company also estimates that energy savings of
more than 450 million kilowatt-hours have been realized through
operation of its conservation and energy use management programs
through 1993. During the next five years, the Company plans to
expend an estimated $525 million to encourage the efficient use
of electric energy and to reduce the need to build new generating
facilities.
CLEAN AIR ACT
- -------------
The Company has developed cost-effective plans for complying with
the Clean Air Act (CAA) which requires the reduction of sulfur
dioxide and nitrogen oxides emissions in two phases to achieve
prescribed standards. The Company anticipates CAA related
capital expenditures totaling $203 million over the next five
years. The plans call for replacement of boiler burner equipment
for nitrogen oxides emissions control, the use of lower-sulfur
fuel and co-firing with natural gas at selected baseload plants.
The CAA allows companies to achieve required emission levels by
using a market-based emission allowance trading system. If
economical, emission allowances may be purchased in lieu of
burning lower-sulfur fuel.
13
The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located in western Pennsylvania. As a result
of installing flue gas scrubbing equipment to meet Phase I
requirements of the CAA, this station will receive additional
allowances. The Company's share of these "bonus" allowances may
be used to reduce the need for lower-sulfur fuel at its other
plants. The Company's share of the construction cost for the
flue gas scrubbing equipment is approximately $38 million.
Installation of scrubbers is not contemplated for the
Company's wholly-owned plants. Both the District of Columbia and
Maryland have approved the Company's plans for meeting Phase I
requirements including cost recovery of investment and inclusion
of emission allowance expenses in the Company's fuel adjustment
clause.
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;
however, the regulatory commissions are required by law to
provide a reasonable opportunity to earn a fair rate of return on
new plant investments which are required to replace existing
plant at the time replacement of facilities actually occurs. The
regulatory commissions have authorized fuel rates which provide
for billing customers for the actual cost of fuel and interchange
on a timely basis. The impact of inflation on the Company's
future results of operations cannot be projected since it will be
dependent, in part, on the timeliness of rate decisions and the
extent to which rate changes are based upon current costs of
providing service.
Annual base rate increases and decreases which became
effective during the period 1991 through 1993 are shown below.
- -----------------------------------------------------------------
District
of
Year Total Maryland Columbia Wholesale
- -----------------------------------------------------------------
(Millions of Dollars)
1993 $ 38.1 $34.3 $ - $3.8
1992 51.2 18.0 30.4 2.8
1991 38.9 19.7 19.7 (.5)
------ ----- ----- ----
$128.2 $72.0 $50.1 $6.1
====== ===== ===== ====
- -----------------------------------------------------------------
14
Maryland
- --------
In October 1993, pursuant to a settlement agreement, the
Commission authorized a $27 million, or 3%, increase in base rate
revenues effective November 1, 1993. The settlement included a
new system composite depreciation rate of approximately 3.1%, up
from the 3% rate previously in effect. Prior to the settlement,
the Company had filed updated cost of service data which
demonstrated a need for a $49.9 million increase in Maryland base
rate revenue, based upon the requested return of 9.89% on average
rate base including a 12.75% return on common stock equity, 1993
federal tax legislation and the completed separate depreciation
case. In connection with the settlement agreement, no
determination was made with respect to rate of return. The rate
of return on common stock equity most recently determined for the
Company in a fully litigated rate case was 12.75% established by
the Commission in a June 1991 rate increase order.
In October 1992, pursuant to a settlement agreement, the
Commission authorized an increase in base rate revenues of
approximately 3% with $18 million effective December 1, 1992, and
$7.3 million effective June 1, 1993. No determination with
respect to rate of return was specified.
District of Columbia
- --------------------
In its pending base rate proceeding, the Company is currently
seeking a $55.4 million, or 8.2%, increase in base rate revenue,
based upon a return of 9.46% on average rate base including an
11.8% return on common stock equity. On June 4, 1993, the
Company had filed a base rate application requesting a $72.6
million increase in base rate revenue based upon a requested
return of 9.84% on average rate base including a 12.35% return on
common stock equity. The Company updated its initial June 1993
cost of service data filing to reflect subsequent events such as
final federal tax legislation changes, the effects of a new three
year labor agreement with its union employees, the settlement of
the United Mine Workers strike as it related to the Company's
coal inventory, cost of service revisions and an updated cost of
capital study. The requested increase in annual base rate
revenues is predicated on adoption by the Commission of the
Company's ratemaking proposal with respect to the demand side
management program costs, including treatment of lost revenues.
If the Commission concludes that this item should also be
recovered in base rates, an additional $22.2 million must be
added to the base rate revenue requirement for a total requested
increase in base rate revenues of $77.6 million. Hearings have
been completed, final briefs have been filed and the case is
before the Commission for its decision, which is expected to be
issued near the end of February 1994.
15
In June 1992, the Commission authorized a $30.4 million, or
4.6%, increase in base rate revenues effective July 7, 1992. The
authorized rates were based on a 9.96% rate of return on average
rate base, including a 12.35% return on common stock equity.
The Commission also approved a procedure for deferring purchased
capacity cost increases between rate cases, accruing a return on
the deferred amounts, and including such deferred amounts in
determining revenue requirements in future rate proceedings. In
February 1993, the Commission adopted a surcharge mechanism, to
become effective following the Company's next base rate case
discussed above, for recovery of the capital cost carrying
charges on CAA compliance costs between rate proceedings. The
Company is authorized to accrue a capital cost recovery factor on
applicable CAA costs while the surcharge rate is effective.
Wholesale
- ---------
The Company has a 10-year full services power supply contract
with 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 $3.8 million and $2.8 million
effective January 1, 1993 and 1992, respectively.
In November 1993, the Company amended its contract with
SMECO to provide for rate increases of $2.6 million, $2.3 million
and $4.2 million effective January 1, 1994, 1995 and 1996,
respectively.
THE COVE POINT JOINT VENTURE
- ----------------------------
Subsidiaries of the Company and the Columbia Gas System, Inc.,
have formed a joint venture partnership to own and operate
natural gas storage and terminaling facilities at Cove Point,
Maryland, and an 87-mile natural gas pipeline that extends from
Cove Point to Loudoun, Virginia. These facilities are currently
owned by Columbia LNG Corporation, a Columbia Gas subsidiary.
In November 1993, the partnership filed a request with the
Federal Energy Regulatory Commission (FERC) for approval of
proposed natural gas peak-shaving services to local gas
distribution companies and other natural gas users beginning with
the winter heating season of 1995-96. With the recent
16
restructuring of the natural gas industry under FERC Order 636,
this price-competitive service will provide supply security and
operating flexibility to local distribution companies in meeting
their customers' service obligations.
One of the Company's principal strategic interests in the
Cove Point project is to secure a reliable and cost-effective
source of transportation for gas to fuel the generators at its
Chalk Point Generating Station. The Cove Point pipeline is the
sole means of delivering natural gas to southern Maryland where
Chalk Point is located. The Company is currently expanding Chalk
Point's fuel flexibility to burn increased amounts of gas to
comply with the CAA and minimize customer costs.
Under the agreement, Columbia LNG Corp. will contribute its
Cove Point terminal and pipeline assets in exchange for an equity
interest in the partnership, and the Company's subsidiaries will
invest up to $25 million in the form of equity and debt. This
investment will be used by the partnership to recommission
certain existing facilities at the terminal and construct a new
liquefaction unit that will be used in the peaking service. The
transaction is subject to Columbia's receipt of regulatory and
other approvals.
NEW ACCOUNTING STANDARDS
- ------------------------
Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 109 entitled
"Accounting for Income Taxes," and SFAS No. 106 entitled
"Employers' Accounting for Postretirement Benefits Other Than
Pensions." See the discussion included in Notes (1), (3) and (4)
of the Notes to Consolidated Financial Statements, Summary of
Significant Accounting Policies, Pensions and Other
Postretirement Benefits and Income Taxes, respectively.
In November 1992, the Financial Accounting Standards Board
(FASB) issued SFAS No. 112 entitled "Employers' Accounting for
Postemployment Benefits," which will become effective for the
Company's 1994 consolidated financial statements. See the
discussion included in Note (3) of the Notes to Consolidated
Financial Statements, Pensions and Other Postretirement Benefits,
for additional information.
In May 1993, the FASB issued SFAS No. 115 entitled
"Accounting for Certain Investments in Debt and Equity
Securities," which will also become effective for the Company's
1994 consolidated financial statements. See the discussion
included in Note (14) of the Notes to Consolidated Financial
Statements, Selected Nonutility Subsidiary Financial Information.
17
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 1993,
the Company was participating in environmental assessments and
cleanups under these laws at two federal Superfund sites and a
state site. 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.
In August 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 Cases." 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. Since the filings, a number of the individual suits
have been disposed of without any payment by the Company. While
the aggregate amount specified in the remaining suits would
exceed $1 billion, the Company believes the amounts are greatly
exaggerated as were the claims already disposed of. The amount
of total liability, if any, and any related insurance recovery
cannot be precisely determined at this time; however, based on
information and relevant circumstances known at this time, the
Company does not believe these suits will have a material adverse
effect on its financial position.
See the discussion included in Note (12) of the Notes to
Consolidated Financial Statements, Commitments and Contingencies,
for additional information.
18
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's net earnings totaled $25.1 million in 1993 compared with
$28.2 million in 1992 and $23.4 million in 1991. In 1993, PCI
contributed $.22 per share to PEPCO's consolidated earnings of
$1.95 per share. PCI contributed $.25, and $.22 per share to
PEPCO's 1992 and 1991 consolidated earnings per share,
respectively.
PCI generates income primarily from its leasing activities
and securities investments. Revenue from leasing activities,
which includes rental income, gains on asset sales, interest
income and fees, totaled $114.2 million in 1993 compared with
$122.1 million and $128.7 million in 1992 and 1991, respectively.
The decrease in income from leasing activities in 1993 as
compared to 1992 was due to decreased rental income from
operating leases which replaced leases for certain aircraft
returned by three lessees. The decrease in operating lease
rentals was partially offset by pre-tax gains from asset sales
totaling $7.3 million in 1993 compared to $4 million and $17.7
million in 1992 and 1991, respectively. Fee income in 1993
totaled $13.2 million compared with $4 million and $5.1 million
in 1992 and 1991, respectively.
PCI's marketable securities portfolio contributed pre-tax
income of $38.4 million in 1993 compared with $37.1 million and
$21.1 million in 1992 and 1991, respectively, which results
included net realized gains of $7 million in 1993 compared with
$7.5 million in 1992 and net losses of $7.7 million in 1991.
Other investments for 1993 resulted in a pre-tax loss of
$13.3 million which was primarily the result of a writedown of
approximately $13.5 million related to the termination of
obligations with respect to a real estate limited partnership
interest.
The decrease in 1993 earnings from this writedown and from
reduced operating lease income was partially offset by the
completion of a partnership transaction, whereby PCI contributed
aircraft, subject to direct finance leases, to a majority owned
partnership resulting in future cash savings of $37.4 million.
As a result of this transaction, PCI's obligation for previously
accrued deferred taxes was reduced, resulting in after tax
earnings of $21.3 million, after provision for all costs of the
transaction. The excess deferred taxes were recognized as a
reduction in income tax expense.
19
Expenses, before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $159.3 million, $130.5 million and $122 million
for the years ended December 31, 1993, 1992 and 1991,
respectively. Of these expenses, interest was the largest single
component, amounting to $77.9 million, $86.2 million and $80.3
million in 1993, 1992 and 1991, respectively. Depreciation and
operating expenses totaled $66.8 million in 1993 as compared to
$34.6 million and $27.7 million in 1992 and 1991, respectively.
The increased 1993 expenses resulted from costs related to the
partnership transaction referred to above, the annualization of
depreciation on increased operating lease investment, and
increased operating expenses incurred for aircraft under usage
based leases or which were not under lease during part of the
year. The 1993 reduction in deferred taxes resulting from the
partnership transaction was partially offset by an August 1993
charge to earnings of $5.1 million to adjust PCI's deferred taxes
for the higher rate contained in the Omnibus Budget
Reconciliation Act of 1993.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
Investments in leased equipment of $32.4 million in 1993 reflect
the purchase of a new MD-11 aircraft which was placed on long-
term leveraged lease at the same time older equipment under lease
by the same carrier was sold for proceeds of $108.1 million and a
pre-tax gain of $6.2 million. The remaining investment was
related to the refurbishment and modification of other aircraft
under lease. At the end of 1993, PCI had no commitments for the
purchase of additional aircraft or other equipment leasing
assets.
At December 31, 1993, PCI had two aircraft on lease to
Hawaiian Airlines (Hawaiian) which, on September 21, 1993, filed
for bankruptcy protection under Chapter 11 of the Bankruptcy
Code. To date, Hawaiian has made all of its scheduled monthly
rent payments.
PCI's outstanding short-term debt totaled $126.3 million at
December 31, 1993, a decrease of $137.2 million from the $263.5
million outstanding at December 31, 1992. During 1993, PCI
issued $363.7 million in long-term debt, including non-recourse
debt, and debt repayments totaled $247.1 million. PCI assumed
$22.6 million in debt as a result of the purchase of minority
interests and subsequent consolidation of two entities previously
accounted for under the equity method.
20
PCI paid PEPCO a $14 million dividend in February 1993 and a
$12 million dividend in January 1992. On January 27, 1994, PCI
declared a $15 million dividend to PEPCO payable in January
1994. PCI remains adequately capitalized to support future
business plans, which are designed to supplement utility earnings
and build long-term value. In addition to its investments in
equipment leasing and securities, PCI has limited investments in
Washington metropolitan area real estate and other business
activities.
21
<TABLE>
Consolidated Statements of Earnings
Potomac Electric Power Company and Subsidiaries
- ------------------------------------------------------------------------------
- --------------------
For the year
ended December 31,
1993 1992
1991
- ------------------------------------------------------------------------------
- --------------------
(Thousands
of Dollars)
<CAPTION>
<S> <C> <C>
<C>
Revenue (Note 2)
Operating revenue $1,702,442
$1,562,167 $1,552,066
Interchange deliveries 22,763
39,391 67,249
----------
- ---------- ----------
Total Revenue 1,725,205
1,601,558 1,619,315
----------
- ---------- ----------
Operating Expenses
Fuel 354,282
345,549 387,061
Purchased energy 173,456
166,601 176,583
----------
- ---------- ----------
Fuel and purchased energy 527,738
512,150 563,644
Capacity purchase payments (Note 12) 96,288
95,481 94,798
Other operation 207,814
204,481 196,760
Maintenance 93,668
90,756 90,385
Depreciation and amortization 163,607
149,785 134,340
Income taxes (Note 4) 110,176
75,272 82,681
Other taxes (Note 5) 201,252
194,180 166,476
----------
- ---------- ----------
Total Operating Expenses 1,400,543
1,322,105 1,329,084
----------
- ---------- ----------
Operating Income 324,662
279,453 290,231
----------
- ---------- ----------
Other Income
Nonutility subsidiary (Note 14)
Income 139,341
161,154 145,057
Expenses, including interest and income taxes (114,240)
(132,993) (121,706)
----------
- ---------- ----------
Net earnings from nonutility subsidiary 25,101
28,161 23,351
Allowance for other funds used during construction 13,242
16,089 13,514
Other, net 10,221
1,506 2,153
----------
- ---------- ----------
Total Other Income 48,564
45,756 39,018
----------
- ---------- ----------
Income Before Utility Interest Charges 373,226
325,209 329,249
----------
- ---------- ----------
Utility Interest Charges
Interest on debt 141,393
138,097 138,512
Allowance for borrowed funds used during construction (9,746)
(13,648) (19,427)
----------
- ---------- ----------
Net Utility Interest Charges 131,647
124,449 119,085
----------
- ---------- ----------
Income Before Cumulative Effect of Accounting Change 241,579
200,760 210,164
Cumulative Effect of Accounting Change for Unbilled
Revenues (Net of Income Taxes of $9,458) (Note 1) -
16,022 -
----------
- ---------- ----------
Net Income 241,579
216,782 210,164
Dividends on Preferred Stock 16,255
14,392 12,298
----------
- ---------- ----------
Earnings for Common Stock $ 225,324 $
202,390 $ 197,866
==========
========== ==========
Average Common Shares Outstanding (000s) 115,640
112,390 105,911
Earnings Per Common Share <F1>
Before cumulative effect of accounting change $1.95
$1.66 $1.87
Cumulative effect of accounting change for unbilled
revenues -
.14 -
-----
- ----- -----
Total $1.95
$1.80 $1.87
=====
===== =====
Cash Dividends Per Common Share $1.64
$1.60 $1.56
</TABLE>
<F1> No material dilution would occur if all of the convertible preferred stock
and debentures were converted into common stock.
22
<TABLE>
Consolidated Balance Sheets
Potomac Electric Power Company and Subsidiaries
- ------------------------------------------------------------------------------
- ---------------
December 31,
Assets 1993
1992
- ------------------------------------------------------------------------------
- ---------------
(Thousands
of Dollars)
<CAPTION>
<S> <C>
<C>
Property and Plant - at original cost (Notes 6 and 10)
Electric plant in service $ 5,252,736
$ 5,014,281
Construction work in progress 373,665
314,855
Electric plant held for future use 33,644
34,766
Nonoperating property 5,096
3,722
-----------
-----------
5,665,141
5,367,624
Accumulated depreciation (1,533,999)
(1,436,367)
-----------
-----------
Net Property and Plant 4,131,142
3,931,257
-----------
-----------
Current Assets
Cash and cash equivalents 7,439
4,875
Customer accounts receivable, less allowance for uncollectible
accounts of $2,748 and $2,409 100,973
86,857
Other accounts receivable, less allowance for uncollectible
accounts of $300 53,454
37,040
Accrued unbilled revenues (Note 1) 71,497
66,628
Prepaid taxes 30,531
26,898
Other prepaid expenses 6,053
5,391
Material and supplies - at average cost
Fuel 61,973
99,655
Construction and maintenance 70,262
77,089
-----------
-----------
Total Current Assets 402,182
404,433
-----------
-----------
Deferred Charges
Income taxes recoverable through future rates, net (Note 1) 233,431
-
Other 233,573
143,072
-----------
-----------
Total Deferred Charges 467,004
143,072
-----------
-----------
Nonutility Subsidiary Assets
Cash and cash equivalents 2,625
2,574
Marketable securities (Note 14) 466,153
397,183
Investment in finance leases (Note 14) 358,524
456,678
Operating lease equipment, net of accumulated depreciation
of $85,302 and $55,981 (Note 14) 565,443
565,001
Receivables 84,726
74,151
Other investments 163,911
132,472
Other assets 23,750
35,449
-----------
-----------
Total Nonutility Subsidiary Assets 1,665,132
1,663,508
-----------
-----------
Total Assets $ 6,665,460
$ 6,142,270
===========
===========
23
</TABLE>
<TABLE>
- ------------------------------------------------------------------------------
- ---------------
December 31,
Capitalization and Liabilities 1993
1992
- ------------------------------------------------------------------------------
- ---------------
(Thousands
of Dollars)
<CAPTION>
<S> <C>
<C>
Capitalization
Common equity (Note 7)
Common stock, $1 par value - authorized 200,000,000 shares,
issued 117,797,652 and 114,296,443 shares $ 117,798
$ 114,296
Premium on stock and other capital contributions 1,011,778
919,089
Capital stock expense (13,800)
(13,267)
Retained income 839,433
802,774
-----------
-----------
Total Common Equity 1,955,209
1,822,892
Preference stock, cumulative, $25 par value -
authorized 8,800,000 shares, no shares issued or outstanding -
-
Serial preferred stock (Note 8) 125,442
125,489
Redeemable serial preferred stock (Note 9) 147,000
148,500
Long-term debt (Note 10) 1,589,621
1,579,109
-----------
-----------
Total Capitalization 3,817,272
3,675,990
-----------
-----------
Current Liabilities
Long-term debt and preferred stock redemption
due within one year 17,977
128,058
Short-term debt (Note 11) 294,615
61,600
Accounts payable and accrued payroll 137,321
130,034
Taxes accrued 25,840
27,342
Interest accrued 32,476
37,262
Customer deposits 22,296
21,832
Other 60,542
44,782
-----------
-----------
Total Current Liabilities 591,067
450,910
-----------
-----------
Deferred Credits
Income taxes (Notes 1 and 4) 780,723
524,407
Investment tax credits (Note 4) 71,906
75,375
Other 28,916
28,814
-----------
-----------
Total Deferred Credits 881,545
628,596
-----------
-----------
Nonutility Subsidiary Liabilities
Long-term debt (Note 10) 1,027,705
888,526
Short-term notes payable (Note 11) 126,250
263,515
Deferred taxes and other (Note 4) 221,621
234,733
-----------
-----------
Total Nonutility Subsidiary Liabilities 1,375,576
1,386,774
-----------
-----------
Commitments and Contingencies (Note 12)
Total Capitalization and Liabilities $ 6,665,460
$ 6,142,270
===========
===========
24
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
Potomac Electric Power Company and Subsidiaries
- ------------------------------------------------------------------------------
- -----------------------
For the
year ended December 31,
1993
1992 1991
- ------------------------------------------------------------------------------
- -----------------------
(Thousands of Dollars)
<CAPTION>
<S> <C>
<C> <C>
Operating Activities
Income from utility operations $ 216,478
$ 188,621 $ 186,813
Adjustments to reconcile income to net cash
from operating activities:
Depreciation and amortization 163,607
149,785 134,340
Deferred income taxes and investment tax credits 27,711
43,414 15,170
Allowance for funds used during construction (22,988)
(29,737) (32,941)
Changes in materials and supplies 44,509
(11,144) 18,060
Changes in accounts receivable and accrued unbilled revenues (35,399)
(46,483) (19,729)
Changes in accounts payable (441)
(5,716) (4,287)
Changes in other current assets and liabilities 4,317
6,325 8,305
Changes in deferred conservation and energy use management (57,714)
(26,421) (9,680)
Net other operating activities (39,046)
7,872 (6,278)
Nonutility subsidiary:
Net earnings 25,101
28,161 23,351
Deferred income taxes (32,814)
1,055 13,778
Changes in other assets and net other operating activities 56,897
7,037 36,691
---------
- --------- ---------
Net Cash From Operating Activities 350,218
312,769 363,593
---------
- --------- ---------
Investing Activities
Total investment in property and plant (322,951)
(357,732) (432,143)
Allowance for funds used during construction 22,988
29,737 32,941
---------
- --------- ---------
Net investment in property and plant (299,963)
(327,995) (399,202)
Nonutility subsidiary:
Purchase of marketable securities (254,213)
(266,696) (112,426)
Proceeds from sale or redemption of marketable securities 194,295
195,752 130,609
Investment in leased equipment (32,360)
(30,811) (538,291)
Proceeds from sale or disposition of leased equipment 120,529
48,968 200,951
Purchase of other investments (44,628)
(7,143) (17,928)
Proceeds from sale or distribution of other investments -
42,513 8,222
Investment in promissory notes (1,628)
- -
Proceeds from promissory notes 3,013
27,411 8,313
---------
- --------- ---------
Net Cash Used by Investing Activities (314,955)
(318,001) (719,752)
---------
- --------- ---------
Financing Activities
Dividends on common stock (189,837)
(179,823) (166,933)
Dividends on preferred stock (16,255)
(14,392) (12,298)
Issuance of common stock 96,001
80,396 245,098
Issuance of preferred stock -
50,000 50,000
Redemption of preferred stock (1,500)
(890) -
Issuance of long-term debt 521,264
277,463 97,744
Reacquisition and retirement of long-term debt (628,448)
(137,387) (11,651)
Short-term debt, net 233,015
(25,200) (90,400)
Other financing activities (26,199)
(5,946) (1,709)
Nonutility subsidiary:
Issuance of long-term debt 363,653
242,637 399,127
Repayment of long-term debt (247,077)
(274,991) (129,629)
Short-term debt, net (137,265)
(7,390) (22,495)
---------
- --------- ---------
Net Cash (Used by) From Financing Activities (32,648)
4,477 356,854
---------
- --------- ---------
Net Increase (Decrease) In Cash and Cash Equivalents 2,615
(755) 695
Cash and Cash Equivalents at Beginning of Year 7,449
8,204 7,509
---------
- --------- ---------
Cash and Cash Equivalents at End of Year (Note 13) $ 10,064
$ 7,449 $ 8,204
=========
========= =========
25
</TABLE>
Notes to Consolidated Financial Statements
- ------------------------------------------
(1) Summary of Significant Accounting Policies
------------------------------------------
The Company's utility operations are regulated by the Maryland
and District of Columbia public service commissions and, as to
its wholesale business, 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. In conformity with generally
accepted accounting principles, the accounting policies and
practices applied by the regulatory commissions in the
determination of rates for utility operations are also employed
for financial reporting purposes.
A description of significant accounting policies follows.
Principles of Consolidation
- ---------------------------
The consolidated financial statements combine the financial
results of the Company and all majority-owned subsidiaries. The
Company's principal subsidiary is Potomac Capital Investment
Corporation (PCI). All material intercompany balances and
transactions have been eliminated.
Total Revenue
- -------------
Effective January 1, 1992, the Company changed its method of
revenue recognition to provide for the accrual of revenue for
service rendered but unbilled as of the end of each month. Prior
to 1992, revenues were recognized using the meters read method of
accounting whereby annual revenues reflected 12 monthly meter
readings for each customer. The new method was adopted to
provide a better matching of revenues and expenses and to conform
with the predominant practice within the utility industry. This
change in the method of revenue recognition resulted in an
increase in 1992 of approximately $16 million in net income or
$.14 per common share. If the new accounting method had been in
effect in 1991, net income would not have been materially
different from that shown in the accompanying consolidated
financial statements. This change in accounting method, which
has no significant effect on revenue over a 12-month period,
affects the timing of revenue recognition within the year,
principally increasing revenues in the second quarter and
decreasing revenues in the fourth quarter.
26
The Company includes in revenues the amounts received for sales
to other utilities related to pooling and interconnection
agreements. Amounts received for such interchange deliveries are
a component of the Company's fuel rates.
In each jurisdiction, the Company's rate schedules include fuel
rates. The fuel rate provisions are designed to provide for
separately stated fuel billings which cover applicable net fuel
and interchange costs or changes in applicable net fuel and
interchange costs from levels incorporated in base rates.
Differences between applicable net fuel and interchange costs
incurred and fuel rate revenues 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.
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. Depreciation is recorded
on a straight line basis over the equipment's estimated useful
life.
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.
27
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 1993 and 3% for 1992
and 1991.
Conservation and Energy Use Management
- --------------------------------------
The Company accounts for energy conservation expenditures as a
deferred charge, and amortizes the costs over five to ten years.
District of Columbia conservation costs receive rate base
treatment, with a capital cost recovery factor accrued on the
unamortized balance in excess of amounts included in rate base.
In Maryland, conservation costs are recovered currently through a
surcharge included in base rates.
Allowance for Funds Used During Construction
- --------------------------------------------
In general, the Company capitalizes AFUDC with respect to
investments in Construction Work in Progress with the exception
of expenditures required to comply with federal, state or local
environmental regulations (pollution control projects), which are
included in rate base without capitalization of AFUDC. In 1992,
pursuant to orders from both the Maryland and District of
Columbia commissions, the Company commenced the accrual of a
capital cost recovery factor on the retail jurisdictional portion
of certain pollution control projects related to compliance with
the Clean Air Act (CAA). The base for calculating this return is
the amount by which the retail jurisdictional CAA expenditure
balance exceeds the CAA balance included in rate base in the
Company's most recently completed base rate proceeding.
The jurisdictional AFUDC capitalization rates are determined as
prescribed by the FERC. The effective capitalization rates were
approximately 8.7% in 1993 and 9.1% in 1992 and 1991, compounded
semiannually.
Nonutility Subsidiary Receivables
- ---------------------------------
The Company's nonutility subsidiary uses the direct write-off
method of accounting when a receivable is deemed to be
uncollectible in lieu of an allowance for doubtful accounts. The
amounts were not material.
28
Income Taxes
- ------------
Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 109 entitled
"Accounting for Income Taxes" which, among other things,
prohibits the use of net-of-tax accounting and requires the use
of an asset and liability approach for financial reporting and
accounting for deferred income taxes. Deferred taxes are being
recorded for all temporary differences based upon currently
enacted tax rates.
The Company's utility net deferred tax liabilities totaled $789
million at December 31, 1993, of which $8.3 million was
classified as a current liability. At December 31, 1993, the
Company's nonutility subsidiary net deferred tax liability
totaled $142.6 million. The adoption of SFAS No. 109 increased
net income for the twelve months ended December 31, 1993 by $2.8
million which is reflected on the Consolidated Statements of
Earnings in "Other, net."
Certain provisions of SFAS No. 109 allow regulated enterprises
to recognize regulatory assets and liabilities for income taxes
to be recovered from or returned to customers in future rates.
Accordingly, as of December 31, 1993, the Company has recorded
additional deferred income taxes and a net regulatory asset of
$233.4 million. No valuation allowance for deferred tax assets
was required or recorded at December 31, 1993.
29
(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 (PJM) of
which the Company is a member. PJM is composed of eleven
electric utilities which operate on a fully integrated basis.
Total revenue for each year was comprised as shown below.
- -----------------------------------------------------------------
1993 1992 1991
-------------------------------------------------
Amount % Amount % Amount %
- -----------------------------------------------------------------
(Thousands of Dollars)
Residential $ 505,173 29.8 $ 432,797 27.8 $ 450,103 29.2
Commercial 791,357 46.6 748,550 48.1 724,039 46.9
U.S. Government 238,192 14.0 229,586 14.8 223,723 14.5
D.C. Government 53,551 3.2 49,815 3.2 48,009 3.1
Wholesale 108,162 6.4 95,350 6.1 96,697 6.3
---------- ----- --------- ----- ---------- -----
Sales of
electricity 1,696,435 100.0 1,556,098 100.0 1,542,571 100.0
===== ===== =====
Other electric
revenues 6,007 6,069 9,495
---------- ---------- ----------
Operating
revenue 1,702,442 1,562,167 1,552,066
Interchange
deliveries 22,763 39,391 67,249
---------- ---------- ----------
Total Revenue $1,725,205 $1,601,558 $1,619,315
========== ========== ==========
- -----------------------------------------------------------------
Sales of electricity include base rate revenues and fuel rate
revenues. Fuel rate revenues were $487.9 million in 1993, $456.4
million in 1992 and $481.1 million in 1991.
The Company's Maryland fuel rate is based on historical net
fuel and interchange costs. The zero-based rate may not be
changed without prior approval of the Maryland Public Service
Commission. Application to the Commission for an increase in the
rate may only be made when the currently calculated fuel rate,
based on the most recent actual net fuel and interchange costs,
30
exceeds the currently effective fuel rate by more than 5%. If
the currently calculated fuel rate is more than 5% below the
currently effective fuel rate, the Company must apply to the
Commission for a fuel rate reduction.
The District of Columbia fuel rate is based upon an average of
historical and projected net fuel and interchange costs and is
adjusted monthly to reflect changes in such costs.
Rates for service, at wholesale, to SMECO include a fuel
adjustment charge based upon estimated applicable fuel and
interchange costs for each billing month. The difference between
the estimated costs and the actual applicable fuel and
interchange costs incurred each month is reflected as an
adjustment to the fuel rate in the succeeding month.
Amounts received for interchange deliveries are a component of
the Company's fuel rates.
31
(3) Pensions and Other Postretirement Benefits
------------------------------------------
The Company's General Retirement Program (Program), a
noncontributory defined benefit program, covers substantially all
full-time employees of the Company and its subsidiaries. The
Program provides for benefits to be paid to eligible employees at
retirement based primarily upon years of service with the Company
and their compensation rates for the three years preceding
retirement. Annual provisions for accrued pension cost are based
upon independent actuarial valuations. The Company's policy is
to fund accrued pension costs.
Pension expense included in net income was $13.7 million in
1993, $10.5 million in 1992 and $10.7 million in 1991. The net
periodic pension cost was computed as follows.
- -----------------------------------------------------------------
1993 1992 1991
- -----------------------------------------------------------------
(Thousands of Dollars)
Service cost-benefits earned $10,300 $ 9,100 $ 8,500
Interest cost on projected
benefit obligation 25,100 23,500 22,000
Actual return on Program assets (24,300) (13,400) (28,500)
Differences between actual
and expected return on
Program assets and net
amortization 2,600 (8,700) 8,700
------- ------- -------
Pension cost $13,700 $10,500 $10,700
======= ======= =======
- -----------------------------------------------------------------
32
Program assets are stated at fair value and were comprised of
approximately 68% and 70% of cash equivalents and fixed income
investments and the balance in equity investments at December 31,
1993 and 1992, respectively. The following table sets forth the
Program's funded status and amounts recognized on the
Consolidated Balance Sheets.
- -----------------------------------------------------------------
1993 1992
- -----------------------------------------------------------------
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Program benefits:
Vested benefits $(249,600) $(211,100)
Nonvested benefits (35,300) (27,200)
--------- ---------
Accumulated benefit obligation $(284,900) (238,300)
========= =========
Actuarial present value of projected
benefit obligation $(358,600) $(293,000)
Program assets at fair value 282,600 261,500
--------- ---------
Projected benefit obligation in excess of
Program assets (76,000) (31,500)
Unrecognized actuarial loss 58,500 23,200
Unrecognized prior service cost 12,900 3,800
Unrecognized net obligation at
January 1, 1987, being recognized
over 18 years 400 400
--------- ---------
Accrued pension liability $ (4,200) $ (4,100)
========= =========
- -----------------------------------------------------------------
The assumed weighted average discount rate and weighted average
rate of increase in future compensation levels used in
determining the actuarial present value of the projected benefit
obligation were 7.75% and 5% in 1993 and 8.75% and 5% in 1992,
respectively. The assumed long-term rate of return on Program
assets was 9% in 1993 and 1992.
In addition to providing pension benefits, the Company provides
certain health care and life insurance benefits for retired
employees and inactive employees covered by disability plans.
The health care plan pays stated percentages of most necessary
medical expenses incurred by these employees, after subtracting
payments by Medicare or other providers and after a stated
deductible has been met. The life insurance plan pays benefits
based on base salary at the time of retirement and age at the
date of death. Participants become eligible for the benefits of
these plans if they retire under the provisions of the Company's
General Retirement Program with ten years of service or become
inactive employees under the Company's disability plans.
33
Effective January 1, 1993, the Company adopted SFAS No. 106,
entitled "Employers' Accounting for Postretirement Benefits Other
Than Pensions" which requires "accrual basis" instead of "cash
basis" accounting for postretirement health care and life
insurance. The effect of this change in accounting was to
decrease 1993 pre-tax income by $2.2 million. The Company is
amortizing the unrecognized transition obligation measured at
January 1, 1993 over a 20-year period.
Postretirement benefit expense included in net income was $9.3
million in 1993. The cost of such benefits, recognized as an
operating expense when paid, was $5 million in 1992 and $5.2
million in 1991. The 1993 postretirement expense includes the
following components.
(Thousands of Dollars)
Service cost-benefits attributable
to service during 1993 $ 2,500
Interest cost on accumulated
postretirement benefit obligation 4,400
Actual return on Plan Assets (400)
Amortization of transition
obligation 2,800
-----------
Net postretirement benefit cost $ 9,300
===========
The accumulated postretirement benefit obligation is reconciled
to the amount recognized in the Company's December 31, 1993
statement of financial position as follows.
(Thousands of Dollars)
Accumulated postretirement
benefit obligation to
Retirees and dependents $(29,700)
Active employees fully eligible (10,300)
Active employees not fully
eligible (14,800)
--------
Total accumulated postretirement
benefit obligation (54,800)
Plan assets at fair value 4,300
--------
Accumulated postretirement benefit
obligation in excess of plan assets (50,500)
Unrecognized transition obligation 47,700
Unrecognized actuarial loss 2,800
--------
Accrued postretirement benefit cost
as of December 31, 1993 $ -
========
34
The Company's SFAS No. 106 obligation at December 31, 1993 is
based on a discount rate of 7.75% and a current health-care cost
trend rate of 8.5% which declines to 5.5% after a six-year
period. A one percentage point increase in the health-care cost
trend rate would increase the Accumulated Postretirement Benefit
Obligation by $2.3 million to approximately $57.1 million and
postretirement expense by approximately $.4 million.
In January 1993, the Company funded the 1993 portion of its
estimated liability for post-retirement 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. Assets were comprised of cash equivalents, fixed
income investments and equity investments and the assumed return
on plan assets is 9%.
In July 1993, a new three-year Agreement between the Company
and Local 1900 of the International Brotherhood of Electrical
Workers was ratified by Union members. As a result of this
Agreement, the Company will reduce the costs of its
postretirement benefits by requiring all eligible employees who
retire on or after January 1, 1994, to share in the cost of these
benefits. These amendments have been reflected in 1993.
The Company treats postretirement benefit costs as an operating
expense and has not recorded a regulatory asset associated with
these costs. The Company's Maryland tariff includes the cost of
postretirement benefits. The District of Columbia Public Service
Commission's decision is expected in February 1994.
In November 1992, the Financial Accounting Standards Board
(FASB) issued SFAS No. 112, "Employers' Accounting for
Postemployment Benefits," effective for fiscal years beginning
after December 15, 1993. SFAS No. 112 requires the accrual of
the expected cost of providing benefits to former or inactive
employees after employment but before retirement. The Company is
evaluating the effects of applying SFAS No. 112 and does not
expect the statement to have a material effect on the Company's
financial position or results of operation.
35
<TABLE>
(4) Income Taxes
------------
The provision for income taxes charged to continuing operations, reconciliation
of consolidated income tax expense and components of consolidated deferred tax
liabilities (assets) are set forth below.
Provisions for Income Taxes Charged to Continuing Operations
- ------------------------------------------------------------
- ------------------------------------------------------------------------------
- ---------------------
1993
1992 1991
- ------------------------------------------------------------------------------
- ---------------------
(Thousands of Dollars)
<CAPTION>
<S> <C> <C>
<C>
Utility current tax expense
Federal $ 69,007 $
50,900 $ 57,093
State and local 9,801
7,571 8,725
---------
- --------- ---------
Total utility current tax expense 78,808
58,471 65,818
---------
- --------- ---------
Utility deferred tax expense
Federal 26,784
26,584 15,046
State and local 5,100
4,682 3,375
Investment tax credits (3,469)
(3,314) (3,251)
---------
- --------- ---------
Total utility deferred tax expense 28,415
27,952 15,170
---------
- --------- ---------
Total utility income tax expense 107,223
86,423 80,988
---------
- --------- ---------
Nonutility subsidiary current tax expense
Federal (13,022)
1,461 (14,029)
---------
- --------- ---------
Nonutility subsidiary deferred tax expense
Federal (31,360)
1,055 13,778
State and local (696)
- -
---------
- --------- ---------
Total nonutility subsidiary deferred tax expense (32,056)
1,055 13,778
---------
- --------- ---------
Total nonutility subsidiary income tax expense (45,078)
2,516 (251)
---------
- --------- ---------
Total income tax expense 62,145
88,939 80,737
Income taxes included in other income (48,031)
4,209 (1,944)
Income taxes included in cumulative effect of accounting change -
9,458 -
---------
- --------- ---------
Income taxes included in utility operating expenses $ 110,176 $
75,272 $ 82,681
=========
========= =========
36
</TABLE>
<TABLE>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
- ------------------------------------------------------------------------------
- ---------------------
1993
1992 1991
- ------------------------------------------------------------------------------
- ---------------------
(Thousands of Dollars)
<CAPTION>
<S> <C> <C>
<C>
Income before income taxes (including cumulative effect
of accounting change) $ 303,724 $
305,721 $ 290,901
=========
========= =========
Utility income tax at federal statutory rate $ 113,295 $
93,515 $ 91,052
Increases (decreases) resulting from
Depreciation 5,096
4,204 3,971
Removal costs (4,385)
(5,109) (6,315)
Allowance for funds used during construction (3,852)
(4,854) (4,127)
Other (6,477)
(5,888) (7,954)
State income taxes, net of federal effect 9,686
8,213 7,986
Tax credits (3,873)
(3,658) (3,625)
Cumulative effect of tax rate change (2,267)
- -
---------
- --------- ---------
Total utility income tax expense 107,223
86,423 80,988
---------
- --------- ---------
Nonutility subsidiary income tax at federal statutory rate (6,992)
10,430 7,854
Increases (decreases) resulting from
Dividends received deduction (7,672)
(6,750) (6,135)
Reversal of previously accrued deferred taxes (35,904)
- -
Other (408)
(1,164) (1,970)
State income taxes, net of federal effect (696)
- -
Cumulative effect of tax rate change 6,594
- -
---------
- --------- ---------
Total nonutility subsidiary income tax expense (45,078)
2,516 (251)
---------
- --------- ---------
Total consolidated income tax expense 62,145
88,939 80,737
Income taxes included in other income (48,031)
4,209 (1,944)
Income taxes included in cumulative effect of accounting change -
9,458 -
---------
- --------- ---------
Income taxes included in utility operating expenses $ 110,176 $
75,272 $ 82,681
=========
========= =========
</TABLE>
<TABLE>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
at December 31, 1993 (Thousands of Dollars)
--------------------
<CAPTION>
<S> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax basis differences $ 672,625
Rapid amortization of certified pollution control
facilities 31,090
Deferred taxes on amounts to be collected through
future rates 88,787
Property taxes 10,218
Deferred fuel 4,644
Prepayment premium on debt retirement 11,215
Deferred ITC (27,435)
Contributions in aid of construction (23,951)
Other 21,825
---------
Total utility deferred tax liabilities (net) 789,018
Current portion of utility deferred tax liabilities
(included in Other Current Liabilites) 8,295
---------
Total utility deferred tax liabilities (net) - non current $ 780,723
=========
Nonutility subsidiary deferred tax liabilities (assets)
Finance leases $ 130,833
Operating lease depreciation 114,134
Reversal of previously accrued taxes related
to partnerships (16,969)
Alternative minimum tax (75,610)
Other (9,789)
---------
Total nonutility subsidiary deferred tax liabilities (net),
(included in Deferred taxes and other) $ 142,599
=========
37
</TABLE>
The Omnibus Budget Reconciliation Act of 1993, which was
enacted on August 10, 1993, increased the federal corporate
income tax rate from 34% to 35% for the periods beginning after
December 31, 1992.
The Tax Reform Act of 1986 repealed the Investment Tax Credit
(ITC) for property placed in service after December 31, 1985,
except for certain transition property. ITC previously earned on
utility property continues to be normalized over the remaining
service lives of the related assets.
The Company and its subsidiaries file a consolidated federal
income tax return. The Company's federal income tax liabilities
for all years through 1991 have been finally determined. The
Company is of the opinion that the final settlement of its
federal income tax liabilities for subsequent years will not have
a material adverse effect on its financial position.
38
(5) Other Taxes
-----------
Taxes, other than income taxes, charged to utility operating
expenses for each period are shown below.
- ----------------------------------------------------------------
1993 1992 1991
- ----------------------------------------------------------------
(Thousands of Dollars)
Gross receipts $ 88,044 $ 81,266 $ 71,953
Property 58,193 55,965 52,938
Payroll 10,534 10,582 9,967
County fuel-energy 34,614 37,283 23,180
Environmental, use and
other 9,867 9,084 8,438
-------- -------- --------
$201,252 $194,180 $166,476
======== ======== ========
- -----------------------------------------------------------------
39
(6) Jointly Owned Generating Facilities
-----------------------------------
The Company owns a 9.72% undivided interest in the Conemaugh
Generating Station located near Johnstown, Pennsylvania,
consisting of two baseload units totaling 1,700 megawatts. The
Company and other utilities own the station as tenants in common
and share costs and output in proportion to their ownership
shares. Each owner has arranged its own financing relating to
its share of the facility. The Company's share of the operating
expenses of the station is included in the Consolidated
Statements of Earnings. The Company's investment in the
Conemaugh facility of $67.1 million at December 31, 1993 and
$51.8 million at December 31, 1992, includes $23.4 million and
$11.6 million of Construction Work in Progress, respectively.
The Conemaugh Generating Station is required to comply with
certain provisions of the Clean Air Act by January 1, 1995. The
construction of flue gas desulfurization equipment for both units
began in 1992. The Company's share of the construction cost is
approximately $38 million.
40
<TABLE>
(7) Common Equity
Changes in common stock, premium on stock and retained income are summarized
below.
- ------------------------------------------------------------------------------
- ---------
Common Stock Premium
Retained
Shares Par Value on Stock
Income
- ------------------------------------------------------------------------------
- ---------
(Thousands of Dollars)
<CAPTION>
<S> <C> <C> <C> <C>
Balance, December 31, 1990 99,714,471 $ 99,714 $ 607,775 $
739,236
Net income before net earnings
from nonutility subsidiary - - -
186,813
Nonutility subsidiary:
Net earnings - - -
23,351
Marketable equity securities
valuation allowance, net of tax - - -
5,971
Dividends:
Preferred stock - - -
(12,298)
Common stock - - -
(166,933)
Conversion of convertible
debentures 370 - 10
-
Conversion of preferred stock 10,581 11 81
-
Sale of common stock through
Shareholder Dividend
Reinvestment Plan 1,571,880 1,572 33,285
-
Issuance of common stock to
Employee Savings Plans 382,595 383 7,903
-
Sale of common stock through
public offerings 9,425,900 9,426 192,529
-
----------- ---------- ----------
- ----------
Balance, December 31, 1991 111,105,797 111,106 841,583
776,140
Net income before net earnings
from nonutility subsidiary - - -
188,621
Nonutility subsidiary:
Net earnings - - -
28,161
Marketable equity securities
valuation allowance, net of tax - - -
4,067
Dividends:
Preferred stock - - -
(14,392)
Common stock - - -
(179,823)
Conversion of convertible
debentures 2,220 2 58
-
Conversion of preferred stock 22,318 22 169
-
Gain on acquisition of preferred
stock - - 24
-
Other capital contributions - - 25
-
Sale of common stock through
Shareholder Dividend
Reinvestment Plan 1,787,724 1,788 42,414
-
Issuance of common stock to
Employee Savings Plans 378,384 378 9,028
-
Sale of common stock through
public offerings 1,000,000 1,000 25,788
-
----------- ---------- ----------
- ----------
Balance, December 31, 1992 114,296,443 114,296 919,089
802,774
Net income before net earnings
from nonutility subsidiary - - -
216,478
Nonutility subsidiary:
Net earnings - - -
25,101
Marketable equity securities
valuation allowance, net of tax - - -
1,172
Dividends:
Preferred stock - - -
(16,255)
Common stock - - -
(189,837)
Conversion of convertible
debentures 3,480 4 93
-
Conversion of preferred stock 5,534 6 42
-
Loss on acquisition of preferred
stock - - (24)
-
Other capital contributions - - 69
-
Sale of common stock through
Shareholder Dividend
Reinvestment Plan 1,638,227 1,638 42,655
-
Issuance of common stock to
Employee Savings Plans 362,468 362 9,277
-
Sale of common stock through
public offerings 1,491,500 1,492 40,577
-
----------- ---------- ----------
- ----------
Balance, December 31, 1993 117,797,652 $ 117,798 $1,011,778 $
839,433
=========== ========== ==========
==========
41
</TABLE>
During the period of July through October 1993, the Company
sold 1,491,500 shares of Common Stock at an average price of
$28.21 per share through a Continuous Offering Stock Program
pursuant to a "shelf" registration statement filed with the
Securities and Exchange Commission in June 1992.
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, 1993, 52,714 shares of common stock were
reserved for issuance upon the conversion of convertible
preferred stock, 2,771,633 shares for issuance upon the
conversion of the 7% convertible debentures, 3,392,500 shares for
issuance upon the conversion of the 5% convertible debentures,
2,838,420 shares for issuance under the DRP and 191,275 shares
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, 1993.
42
(8) Serial Preferred Stock
----------------------
The Company has authorized 11,211,044 shares of cumulative $50
par value Serial Preferred Stock. At December 31, 1993 and 1992,
there were outstanding 5,461,038 shares and 5,491,986 shares,
respectively. The various series of Serial Preferred Stock
outstanding (excluding 2,952,200 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 1993 1992
- -----------------------------------------------------------------
(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,
8,838 and 9,786 shares,
respectively $50.00 442 489
Auction Series A, 1,000,000 shares $50.00 50,000 50,000
-------- --------
$125,442 $125,489
======== ========
- -----------------------------------------------------------------
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, 1993,
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 948 shares in 1993, 3,827 shares in 1992 and 1,804 shares in
1991. The estimated fair value of this series, based on quoted
market prices was $1.4 million at December 31, 1993 and 1992.
Dividends on the Serial Preferred Stock, Auction Series A, are
cumulative and are based on the rate determined by auction
procedures prior to each dividend period. The maximum rate can
range from 110% to 200% of the applicable "AA" Composite
Commercial Paper Rate. The annual dividend rate is 3.02% ($1.51)
for the period December 1, 1993 through February 28, 1994. The
average annual dividend rates were 2.8% ($1.40) in 1993 and
3.412% ($1.706) in 1992. The estimated fair value of this series
at December 31, 1993 and 1992, was the carrying amount.
43
The estimated fair value at December 31, 1993 and 1992, for the
remaining serial preferred stock (excluding the Redeemable Serial
Preferred Stock) was $59.5 million and $55.7 million,
respectively, based on current redemption prices and discounted
cash flows using current rates for preferred stock with similar
terms.
(9) Redeemable Serial Preferred Stock
---------------------------------
The outstanding series of $50 par value Redeemable Serial
Preferred Stock are shown below.
- -----------------------------------------------------------------
December 31,
1993 1992
- -----------------------------------------------------------------
(Thousands of Dollars)
$3.37 Series of 1987, 952,200 and
982,200 shares, respectively $ 47,610 $ 49,110
$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
-------- --------
147,610 149,110
Redemption Requirement due within one year (610) (610)
-------- --------
$147,000 $148,500
======== ========
- ----------------------------------------------------------------
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 $52.25, which is reduced in succeeding
years, equaling par value beginning June 1, 2002.
The shares of the $3.89 (7.78%) Series are subject to mandatory
redemption, at par, through the operation of a sinking fund which
will redeem not less than 165,000 nor more than 330,000 shares
annually, beginning June 1, 2001 and 175,000 shares on June 1,
2006. The option to redeem in excess of 165,000 shares annually
is not cumulative. The shares may be called for redemption at
any time at a per share price of $53.89; however, the shares are
not redeemable prior to June 1, 1996, through certain refunding
operations. The redemption price is reduced in succeeding years,
equaling $50.98 beginning June 1, 2003.
44
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 1998 with respect to the
Redeemable Serial Preferred Stock are $.6 million in 1994 and
$1.5 million annually thereafter.
The estimated fair value of the Company's Redeemable Serial
Preferred Stock was $164.1 million and $153.5 million based on
quoted market prices at December 31, 1993 and 1992, respectively.
45
<TABLE>
(10) Long-Term Debt
Details of long-term debt are shown below.
- ------------------------------------------------------------------------------
- ------------------------
Interest
December 31,
Rate Maturity
1993 1992
- ------------------------------------------------------------------------------
- ------------------------
(Thousands of Dollars)
<CAPTION>
<S> <C> <C>
<C>
First Mortgage Bonds
Fixed Rate Series:
4-5/8% December 1, 1993 $
- $ 25,000
5-1/4% December 1, 1994
15,000 15,000
5% December 15, 1995
40,000 40,000
5-5/8% December 31, 1997
18,000 19,000
4-3/8% February 15, 1998
50,000 50,000
4-1/2% May 15, 1999
45,000 45,000
9% April 15, 2000
100,000 100,000
5-1/8% April 1, 2001
15,000 15,000
5-7/8% May 1, 2002
35,000 35,000
6-5/8% February 15, 2003
40,000 40,000
5-5/8% October 15, 2003
50,000 -
7-3/4% March 15, 2004
- 45,000
6-1/2% July 1, 2004
15,000 15,000
6-1/8% July 1, 2007
38,300 38,300
6-1/2% July 1, 2007
20,000 20,000
7-3/4% October 1, 2007
- 50,000
6-1/2% March 15, 2008
78,000 -
5-7/8% October 15, 2008
50,000 -
6-5/8% January 1, 2009
7,500 7,500
8-3/8% January 15, 2009
- 100,000
8-3/4% April 15, 2010
- 37,000
9-1/4% March 1, 2016
- 75,000
8-3/4% November 15, 2016
- 75,000
8-1/4% March 1, 2017
- 75,000
9-3/4% May 1, 2019
43,000 75,000
8-5/8% August 15, 2019
63,000 75,000
9% June 1, 2021
100,000 100,000
6% September 1, 2022
30,000 30,000
6-3/8% January 15, 2023
37,000 -
7-1/4% July 1, 2023
100,000 -
6-7/8% September 1, 2023
100,000 -
6-7/8% October 15, 2024
75,000 -
8-1/2% May 15, 2027
75,000 75,000
7-1/2% March 15, 2028
40,000 -
Variable Rate Series:
Adjustable rate December 1, 2001
50,000 50,000
- ---------- ----------
Total First Mortgage Bonds
1,329,800 1,326,800
Convertible Debentures
5% September 1, 2002
115,000 115,000
7% January 15, 2018
68,834 70,376
Medium-Term Notes
8.61% to 8.72% October 15, 1993
- 100,000
9.08% July and August 1997
50,000 50,000
7.46% to 7.60% January 2002
40,000 40,000
7.64% January 17, 2007
35,000 35,000
- ---------- ----------
Total Utility Long-Term Debt
1,638,634 1,737,176
Net unamortized discount
(31,646) (30,619)
Current portion
(17,367) (127,448)
- ---------- ----------
Net Utility Long-Term Debt
$1,589,621 $1,579,109
========== ==========
Nonutility Subsidiary Long-term Debt
Varying rates through 2011
$1,027,705 $ 888,526
========== ==========
46
</TABLE>
Utility Long-Term Debt
- ----------------------
The outstanding First Mortgage Bonds (bonds) are secured by a
lien on substantially all of the Company's property and plant.
Additional bonds may be issued under the mortgage as amended and
supplemented in compliance with the provisions of the indenture.
In January 1993, the Company issued $37 million of 6-3/8% First
Mortgage Bonds due 2023, in conjunction with the sale at 99% by
Prince George's County, Maryland, of a like amount of the
County's Pollution Control Revenue Refunding Bonds. Proceeds
were applied toward the redemption of the Company's $37 million
8-3/4% First Mortgage Bonds due 2010, at 102% of principal amount
plus accrued interest, and a like amount of the County's
Pollution Control Revenue Bonds.
In February 1993, the Company sold, at 98.403%, $78 million of
6-1/2% First Mortgage Bonds due in 2008, and, at 99.385%, $40
million of 7-1/2% First Mortgage Bonds due in 2028. Proceeds
from the sales were applied toward the March 1993 redemption, at
106.02% of principal amount plus accrued interest, of $75 million
of 9-1/4% First Mortgage Bonds due in 2016.
In June 1993, the Company sold, at 98.711%, $100 million of
7-1/4% First Mortgage Bonds due in 2023. A portion of the
proceeds from the sale were applied to the August 1993
redemption, at 104.9% of principal amount plus accrued interest,
of $75 million of 8-3/4% First Mortgage Bonds due in 2016.
In August 1993, the Company sold, at 98.44%, $100 million of
6-7/8% First Mortgage Bonds due in 2023. Proceeds from the sale
were applied to the September 1993 redemption, at 103.21% of
principal amount plus accrued interest, of $100 million of 8-3/8%
First Mortgage Bonds due in 2009.
In September 1993, the Company sold, at 99.223%, $50 million of
5-5/8% First Mortgage Bonds due in 2003; at 98.968%, $50 million
of 5-7/8% First Mortgage Bonds due in 2008; and, at 99.320%, $75
million of 6-7/8% First Mortgage Bonds due in 2024. Proceeds
were applied to the November 1993 redemptions of $45 million of
7-3/4% First Mortgage Bonds due in 2004 at 102.1% of principal
amount plus accrued interest, $50 million of 7-3/4% First
Mortgage Bonds due in 2007 at 103.06% of principal amount plus
accrued interest, and $75 million of 8-1/4% First Mortgage Bonds
due in 2017 at 104.38% of principal amount plus accrued interest.
On January 12, 1994, the Company sold, at par, $50 million of
6-1/4% Medium-Term Notes due in 2009 and, at 98.494%, $50 million
of 7% Medium-Term Notes due in 2024. The notes were sold
pursuant to a "shelf" registration statement filed with the
Securities and Exchange Commission during September 1993, of
which $225 million remains available.
The interest rate on the $50 million Adjustable Rate series
First Mortgage Bonds is adjusted annually on December 1, based
upon 116% of the 10-year "constant maturity" United States
Treasury bond rate for the preceding three-month period ended
October 31. Effective December 1, 1993, the applicable interest
rate is 6.657%. The applicable interest rate was 7.733% at
47
December 1, 1992 and 8.924% at December 1, 1991. The Bonds are
nonredeemable prior to December 1, 1994. The estimated fair
value of this bond series at December 31, 1993, based on the
current market price was $54 million. The carrying value was
considered to be the estimated fair value of this bond series at
December 31, 1992.
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 and sinking fund
requirements for the Company's long-term debt outstanding at
December 31, 1993 are $17.4 million in 1994, $44 million in 1995,
$6 million in 1996, $56 million in 1997 and $50 million in 1998.
The estimated fair value of the fixed rate First Mortgage
Bonds, excluding amounts due within one year, in the aggregate,
was $1.3 billion at December 31, 1993 and 1992; and the
Convertible Debentures, excluding amounts due within one year, in
the aggregate, was $177 million and $166 million, respectively.
The estimated fair value at December 31, 1993 and 1992, 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 bonds with similar terms and remaining maturities.
At December 31, 1993 and 1992, the estimated fair value of the
Medium-Term Notes, in the aggregate, was $139 million and $132
million, respectively, based on discounted cash flows using
current rates for notes with similar terms and remaining
maturities.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at December 31, 1993 consisted of $947.9 million
of unsecured borrowings from institutional lenders maturing at
various dates between January 1994 and July 2003. The interest
rates of such borrowings ranged from 3.64% to 10.65%. The
weighted average interest rate was 7.45% at December 31, 1993,
8.13% at December 31, 1992 and 8.9% at December 31, 1991. Annual
aggregate principal repayments are $160.8 million in 1994, $181.8
million in 1995, $173.2 million in 1996, $103.8 million in 1997,
$92.3 million in 1998 and $236 million thereafter.
The remaining $79.8 million was non-recourse debt, $54.7
million of which was secured by aircraft currently under
operating lease. The debt is payable in monthly installments at
rates of LIBOR (London Interbank Offered Rate) plus 1.25% and
LIBOR plus 1.375% with final maturity on March 15, 2002. The
remaining non-recourse debt of $25.1 million is related to PCI's
majority owned real estate partnerships of which $16.5 million is
48
due in consecutive monthly installments with maturity on February
28, 1994, at a floating rate of interest based on LIBOR plus 2%.
The remaining non-recourse real estate debt consists of $8.6
million payable in monthly installments at a fixed rate of
interest of 9.66% with final maturity on October 1, 2011.
The estimated fair value of PCI's long-term debt, including
non-recourse debt, was $1.1 billion and $925 million at December
31, 1993 and 1992, respectively, based on current rates offered
to similar companies for debt with similar remaining maturities.
49
(11) Short-Term Debt
---------------
The Company's short-term financing requirements have been
satisfied principally through the sale of commercial promissory
notes.
The Company has $90 million in revolving credit agreements with
a group of 11 banks and conventional bank line of credit
agreements of $215.5 million with 21 banks to support its utility
operations, all of which were unused during 1993, 1992 and 1991.
Nonutility Subsidiary Short-Term Notes Payable
- ----------------------------------------------
The nonutility subsidiary's short-term financing requirements
have been satisfied principally through the sale of commercial
promissory notes.
The nonutility subsidiary maintains a minimum 100% line of
credit back-up for its outstanding commercial promissory notes,
all of which were unused during 1993, 1992 and 1991.
50
(12) Commitments and Contingencies
-----------------------------
The Company leases its general office building and certain data
processing and duplicating equipment, motor vehicles,
communication system and construction equipment under long-term
lease agreements. The lease of the general office building
expires in 2002 and leases of equipment extend for periods of up
to 6 years. Charges under such leases are accounted for as
operating expenses or construction expenditures, as appropriate.
Rents, including property taxes and insurance, net of rental
income from subleases, aggregated approximately $13.6 million in
1993, $12.6 million in 1992 and $11.4 million in 1991. The
approximate annual commitments under all leases, reduced by
rentals to be received under subleases are $11.3 million in 1994,
$8.8 million in 1995, $7 million in 1996, $4.7 million in 1997,
$4.6 million in 1998 and a total of $19.5 million in the years
thereafter.
The Company's long-term capacity purchase agreements with Ohio
Edison and APS commenced June 1, 1987 and are expected to
continue at the 450 megawatt level through 2005. Under the terms
of the agreement with Ohio Edison, the Company is required to
make capacity payments, subject to certain contingencies, which
include a share of Ohio Edison's fixed operating and maintenance
cost. The approximate monthly capacity commitment under this
agreement, excluding fixed operating and maintenance cost, was
$12,380 per megawatt, per month, through 1993; increasing to
$18,060 per megawatt, per month, effective January 1994 through
1998; and increasing to $25,620 per megawatt, per month, in 1999
through 2005.
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
capacity payment to SMECO is approximately $462,000 per month.
The Company was a defendant in employment discrimination
litigation which was pending in the United States District Court
for the District of Columbia. In February 1993, the parties to
the case reached tentative settlement of the claims and, in April
1993, the Company paid $38.26 million into a trust fund pursuant
to the terms of the agreement. The funds will be disbursed from
the trust fund to certain covered classes of current and former
employees and applicants for employment and to cover the
plaintiffs' legal and expert fees and costs. The Court approved
the settlement agreement effective July 1993. The Company
received insurance payments of $13.5 million in October 1993 and
$24 million in January 1994, bringing the total recovered from
insurance companies to $37.5 million. At December 31, 1993,
approximately $.8 million was charged to non-operating expense.
51
In August 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
Cases." 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 four hundred and
forty-eight (448) individual plaintiffs added the Company to
their Complaints. While the pleadings are not entirely clear, it
appears that each plaintiff seeks $2 million in compensatory
damages and $4 million in punitive damages from each defendant.
In a related proceeding in the Baltimore City case, the Company
was served, in September 1993, with a third party complaint by
Owens Corning Fiberglass, Inc. (Owens Corning) alleging that
Owens Corning was in the process of settling approximately 700
individual asbestos-related cases and seeking a judgment for
contribution against the Company on the same theory of alleged
negligence set forth above in the plaintiffs' case.
Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed
a third party complaint against the Company, seeking contribution
for the same plaintiffs involved in the Owens Corning third party
complaint. Since the filings, a number of the individual suits
have been disposed of without any payment by the Company. While
the aggregate amount specified in the remaining suits would
exceed $1 billion, the Company believes the amounts are greatly
exaggerated as were the claims already disposed of. The amount
of total liability, if any, and any related insurance recovery
cannot be precisely determined at this time; however, based on
information and relevant circumstances known at this time, the
Company does not believe these suits will have a material adverse
effect on its financial position.
The Company is subject to contingencies associated with
environmental matters, principally related to possible
obligations to remove or mitigate the effects on the environment
of the disposal of certain substances at the sites discussed
below.
During 1993, the Company participated with two other
potentially responsible parties (PRPs) in a removal action at a
site in Harmony, West Virginia pursuant to an Administrative
Order (AO) issued by the Environmental Protection Agency (EPA).
Approximately $3 million (of which the Company has paid one-
third, subject to possible reallocation) was expended on the
removal action, which the EPA has stated is in compliance with
the AO. Approximately $1.9 million of this cost has now been
recovered from third parties. EPA oversight costs, which are not
expected to be material, have not yet been assessed. While
compliance with the AO has been completed, the Company cannot
determine whether it will be subject to any future liability with
respect to this site.
52
The Company is currently participating with certain other PRPs
in a Remedial Investigation/Feasibility Study (RI/FS) with
respect to a site in Philadelphia, Pennsylvania. Pursuant to an
agreement among the participating PRPs, the Company is
responsible for 12% of the costs of the RI/FS. Total costs of
the RI/FS, including legal fees, are currently estimated to be
$6.5 million. The Company has paid $548,000 to date. The
Company cannot estimate the extent of the EPA's administrative
and oversight costs or the expense associated with a remedy
ultimately acceptable to the EPA with respect to this site.
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.
53
(13) Supplemental Cash Flow Information
----------------------------------
Listed below is supplemental disclosure of cash flow information.
- -----------------------------------------------------------------
1993 1992 1991
- -----------------------------------------------------------------
(Thousands of Dollars)
Cash paid for:
Interest, net of capitalized
interest (including nonutility
subsidiary interest of $76,556,
$86,917 and $71,636) $206,955 $204,657 $181,311
Income taxes $ 67,741 $ 52,764 $ 59,318
Nonutility subsidiary noncash
transactions:
Promissory note received in
exchange for equipment $ - $ 10,000 $ -
Property transferred to
partnership $ - $ - $ 84,356
Consolidation of majority-owned
subsidiaries $ 35,320 $ - $ -
- -----------------------------------------------------------------
For purposes of the consolidated financial statements, cash and
cash equivalents include cash on hand, money market funds and
commercial paper with maturities of three months or less.
54
(14) Selected Nonutility Subsidiary Financial Information
----------------------------------------------------
Selected financial information of the Company's principal
consolidated nonutility investment subsidiary, Potomac Capital
Investment Corporation (PCI) and its subsidiaries, is presented
below. The Company's equity investment in PCI, which was reduced
by a $14 million dividend in 1993 and a $12 million dividend in
1992, was $290.9 million and $278.6 million at December 31, 1993
and 1992, respectively.
- -----------------------------------------------------------------
For the year ended
December 31,
1993 1992 1991
- -----------------------------------------------------------------
(Thousands of Dollars)
Income
Leasing activities $114,226 $122,087 $128,714
Marketable securities 38,417 37,062 21,095
Other investments (13,302) 2,005 (4,752)
-------- -------- --------
139,341 161,154 145,057
-------- -------- --------
Expenses
Interest 77,861 86,156 80,269
Administrative and general 14,640 9,762 14,021
Depreciation and operating 66,817 34,559 27,667
Income tax expense (45,078) 2,516 (251)
-------- -------- --------
114,240 132,993 121,706
-------- -------- --------
Net earnings from nonutility
subsidiary $ 25,101 $ 28,161 $ 23,351
======== ======== ========
55
Marketable Securities
- ---------------------
At December 31, 1993, marketable securities consist primarily of
preferred stocks with mandatory redemption features and corporate
debt securities. Preferred stocks with mandatory redemption
features and corporate debt securities are generally carried at
cost and amortized cost, respectively. PCI has both the ability
and intent to hold these securities until maturity. Certain of
these securities which PCI believes have been permanently
impaired have been carried at estimated net realizable value.
Equity securities have been carried at the lower of cost or
market and any unrealized losses thereon are recognized, net of
tax, in common equity. At December 31, 1992, the cost of equity
securities exceeded the carrying value by approximately $1.8
million.
- -----------------------------------------------------------------
December 31,
1993 1992
- -----------------------------------------------------------------
(Thousands of Dollars)
Carrying Market Carrying Market
Value Value Value Value
--------- -------- -------- --------
Mandatory redeemable
preferred stock $465,034 $472,633 $365,029 $374,428
Debt securities 1,116 518 3,223 1,622
Equity securities 3 - 28,931 28,931
-------- -------- -------- --------
Total $466,153 $473,151 $397,183 $404,981
======== ======== ======== ========
- -----------------------------------------------------------------
Net recognized gains or losses from marketable securities
amounted to gains of $7 million and $7.5 million in 1993 and
1992, respectively, and a loss of $7.7 million in 1991.
In May 1993, the FASB issued SFAS No. 115 entitled "Accounting
for Certain Investments in Debt and Equity Securities," which
will become effective for fiscal years beginning after December
15, 1993. The Company is evaluating the effects of applying SFAS
No. 115 and does not expect implementation to have a material
impact on the results of operations.
56
Investment in Finance Leases
- ----------------------------
PCI's net investment in finance leases consists primarily of
direct finance leases and are summarized below.
- -----------------------------------------------------------------
December 31,
1993 1992
- -----------------------------------------------------------------
(Thousands of Dollars)
Rents receivable $419,284 $601,084
Estimated residual values 155,187 162,646
Less: Unearned and deferred income (215,947) (307,052)
-------- --------
Investment in finance leases 358,524 456,678
Less: Deferred taxes arising from
finance leases (130,833) (167,555)
-------- --------
Net investment in finance leases $227,691 $289,123
======== ========
- -----------------------------------------------------------------
Minimum lease payments receivable from finance leases,
primarily aircraft, for each of the years 1994 through 1998 are
$29.5 million, $30.6 million, $29.4 million, $27.1 million and
$31.2 million, respectively. Net income from leveraged leases
was $1.1 million in 1993, $7.1 million in 1992 and $2.5 million
in 1991.
Operating Lease Equipment
- -------------------------
Rent payments receivable from aircraft equipment operating leases
for each of the years 1994 through 1998 are $51.8 million in
1994, $48.1 million in 1995, $46.6 million in 1996, $43.9 million
in 1997 and $34.7 million in 1998.
57
<TABLE>
(15) Quarterly Financial Summary (Unaudited)
- ------------------------------------------------------------------------------
- ---------------------------------------
1st 2nd
3rd 4th
Quarter Quarter
Quarter Quarter Total
- ------------------------------------------------------------------------------
- ---------------------------------------
(Thousands of
Dollars except Per Share Data)
<CAPTION>
<S> <C> <C>
<C> <C> <C>
1993
Operating Revenue $ 331,236 416,152
610,540 344,514 1,702,442
Total Revenue $ 339,455 419,693
614,261 351,796 1,725,205
Operating Expenses $ 302,833 332,796
442,306 322,608 1,400,543
Operating Income $ 36,622 86,897
171,955 29,188 324,662
Net Income $ 13,044 77,022
144,671 6,842 241,579
Earnings for Common Stock $ 8,931 72,974
140,631 2,788 225,324
Earnings Per Common Share $ .08 .63
1.21 0.02 1.95
Dividends Per Share $ .41 .41
.41 .41 1.64
1992
Operating Revenue $ 321,119 381,294
544,753 315,001 1,562,167
Total Revenue $ 325,946 390,536
553,631 331,445 1,601,558
Operating Expenses $ 296,616 320,874
405,903 298,712 1,322,105
Operating Income $ 29,330 69,662
147,728 32,733 279,453
Income Before Cumulative Effect of Accounting Change $ 8,049 49,159
122,804 20,748 200,760
Cumulative Effect of Accounting Change,
Net of Income Taxes $ 16,022 -
- - 16,022
Net Income $ 24,071 49,159
122,804 20,748 216,782
Earnings for Common Stock $ 20,667 45,839
119,243 16,641 202,390
Earnings Per Common Share
Before Cumulative Effect of Accounting Change $ .04 .41
1.06 .15 1.66
Cumulative Effect of Accounting Change $ .14 -
- - .14
Total $ .18 .41
1.06 .15 1.80
Dividends Per Share $ .40 .40
.40 .40 1.60
1991
Operating Revenue $ 289,522 361,063
562,710 338,771 1,552,066
Total Revenue $ 311,342 374,466
572,317 361,190 1,619,315
Operating Expenses $ 285,775 308,992
418,973 315,344 1,329,084
Operating Income $ 25,567 65,474
153,344 45,846 290,231
Net Income $ 6,943 42,755
132,923 27,543 210,164
Earnings for Common Stock $ 4,253 40,047
129,463 24,103 197,866
Earnings Per Common Share $ .04 .38
1.21 .22 1.87
Dividends Per Share $ .39 .39
.39 .39 1.56
</TABLE>
The Company's sales of electric energy are seasonal and, accordingly,
comparisons by quarter within a year are not meaningful.
The total of the four quarterly earnings per share may not equal
the earnings per share for the year due to changes in the number of
common shares outstanding during the year.
58
<TABLE>
Stock Market Information
- ------------------------------------------------------------------------------
- -----------------------------------------------
1993 High Low 1992
High Low
- ------------------------------------------------------------------------------
- -----------------------------------------------
<CAPTION>
<S> <C> <C> <C>
<C> <C>
1st Quarter $26-1/2 $23-7/8 1st Quarter
$25-1/8 $22-3/4
2nd Quarter $27-3/8 $25-5/8 2nd Quarter
$26 $23
3rd Quarter $28-7/8 $27-1/8 3rd Quarter
$27-1/2 $25-1/8
4th Quarter $28-3/4 $24-5/8 4th Quarter
$26-3/4 $22-5/8
(Close $26-3/4) (Close $23-7/8)
Shareholders at December 31, 1993: 98,892
- ------------------------------------------------------------------------------
- -----------------------------------------------
</TABLE>
<TABLE>
Selected Consolidated Financial Data
- ------------------------------------------------------------------------------
- -----------------------------------------------
1993 1992 1991
1990 1989 1988 1983
- ------------------------------------------------------------------------------
- -----------------------------------------------
(Thousands except
Per Share Data)
<CAPTION>
<S> <C> <C> <C> <C>
<C> <C> <C>
Operating Revenue $1,702,442 1,562,167 1,552,066
1,411,713 1,394,909 1,349,811 1,169,729
Total Revenue $1,725,205 1,601,558 1,619,315
1,501,728 1,531,024 1,411,630 1,308,735
Operating Expenses $1,400,543 1,322,105 1,329,084
1,245,579 1,256,553 1,138,667 1,091,617
Net Earnings from Nonutility
Subsidiary $ 25,101 28,161 23,351
5,035 31,100 27,938 181
Income Before Cumulative Effect of
Accounting Change $ 241,579 200,760 210,164
170,234 214,587 211,073 140,051
Cumulative Effect of Accounting
Change, Net of Income Taxes $ - 16,022 -
- - - -
Net Income $ 241,579 216,782 210,164
170,234 214,587 211,073 140,051
Earnings for Common Stock $ 225,324 202,390 197,866
159,636 205,352 201,832 123,805
Average Common Shares Outstanding 115,640 112,390 105,911
98,621 95,203 94,450 93,135
Earnings Per Common Share
Before Cumulative Effect of
Accounting Change $ 1.95 1.66 1.87
1.62 2.16 2.14 1.33
Cumulative Effect of Accounting
Change $ - .14 -
- - - -
Total $ 1.95 1.80 1.87
1.62 2.16 2.14 1.33
Cash Dividends Per Common Share $ 1.64 1.60 1.56
1.52 1.46 1.38 0.89
Investment in Property
and Plant $5,665,141 5,367,624 5,048,121
4,659,280 4,270,718 3,945,739 3,043,236
Net Investment in Property
and Plant $4,131,142 3,931,257 3,706,866
3,397,992 3,097,532 2,857,006 2,282,748
Utility Assets $5,000,328 4,478,762 4,174,713
3,852,415 3,528,883 3,267,465 2,732,394
Nonutility Subsidiary Assets $1,665,132 1,663,508 1,679,079
1,387,247 1,113,827 878,990 30,195
Total Assets $6,665,460 6,142,270 5,853,792
5,239,662 4,642,710 4,146,455 2,762,589
Long-Term Utility Obligations
(including redeemable preferred
and preference stock) $1,736,621 1,727,609 1,662,157
1,516,073 1,286,429 1,243,490 1,133,621
- ------------------------------------------------------------------------------
- -----------------------------------------------
59
</TABLE>
Report of Independent Accountants
To the Shareholders and
Board of Directors of
Potomac Electric Power Company
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of earnings and of cash flows
present fairly, in all material respects, the financial position
of Potomac Electric Power Company and its subsidiaries at
December 31, 1993 and 1992, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1993, 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.
As discussed in Notes 1 and 3 of the Notes to Consolidated
Financial Statements, respectively, the Company changed its
methods of accounting for income taxes and other postretirement
benefits in 1993. As also discussed in Note 1, the Company
changed its method of accounting for unbilled revenues in 1992.
/s/ Price Waterhouse
Price Waterhouse
Washington, D.C.
January 21, 1994
60
