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 27, 1995
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.
27 Financial Data Schedule..........Filed herewith.
99 The 1994 consolidated financial
statements of the Company and
Subsidiaries, together with the
report thereon of Price Waterhouse
dated January 26, 1995; 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)
/s/ H. Lowell Davis
By ___________________________
H. Lowell Davis
Vice Chairman and
Chief Financial Officer
January 27, 1995
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 1994 through 1990 on the basis of parent company operations only, are
as follows.
<CAPTION>
For The Year Ended December 31,
-----------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $208,074 $216,478 $172,599 $186,813 $165,199
Taxes based on income 116,648 107,223 76,965 80,988 70,962
-------- -------- -------- -------- --------
Income before taxes and cumulative effect
of accounting change 324,722 323,701 249,564 267,801 236,161
-------- -------- -------- -------- --------
Fixed charges:
Interest charges 139,210 141,393 138,097 138,512 127,386
Interest factor in rentals 6,300 5,859 6,140 5,690 4,237
-------- -------- -------- -------- --------
Total fixed charges 145,510 147,252 144,237 144,202 131,623
-------- -------- -------- -------- --------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $470,232 $470,953 $393,801 $412,003 $367,784
======== ======== ======== ======== ========
Coverage of fixed charges 3.23 3.20 2.73 2.86 2.79
==== ==== ==== ==== ====
Preferred dividend requirements $16,437 $16,255 $14,392 $12,298 $10,598
-------- -------- -------- -------- --------
Ratio of pre-tax income to net income 1.56 1.50 1.45 1.43 1.43
---- ---- ---- ---- ----
Preferred dividend factor $25,642 $24,383 $20,868 $17,586 $15,155
-------- -------- -------- -------- --------
Total fixed charges and preferred dividends $171,152 $171,635 $165,105 $161,788 $146,778
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.75 2.74 2.39 2.55 2.51
==== ==== ==== ==== ====
</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 1994 through 1990 on a fully consolidated basis are as follows.
<CAPTION>
For The Year Ended December 31,
-----------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
(Thousands of Dollars)
Net income before cumulative effect
of accounting change $227,162 $241,579 $200,760 $210,164 $170,234
Taxes based on income 93,953 62,145 79,481 80,737 63,360
-------- -------- -------- -------- --------
Income before taxes and cumulative effect
of accounting change 321,115 303,724 280,241 290,901 233,594
-------- -------- -------- -------- --------
Fixed charges:
Interest charges 224,514 221,312 226,453 225,323 199,469
Interest factor in rentals 9,938 9,257 6,599 6,080 4,559
-------- -------- -------- -------- --------
Total fixed charges 234,452 230,569 233,052 231,403 204,028
-------- -------- -------- -------- --------
Nonutility subsidiary capitalized interest (521) (2,059) (2,200) (6,542) -
-------- -------- -------- -------- --------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $555,046 $532,234 $511,093 $515,762 $437,622
======== ======== ======== ======== ========
Coverage of fixed charges 2.37 2.31 2.19 2.23 2.14
==== ==== ==== ==== ====
Preferred dividend requirements $16,437 $16,255 $14,392 $12,298 $10,598
-------- -------- -------- -------- --------
Ratio of pre-tax income to net income 1.41 1.26 1.40 1.38 1.37
---- ---- ---- ---- ----
Preferred dividend factor $23,176 $20,481 $20,149 $16,971 $14,519
-------- -------- -------- -------- --------
Total fixed charges and preferred dividends $257,628 $251,050 $253,201 $248,374 $218,547
======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.15 2.12 2.02 2.08 2.00
==== ==== ==== ==== ====
</TABLE>
Item 7
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Prospectuses constituting parts of the Registration Statements on
Form S-8 (Number 33-36798, 33-53685 and 33-54197) and on Form S-3
(Numbers 33-58810 and 33-50377) of Potomac Electric Power Company
of our report dated January 26, 1995 appearing on page 26 of
Exhibit 99 of the Current Report on Form 8-K of Potomac Electric
Power Company dated January 27, 1995.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Washington, D.C.
January 27, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,291,295
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 430,081
<TOTAL-DEFERRED-CHARGES> 563,126
<OTHER-ASSETS> 1,681,254
<TOTAL-ASSETS> 6,965,756
<COMMON> 118,248
<CAPITAL-SURPLUS-PAID-IN> 1,006,526
<RETAINED-EARNINGS> 830,524
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,955,298
143,563
125,409
<LONG-TERM-DEBT-NET> 1,723,399
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 189,600<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 45,445
0
<CAPITAL-LEASE-OBLIGATIONS> 136,723
<LEASES-CURRENT> 15,233
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,631,086
<TOT-CAPITALIZATION-AND-LIAB> 6,965,756
<GROSS-OPERATING-REVENUE> 1,823,074
<INCOME-TAX-EXPENSE> 119,859
<OTHER-OPERATING-EXPENSES> 1,378,722
<TOTAL-OPERATING-EXPENSES> 1,498,581
<OPERATING-INCOME-LOSS> 324,493
<OTHER-INCOME-NET> 32,257
<INCOME-BEFORE-INTEREST-EXPEN> 356,750
<TOTAL-INTEREST-EXPENSE> 129,588
<NET-INCOME> 227,162
16,437
<EARNINGS-AVAILABLE-FOR-COMM> 210,725
<COMMON-STOCK-DIVIDENDS> 195,755
<TOTAL-INTEREST-ON-BONDS> 123,700<F2>
<CASH-FLOW-OPERATIONS> 376,450
<EPS-PRIMARY> $1.79
<EPS-DILUTED> 0<F3>
<FN>
<F1>Included on the Balance Sheet in the caption "Short-term debt."
<F2>Total annualized interest costs for all utility long-term debt outstanding
at December 31, 1994.
<F3>No material dilution would occur if all the convertible preferred stock and
debentures were converted into common stock.
</FN>
</TABLE>
Item 7
Exhibit 99
Financial Information
- ---------------------
Potomac Electric Power Company and Subsidiaries
Contents
- --------
Management's Discussion and Analysis of
Consolidated Results of Operations and
Financial Condition...................................... 2
Report of Independent Accountants.......................... 26
Consolidated Statements of Earnings........................ 27
Consolidated Balance Sheets................................ 28
Consolidated Statements of Cash Flows...................... 30
Notes to Consolidated Financial Statements................. 31
Selected Consolidated Financial Data....................... 69
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 1994. 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
1992 through 1994 for the Company and PCI.
The Company's earnings for common stock during 1994 totaled
$210.7 million, as compared to $225.3 million in 1993. As set
forth below, earnings per share for common stock decreased from
$1.95 in 1993 to $1.79 for 1994.
The 1992 earnings per share amount from utility operations
shown below includes $.14 as the cumulative effect of an
accounting change for unbilled revenue.
- -----------------------------------------------------------------
1994 1993 1992
- -----------------------------------------------------------------
Utility Operations $1.63 $1.73 $1.55
Nonutility Subsidiary .16 .22 .25
----- ----- -----
Consolidated $1.79 $1.95 $1.80
===== ===== =====
- ----------------------------------------------------------------
The average number of common shares outstanding at December 31,
1994 increased by 2.4 million shares as compared to December 31,
1993.
Utility earnings for 1994 reflect the effect on electricity
sales and revenue of mild weather during the 1994 summer cooling
season as compared to the unseasonably hot weather during the
1993 summer cooling season, partially offset by the continued
effect of the 1993 base rate increases in Maryland. Although
1994 revenue increased as a result of the base rate increase
authorized by the District of Columbia during the year, the
2
earnings impact was limited since this revenue increase was
substantially offset by write-offs resulting from the rate order,
as explained in the discussion of "Other Income" below.
UTILITY
- -------
Results of Operations
- ---------------------
Total Revenue
- -------------
The changes in total revenue are shown in the following table.
- -----------------------------------------------------------------
Increase (Decrease)
from Prior Year
1994 1993 1992
- -----------------------------------------------------------------
(Millions of Dollars)
Change in kilowatt-hour sales $(18.7) $ 87.0 $(39.1)
Change in base rate revenue 32.2 45.4 71.8
Change in fuel adjustment clause
billings to cover cost of
fuel and interchange 73.2 8.0 (19.2)
Change in other revenue 1.5 (.1) (3.4)
------ ----- -----
Change in Operating Revenue 88.2 140.3 10.1
------ ------ ------
Change in interchange deliveries 9.7 (16.7) (27.9)
------ ------ ------
Change in Total Revenue $ 97.9 $123.6 $(17.8)
====== ====== ======
- -----------------------------------------------------------------
The $32.2 million change in 1994 base rate revenue compared
to 1993 reflects the effect of a District of Columbia rate
increase of $26.7 million (effective primarily in March 1994) and
the continued effect of 1993 rate increases in Maryland. Also,
1994 revenue reflects cooler weather during the summer billing
months of June through October as compared to the warmer than
average weather during the corresponding period in 1993. Summer
period base rates are high to encourage customer conservation and
peak load shifting. In addition, 1994 base rate revenue reflects
approximately $5 million for achieving specified 1993 Maryland
energy goals associated with the conservation incentive provision
of the Company's Demand Side Management (DSM) surcharge tariff.
3
The increase in base rate revenue in 1993 as compared to
1992 reflects the effects of Maryland rate increases of $7.3
million (effective June 1993) and $27 million (effective November
1993) and the continued effect of 1992 rate increases in both of
the Company's retail jurisdictions. Also, 1993 revenue reflects
warmer than average weather during the summer billing months of
June through October.
Base rate revenue for 1992 compared to 1991 was 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 on 1992 revenue.
An increase in 1994 and decreases in 1993 and 1992 in
revenue from interchange deliveries reflect changes in levels and
pricing in energy delivered to the Pennsylvania-New Jersey-
Maryland Interconnection Association (PJM). Interchange
deliveries continue to be a component of the Company's fuel
rates.
4
Kilowatt-hour Sales
- -------------------
- -----------------------------------------------------------------
1994 1993
vs. vs.
1994 1993 1992 1993 1992
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
By Customer Type
Residential 6,574 6,727 6,142 (2.3)% 9.5%
Commercial 11,685 11,751 11,391 (.6) 3.2
U.S. Government 4,010 3,986 3,948 .6 1.0
D.C. Government 914 903 873 1.2 3.4
Wholesale 2,363 2,327 2,130 1.5 9.2
------ ------ ------
Total energy sales 25,546 25,694 24,484 (.6) 4.9
====== ====== ======
Interchange
Energy deliveries 800 483 771 65.6 (37.4)
====== ====== ======
By Geographic Area
Maryland, including
wholesale 15,251 15,319 14,441 (.4) 6.1
District of Columbia 10,295 10,375 10,043 (.8) 3.3
------ ------ ------
Total energy sales 25,546 25,694 24,484 (.6) 4.9
====== ====== ======
- -----------------------------------------------------------------
The slight decrease in kilowatt-hour sales in 1994,
following a 4.9% increase in 1993, reflects primarily decreased
customer usage of electricity during the summer cooling season
(June through October) due to mild weather during these months as
compared to the unseasonably hot weather during the same period
in 1993, partially offset by an increase of .9% in the number of
customers. Cooling degree hours during 1994 were 14% below those
in 1993 and 5% above the 20-year average. The increase in
kilowatt-hour sales in 1993 compared to 1992 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. 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 Company's 1994 summer peak demand was 5,660 megawatts,
1.6% below the 1993 summer peak demand of 5,754 megawatts and
1.9% 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 6,723
megawatts. To meet the 1994 summer peak demand, the Company had
5
256 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. The all-time winter peak
demand of 5,010 megawatts was established in January 1994, which
was 11.1% above the previous winter peak demand of 4,511
megawatts which occurred in December 1989.
Operating Expenses
- ------------------
Fuel, Purchased Energy and Capacity Purchase Payments
- -----------------------------------------------------
1994 1993 1992
- -----------------------------------------------------------------
(Millions of Dollars)
Fuel expense $392.7 $354.3 $345.5
------ ------ ------
Purchased energy
PJM receipts 108.8 108.9 94.6
Other purchases 64.6 64.5 72.0
------ ------ ------
Total purchased energy 173.4 173.4 166.6
------ ------ ------
Fuel and purchased energy $566.1 $527.7 $512.1
====== ====== ======
Capacity purchase payments $127.8 $ 96.3 $ 95.5
====== ====== ======
- -----------------------------------------------------------------
Net System Generation and Purchased Energy was as follows.
- -----------------------------------------------------------------
1994 1993 1992
- -----------------------------------------------------------------
(Millions of Kilowatt-hours)
Net system generation 19,320 19,145 18,274
====== ====== ======
Purchased energy 8,356 8,448 8,251
====== ====== ======
- -----------------------------------------------------------------
The 1994 increase in fuel expense reflects an increase of
.9% in net generation and increased use of major cycling and
peaking generation units which burn higher costs fuels. During
January 1994, severe cold weather sent demand for electricity to
a new winter peak, which required significantly increased net
generation. Major cycling and peaking generation units were used
to meet the increased demand. The 1993 increase in fuel expense
primarily reflects a 4.8% increase in net generation resulting
6
from the increase in kilowatt-hour sales, partially offset by the
Company's ability to purchase low-cost economy energy from PJM
which helped keep the fuel expense increase to a minimum. Fuel
expense in 1992 primarily reflects a decrease 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)
1994 76.1 18.4 5.5 $1.73 $2.70 $2.49 $1.95
1993 79.4 17.4 3.2 1.72 2.55 2.88 1.90
1992 82.9 12.6 4.5 1.72 2.50 2.32 1.85
- -----------------------------------------------------------------
The increase of approximately 3% in each of the past two
years in the system average unit fuel cost resulted from
increased use of major cycling and peaking generation units which
burn higher cost fuels. The Company's major cycling and certain
peaking units can burn natural gas or oil, adding flexibility in
selecting the most cost-effective fuel mix. The increase in the
actual percent of gas contribution in 1994 to the fuel mix
reflects the decreased price of gas and the increased price of
oil. The decrease in the actual percent of coal contribution to
the fuel mix in 1994 primarily reflects major outages for
construction related to Clean Air Act additions on baseload coal
generation units.
The Company's generating and transmission facilities are
interconnected with the other members of PJM and other utilities.
The pricing of most PJM internal economy energy transactions is
based upon "split savings" so that the price of such energy is
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.
7
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 monthly capacity commitment under
these agreements, excluding an allocation of fixed operating and
maintenance cost, increased from $12,380 per megawatt through
1993 to $18,060 per megawatt effective January 1994, with
provision for escalation in 1999. In addition, effective June 1,
1994 through May 31, 1995, the Company is purchasing 147
megawatts of capacity from Pennsylvania Power and Light Company
at a total cost of $3 million.
The Company has a purchase agreement with SMECO, through
2015, for 84 megawatts of capacity supplied by a combustion
turbine installed and owned by SMECO at the Company's Chalk Point
Generating Station. The Company is responsible for all costs
associated with operating and maintaining the facility. The
capacity payment to SMECO is $462,000 per month.
Other Operation and Maintenance Expenses
- ----------------------------------------
Other operation and maintenance expenses totaled $298.7 million
for 1994. These expenses decreased by $2.8 million (.9%) in 1994
and increased by $6.2 million (2.1%) and $8.1 million (2.8%) in
1993 and 1992, respectively. The relative stability in other
operation and maintenance expense was achieved through the
Company's budget and cost control disciplines, which over the
past three years, have resulted in an 6% decline in the number of
Company employees, and other programs to curb increases in
expenses. In September 1994, to further reduce future costs and
staffing levels, the Company announced a Voluntary Severance
Program (VSP). As an incentive to voluntarily sever employment
no later than the first quarter of 1995, the VSP offered a
severance payment to any full-time employee with five or more
years of service with the Company, based on two weeks of pay for
each year of service, not to exceed 52 weeks of pay.
Approximately 340 of the Company's employees will participate in
the VSP. During January 1995, approximately $7.4 million in
severance costs was expensed. For 1994 and 1993, respectively,
other operation expense included $8.7 million and $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 included in Note (3) of the Notes to
Consolidated Financial Statements, Pensions and Other
Postretirement and Postemployment Benefits, for additional
information.
8
Depreciation and Amortization Expense, Income Taxes and
Other Taxes
- -------------------------------------------------------
Depreciation and amortization expense increased by $16.4 million
(10%), $13.8 million (9.2%) and $15.4 million (11.5%) in 1994,
1993 and 1992, respectively, due to additional investment in
property and plant and amortization of increased amounts of
conservation program costs. The increase in income taxes in 1994
reflects an increase in taxable operating income. The 1993
increase in income taxes reflects the higher federal income tax
rate which became effective in 1993 and higher taxable income.
Income taxes in 1992 reflects lower taxable income. Other taxes
increased by $4.8 million (2.4%), $7.1 million (3.6%) and $27.7
million (16.6%) in 1994, 1993 and 1992, respectively. The
increases reflect changes in the levels of operating revenue and
plant investment upon which taxes are based. The substantial
1992 increase 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 $19.1 million in 1994, $25.1 million in
1993 and $28.2 million in 1992. See the Nonutility Subsidiary
discussion below and the discussion included in Note (15) of the
Notes to Consolidated Financial Statements, Selected Nonutility
Subsidiary Financial Information. In addition, other income in
1994 reflects a total after tax reduction of approximately $4.1
million in connection with District of Columbia Public Service
Commission decisions in Formal Case No. 929. This includes
disallowance of rate case test period DSM program expenditures,
adoption of an unbilled revenue adjustment applicable to the
District of Columbia portion of the 1992 accounting change
related to unbilled revenue and adoption of a three year phase-in
period to reflect increased postretirement benefit costs. See
Base Rate Proceedings, District of Columbia, for additional
information. In addition, other income reflects accrued capital
cost recovery factor (CCRF) amounts in "Other, net" of $10.2
million, $8 million and $2.9 million in 1994, 1993 and 1992,
respectively. CCRF is a mechanism which enables the Company to
earn a return on certain costs, principally unamortized DSM
costs, which are not in rate base. In general, CCRF is earned
only on costs specifically allowed by the Company's regulators
with provision for cost recovery on a jurisdictional basis.
"Other, net" also includes $2.8 million in 1993 from the adoption
of SFAS No. 109. See note (4) of the Notes to Consolidated
Financial Statements, Income Taxes, for additional information.
9
Net utility interest charges were relatively stable during
the three-year period 1992 through 1994, 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 8.26% at the beginning of 1992 to 7.56% at the end
of 1994. Allowance For Funds Used During Construction (AFUDC)
credits, which decreased during the period 1992 through 1994,
relate to portions of the Company's Construction Work In Progress
investment. See the Construction and Capacity Additions
discussion below.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's total investment in property and plant, at original
cost, was $5.9 billion at year-end 1994. Investment in property
and plant construction, net of AFUDC, was $926.1 million for the
period 1992 through 1994.
Internally generated cash from utility operations, after
dividends, totaled $268.4 million for the period 1992 through
1994. Sales of First Mortgage Bonds, Medium-Term Notes,
Convertible Debentures, Serial Preferred Stock and Common Stock
during the period 1992 through 1994 provided a total of $1.3
billion. During the years 1992 through 1994, the Company retired
$916.7 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 1995 through 1997, capital resources of
$233.5 million ($45.4 million in 1995) 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 $758 million is expected to be available
from depreciation and amortization charges and income tax
deferrals over the three-year period of which approximately $244
million is the 1995 portion.
During 1994, the Company sold $80.8 million principal amount
of First Mortgage Bonds, $225 million principal amount of Medium-
Term Notes and $9.3 million of Common Stock. Proceeds, together
with proceeds from a sale and leaseback agreement discussed
below, were applied to meet construction requirements of $298.1
million, scheduled debt maturities, sinking fund requirements and
the refinancing of higher cost debt totaling $144.4 million and
to reduce short-term borrowings by $105 million. See the
discussion included in Notes (7) and (10) of the Notes to
Consolidated Financial Statements, Common Equity and Long-Term
Debt, respectively, for additional information.
10
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, 1994
was $123.7 million, compared with $114 million and $131.9 million
at December 31, 1993 and 1992, respectively.
During December 1994, the Company entered into a sale (at
cost) and leaseback agreement for its new control center system
(system). The system is an integrated energy management system
used by the Company's power dispatchers to centrally control the
operation of the Company's electric system, which consists of all
of its generating units, the transmission system and the
distribution system. The Company has accounted for the lease of
the system as a capital lease, recorded at the present value of
future lease payments which totaled $152 million at December 31,
1994. The lease requires semi-annual payments of $7.6 million
over a 25-year period. This lease has been treated as an
operating lease for ratemaking purposes.
Dividends on preferred stock were $16.4 million in 1994,
$16.3 million in 1993 and $14.4 million in 1992. The embedded
cost of preferred stock was 6.37% at December 31, 1991, and 6.53%
at December 31, 1994.
The Company's capitalization ratios (excluding nonutility
subsidiary debt), at December 31, 1994, are presented below.
- -----------------------------------------------------------------
Excluding Including
Amounts Due Amounts Due
In One Year In One Year
- -----------------------------------------------------------------
Long-term debt 43.7% 41.2%
Redeemable serial preferred stock 3.6 3.4
Serial preferred stock 3.2 3.0
Common equity 49.5 46.8
Short-term debt and amounts due in
one year - 5.6
----- -----
Total capitalization 100.0% 100.0%
===== =====
- -----------------------------------------------------------------
In September 1994, the Company filed for a 5.3% increase in
the Maryland fuel rate, which became effective, subject to
refund, on November 1, 1994. The initial filing also included an
adjustment for a deferred fuel amortization charge to recover
over a twelve month period approximately $28.5 million of
previously unrecovered fuel costs incurred through July 31, 1994.
During the case, which is still pending, the Company updated the
proposed deferred fuel amortization, pursuant to a recommendation
of the Staff of the Maryland Public Service Commission, to
11
reflect a reduction in the unrecovered amount at October 31, 1994
to $21.1 million. A final order is expected during the first
quarter of 1995. Based on results for the period ended November
30, 1994, the Company filed for a fuel rate reduction in Maryland
of 5.3%.
Year-end 1994 outstanding utility short-term indebtedness
totaled $189.6 million compared with $294.6 million and $61.6
million at the end of 1993 and 1992, respectively. At year-end
1994, the formula adopted by the Securities and Exchange
Commission would have permitted the Company to issue, without
registration, a total of $448 million in commercial promissory
notes.
The Company maintains a minimum 100% line of credit back-up
for its outstanding commercial promissory notes, which was unused
during 1994, 1993 and 1992.
1994 Least-Cost Resource Plan
- -----------------------------
The Company's 1994 energy plan, which was filed with regulators
in June 1994, is an integrated least-cost resource plan. As part
of the 1994 planning process, the Company has reassessed each of
its existing conservation programs. To reduce the near-term
upward pressure on prices and total customer bills, the Company
proposes to limit its current offering of DSM programs to those
with the strongest cost benefit results and has reduced
previously planned five-year conservation expenditures by
approximately $120 million.
Conservation
- ------------
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. During 1994,
the Company reevaluated its conservation programs, including
additional review and consideration of the current and
prospective effect of these programs on customer rates and bills.
As a result of this reevaluation, the Company phased out several
conservation programs and reduced rebate levels for others. In
addition, in November 1994 the Company temporarily suspended
approval of additional applications for its Custom Rebate
Program. By narrowing its conservation offerings, the Company
expects to be able to continue to encourage its customers to use
energy efficiently without significantly increasing electricity
prices. The Company expects approximately 80% of the previously
estimated benefits from conservation for approximately 45% of
estimated cost.
12
For residential customers the Company continues to offer
rebates for high efficiency heating and air conditioning
equipment. These rebates are paid directly to customers when
customers buy equipment which significantly exceeds the
efficiency of average available equipment.
In 1995, the Company expects to resume operation of its
highly successful Custom Rebate Program for commercial customers.
This program pays rebates to customers who install energy
efficient lighting, motors, heating and cooling systems and other
measures. The Company also continues to operate the New Building
Design Program, which offers cash incentives as well as technical
assistance to developers and designers who incorporate energy
efficient designs and equipment in new commercial construction.
During 1994, the Company invested almost $90 million in
energy conservation programs. The Company recovers the costs of
its conservation programs in its Maryland jurisdiction through a
rate surcharge which amortizes costs over a five year period and
permits the Company to earn a return on its conservation
investment while receiving compensation for lost revenue. In
addition, when the Company's performance exceeds its annual
goals, the Company earns a performance bonus. The Company was
awarded a bonus of $5 million in 1994 based on its 1993
performance. At the end of 1994 the conservation surcharge in
Maryland was $.00338 per kilowatt hour.
In the District of Columbia, conservation costs are
amortized over 10 years with an accrued return on unamortized
costs. To date, costs have been considered in base rate cases.
In March 1994, the District of Columbia Public Service Commission
denied cost recovery for 25% of the test year cost of operating
jurisdictional programs between rate case test years. The
disallowed costs totaled $2.2 million on an after tax basis. In
response to the Company's request for reconsideration, the
Commission directed that the Company's 1994 Least Cost Plan
filing include a proposed mechanism for rate recognition of costs
between base rate cases. The Company has appealed the
disallowance of DSM costs to the District of Columbia Court of
Appeals on the basis of the absence of record evidence supporting
this action and expects to receive an order on appeal in the
second quarter of 1995.
In 1994, approximately 151,000 customers participated in
continuing energy use management programs which cycle air
conditioners and water heaters during peak periods. In addition,
the Company operates a commercial load program which provides
incentives to customers for reducing energy use during peak
periods. Time-of-use rates have been in effect since the early
1980s and currently approximately 60% of the Company's revenue is
based on time-of-use rates.
13
It is estimated that peak load reductions of approximately
525 megawatts have been achieved to date from conservation and
energy use management programs and that additional peak load
reductions of approximately 380 megawatts will be achieved in the
next five years. The Company also estimates that in 1994 energy
savings of more than 760 million kilowatt-hours have been
realized through operation of its conservation and energy use
management programs. During the next five years, the Company
plans to expend an estimated $370 million ($86 million in 1995)
to encourage the efficient use of electric energy and to reduce
the need to build new generating facilities.
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC, are projected to
total $1.1 billion for the five-year period 1995 through 1999,
which includes $165 million of estimated Clean Air Act
expenditures. In 1995, construction expenditures are projected
to total $215 million, which includes $33 million of estimated
Clean Air Act expenditures. Making use of the flexibilities in
its long-term construction plan, the Company in 1994 reduced
projected expenditures for the five years 1995 through 1999 by
$190 million from amounts previously planned. This reduction
followed a $365 million reduction in 1993. The construction
reductions and deferrals are 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 primarily through funds
provided by operations.
A 40-megawatt resource recovery facility with which the
Company has a contract is now under construction in Montgomery
County, Maryland. In addition, the Company has an agreement with
Panda Energy Corporation for a 230-megawatt gas-fueled combined-
cycle cogeneration project in Prince George's County, Maryland.
This project has received a certificate of convenience and
necessity from the Maryland Public Service Commission. These
nonutility generation projects are expected to begin operating in
1995 and 1996, respectively. The Company currently projects that
existing contracts for nonutility generation and the Company's
commitment to conservation will provide adequate reserve margins
to meet customers' needs well beyond the year 2000. Completion
of the first combined-cycle unit at its Station H facility in
Dickerson, Maryland, is currently scheduled for 2004. This will
add a steam cycle to the two combustion turbine units, one of
which was installed in 1992 and one of which was installed in
1993.
14
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. Installation of scrubbers is not
contemplated for the Company's wholly owned plants. Both the
District of Columbia and Maryland commissions 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. The Company
anticipates CAA related capital expenditures totaling $165
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 cofiring 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.
During 1994, the Company entered into an agreement with
Emissions Exchange Corporation (EX) to exchange emission
allowances. The Company delivered to EX 25,000 allowances with
vintage dates of 1999 or earlier in exchange for receiving 30,000
allowances with vintage dates of 2004 or earlier in equal
installments in each of the years 2000 through 2004. This
agreement allows the Company to enter the CAA Phase II with a
reserve bank of allowances by trading allowances not currently
required for a greater number of future allowances, avoiding
price risks associated with selling excess Phase I and purchasing
Phase II allowances.
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. See the discussion included in Note (6) of the Notes to
Consolidated Financial Statements, Jointly Owned Generating
Facilities, for additional information.
BASE RATE PROCEEDINGS
- ---------------------
The Company is subject to utility rate regulation based upon the
historical costs of plant investment, using recent test years to
measure the cost of providing service. The rate-making process
does not give recognition to the current cost of replacing plant
and the impact of inflation. Possible changes in industry
15
structure and regulation may affect the extent to which future
rates are based upon current costs of providing service. The
regulatory commissions have authorized fuel rates which provide
for billing customers on a timely basis for the actual cost of
fuel and interchange, for purchased capacity in the District of
Columbia and emission allowance costs in both retail
jurisdictions.
Annual base rate increases and decreases which became
effective during the period 1992 through 1994 are shown below.
- -----------------------------------------------------------------
District
of
Year Total Maryland Columbia Wholesale
- -----------------------------------------------------------------
(Millions of Dollars)
1994 $ 29.3 $ - $26.7 $2.6
1993 38.1 34.3 - 3.8
1992 51.2 18.0 30.4 2.8
------ ----- ----- ----
$118.6 $52.3 $57.1 $9.2
====== ===== ===== ====
- -----------------------------------------------------------------
Maryland
- --------
In October 1993, pursuant to a settlement agreement, the
Commission authorized a $27 million, or 3%, increase in base rate
revenue 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. 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.
District of Columbia
- --------------------
In its pending base rate proceeding, the Company is currently
seeking a $60.6 million, or 8.2%, increase in base rate revenue,
based upon a 1994 calendar year test period and a return of 9.92%
on average rate base, including a 12.75% return on common stock
equity. This case was filed on September 30, 1994, requesting a
$67 million, or 9%, increase in base rate revenue. The Company
updated its initial cost of service data filing to reduce the
request to $60.6 million to reflect subsequent events which
included the sale and leaseback of the Control Center Replacement
project, a reduction in the 1995 District of Columbia income tax
rate, an approved traffic signal maintenance deregulation
16
agreement with the District of Columbia and an increase in the
FICA tax wage base. In accordance with Commission directives,
the Company has included conservation program expenditures
subsequent to June 1993 in the proposed Environmental Cost
Recovery Rider in its pending Least-Cost Planning proceeding
filed in June 1994. It is expected that both proceedings will be
concluded by mid-1995. On January 17, 1995, the Commission Staff
filed testimony recommending a $37.1 million rate increase.
In May 1994, the Commission ruled on the application for
reconsideration of its March 1994 rate order in Formal Case No.
929. The Commission's original order authorized the Company to
increase its base rates by a total of $25.4 million in two steps:
an increase of $23.2 million effective March 16, 1994 and an
increase of $2.2 million effective June 5, 1994. The order on
reconsideration authorized an additional "step 2" base rate
increase of $1.3 million resulting in a total base rate increase
of $26.7 million. Of the "step 2" increase, $3 million was
contingent on the June 1, 1994 in-service date of the final
segment of a 500 kilovolt transmission line which provides links
in the transmission systems of the Company, Baltimore Gas and
Electric Company and Virginia Power. This transmission line
segment was placed in service prior to June 1, 1994. The
authorized rates are based on a 9.05% rate of return on average
rate base, including an 11% return on common stock equity. Prior
to the order, the Company had filed updated cost of service data
which demonstrated a need for $55.4 million increase in District
of Columbia base rate revenue, based upon the requested return of
9.46% on average rate base including an 11.8% return on common
stock equity.
The Commission's rate increase order approved the Company's
proposal for including future changes in purchased capacity costs
in fuel adjustment billings. In addition, the Commission
reversed its longstanding practice of including Electric Plant
Held for Future Use in rate base. The Commission also authorized
an accounting change for postretirement benefit costs consistent
with Statement of Financial Accounting Standards (SFAS) No. 106
entitled "Employers' Accounting for Postretirement Benefits Other
Than Pensions" and adopted a three year phase-in approach for
inclusion of these increased costs in the Company's rates. In
June 1994, the Company established a regulatory asset for the
increase in postretirement benefit costs of $.6 million on an
after tax basis which will be amortized over a three year period.
The initial order also reduced the Company's revenue
requirement to reflect 20% of the cumulative effect of a 1992
accounting change related to unbilled revenue applicable to the
District of Columbia. The Commission's initial decision to adopt
an unbilled revenue adjustment, supplemented by its subsequent
decisions in response to the Company's application for
reconsideration and motion for clarification, has required the
17
Company to establish in June 1994 a regulatory liability of $2.5
million on an after tax basis which will be amortized in 1995 and
1996.
The Commission's initial decision, rejected the Company's
proposal to provide rate recognition of DSM costs through a
billing surcharge and consistent with prior decisions, included
$5.3 million in base rates to recognize DSM program costs without
provision for lost revenue between rate cases. In addition, the
initial decision and subsequent decisions in response to the
Company's application for reconsideration and motion for
clarification, disallowed the recovery of 25% of test period DSM
program expenditures which required the Company to write off $2.2
million on an after tax basis in June 1994. In its order on
reconsideration, the Commission stated that in the future the
appropriate forum for consideration for DSM cost recovery would
be the Company's least-cost resource planning cases, which the
Company files on a two-year cycle. Under this new process, DSM
approval and cost recovery will be linked together in the same
proceeding. Subsequent to June 1993, the Company has expended
through December 31, 1994, approximately $56 million on
conservation in the District of Columbia. The Company requested
a surcharge mechanism for billing unamortized DSM costs in its
June 1994 Least Cost Planning Case filing.
In July 1994, the Company filed a Petition for Review with
the District of Columbia Court of Appeals related to the
Commission's decisions in Formal Case No. 929 to disallow the
recovery of 25% of test period DSM program expenditures and to
reject an adjustment to reflect increases in employee benefit
costs. The Company expects to receive an order on appeal in the
second quarter of 1995.
Wholesale
- ---------
The Company has a 10-year full service 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 $2.3 million effective January
1, 1995. The rates were increased by $2.6 million and $3.8
million effective January 1, 1994 and 1993, respectively. A rate
increase of $4.2 million is scheduled to become effective January
1, 1996.
18
THE COVE POINT JOINT VENTURE
- ----------------------------
Subsidiaries of the Company and the Columbia Gas System, Inc.,
have formed a joint venture partnership (the Partnership) to own
and operate natural gas storage and terminaling facilities at
Cove Point, Maryland, and an 87-mile natural gas pipeline that
extends from Cove Point to Loudoun County, Virginia. These
facilities were previously owned by Columbia LNG Corporation, a
Columbia Gas subsidiary.
Under the agreement, Columbia LNG Corp. contributed its Cove
Point terminal and pipeline assets in exchange for an equity
interest in the Partnership, and the Company's subsidiaries
agreed to invest $25 million in the form of equity and debt.
This investment will be used by the Partnership to construct a
new liquefaction unit and to recommission certain existing
facilities at the terminal that will be used in the peaking
service discussed below. At December 31, 1994, the Company's
subsidiaries have invested $10 million in the Partnership.
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
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. On November 30, 1994, the
Partnership received a final order from the FERC granting
approval of the project on the basis of cost-of-service rates.
The Partnership accepted the FERC certificate during December
1994, and has begun construction and recommissioning activities.
The Partnership anticipates the new plant and recommissioned
facilities will be available for commercial operation in the fall
of 1995.
One of the Company's principal strategic interests in the
Cove Point project is to secure a reliable and cost-effective
source of transportation for gas to provide fuel to the
generators at its Chalk Point Generating Station. The Cove Point
pipeline is the sole means of delivering natural gas to southern
Maryland where Chalk Point is located. The Company has expanded
Chalk Point's fuel flexibility to burn increased amounts of gas
to comply with the CAA and minimize customer costs.
19
COMPETITION
- -----------
The electric utility industry is subject to increasing
competitive pressures, stemming from a combination of increasing
independent power production, greater reliance upon long-distance
transmission, and regulatory and legislative initiatives intended
to increase bulk power competition, including the Energy Policy
Act of 1992. Since the early 1980s, the Company has pursued
strategies which achieve financial flexibility through
conservation and energy use management programs, extension of the
useful life of generating equipment, cost-effective purchases of
capacity and energy and preservation of scheduling flexibility to
add new generating capacity in relatively small increments. The
Company serves a unique and stable service territory and is a
low-cost energy producer with customer prices which compare
favorably with regional and national averages.
Based on the regulatory framework in which it operates, the
Company currently applies the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" in
accounting for its utility operations. SFAS No. 71 allows
regulated entities, in appropriate circumstances, to establish
regulatory assets and to defer the income statement impact of
certain costs that are expected to be recovered in future rates.
Deregulation of portions of the Company's business could, in the
future, result in not meeting the rate recovery criteria for
application of SFAS No. 71 for part or all of the business.
While the Company does not foresee such a situation at this time,
if this were to occur in the transition to a more competitive
business, accounting standards of enterprises in general would
apply which would entail the write-off of any previously deferred
costs to results of operations. Regulatory assets include
deferred income taxes recoverable through future rates,
unamortized conservation costs and unamortized debt reacquisition
costs.
NEW ACCOUNTING STANDARDS
- ------------------------
Effective January 1, 1994, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 112 entitled
"Employers' Accounting for Postemployment Benefits" and SFAS No.
115 entitled "Accounting for Certain Investments in Debt and
Equity Securities." See the discussions included in Notes (3)
and (15) of the Notes to Consolidated Financial Statements,
Pensions and Other Postretirement Benefits and Selected
Nonutility Subsidiary Financial Information, respectively, for
additional information.
20
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 1994, the
Company was participating in environmental assessments and
cleanups under these laws at two federal Superfund sites and a
private party site as a result of litigation. While the total
cost of remediation at these sites may be substantial, the
Company shares liability with other potentially responsible
parties. Based on the information known to the Company at this
time, management is of the opinion that resolution of these
matters will not have a material effect on the results of
operations or financial position of the Company.
See the discussion included in Note (13) of the Notes to
Consolidated Financial Statements, Commitments and Contingencies,
for additional information.
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's net earnings totaled $19.1 million in 1994, compared with
$25.1 million in 1993 and $28.2 million in 1992. In 1994, PCI
contributed $.16 per share to PEPCO's consolidated earnings of
$1.79 per share. PCI contributed $.22, and $.25 per share,
respectively, to PEPCO's 1993 and 1992 consolidated earnings per
share. Earnings for the year 1994 were lower than 1993 primarily
as a result of the 1993 completion of a transaction whereby PCI
contributed aircraft, subject to direct finance leases, to a
majority owned partnership. 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 in 1993 as a reduction in income tax
expense. During 1994, modifications to this 1993 transaction
resulted in additional after tax earnings of $10 million.
Lower rent revenue and increased operating and maintenance
expenses for certain aircraft also contributed to the decrease in
PCI's net earnings from 1993 to 1994. At year-end 1994, a
portion ($263 million carrying value) of PCI's aircraft leasing
portfolio consisted of equipment not on lease (four L-1011
21
aircraft returned by Trans World Airlines (TWA) when leases
expired in November 1994) and equipment on short-term, and in
some cases, usage-based operating leases with monthly rentals and
maintenance payments dependent upon hours used. Under these
leases, PCI is responsible for future operating and maintenance
expenses exceeding amounts provided therefor by lessees and,
during 1994, PCI provided net charges of $8.3 million (before
tax) against earnings to establish reserves against such future
estimated expenses. Most of the usage-based and short-term
leases include provisions for early termination by PCI if more
favorable transactions become available. In January 1995,
because of the lessee's inability to make timely rental payments
and to satisfy other lease obligations, Fortunair Canada returned
one B747 aircraft previously under short-term lease. PCI is
continuing to seek new leases with more favorable terms or to
sell the equipment on satisfactory terms.
All rental payments due under equipment leases are current.
Continental Airlines (Continental) has announced that it intends
to seek the termination of certain A-300 aircraft leases and,
effective February 1, 1995, the reduction of rental payments due
under certain leases of other widebody aircraft. Pending
discussions with lessors, Continental has indicated that it will
not be making payments to such lessors as required by the terms
of its contracts. Continental has approached PCI to request
discussions regarding the return of one A-300 aircraft and the
renegotiation of certain other leases of widebody aircraft.
Continental has indicated that payments under these leases could
include debt securities convertible into equity in lieu of full
cash payments. PCI has informed Continental that it expects all
lease obligations to be satisfied in full.
There can be no assurance that PCI will be able to obtain
new leases, sell or otherwise dispose of aircraft on satisfactory
terms, following scheduled or unscheduled lease terminations.
22
PCI's aircraft portfolio at December 31, 1994 is summarized
below.
- -----------------------------------------------------------------
Type of Aircraft Year of
Lease Type (a) Lessee Quantity Manufacture
- -----------------------------------------------------------------
Operating B747-200 United Airlines 2 1978
Continental
Airlines 1 1972
Air Club 1 1976
Fortunair (c) 1 1977
B747-200F Atlas Air 1 1976
DC-10-30 Continental
Airlines (b) 5 1973(4), 1974
L1011-50 ING 2 1974
TWA 1 1975
L1011-100 None 4 1974, 1975(3)
A300-B4 Continental
Airlines 1 1979
F28-4000 US Air 2 1979, 1980
Direct
Finance DC-10-30 Continental
Airlines 1 1979
MD-82 Continental
Airlines (b) 3 1982, 1987(2)
B737-300 United Airlines (b) 4 1988
Leveraged B747-300 KLM (b) 1 1984
Singapore
Airlines (b) 1 1985
B757-200 Northwest Airlines 1 1986
MD-11F Federal Express 1 1993
- -----------------------------------------------------------------
(a) Includes aircraft in which PCI has a greater than 10%
ownership interest. Not included in PCI's balance sheet at
December 31, 1994 are two DC-10-30 aircraft on operating
lease to PCI.
(b) PCI owns a partial interest in certain of these aircraft.
(c) Aircraft returned in January 1995.
The aircraft leasing business is highly competitive in all
of its phases, including the re-leasing and disposition of
aircraft. The performance of PCI's aircraft leasing business is
dependent upon aircraft market conditions including, among other
things, the terms upon which aircraft can be sold or leased, the
value of the equipment in the leasing portfolio and the
creditworthiness of the lessees of PCI's aircraft which include
both domestic and foreign commercial airlines, charter, air cargo
23
and express delivery operators. As discussed above, rental
income from the lease of aircraft equipment on short-term or
usage-based leases, as well as the market value of such aircraft
equipment, has been affected adversely by the lengthy adverse
economic cycle and market conditions in the airline industry.
There can be no assurance regarding the timing and degree of
recovery from these conditions and, therefore, no assurance that
PCI will be able to obtain new leases, sell, or otherwise dispose
of aircraft on satisfactory terms, following scheduled or
unscheduled lease terminations.
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 $111.3 million in 1994 compared with
$114.2 million and $122.1 million in 1993 and 1992, respectively.
The decrease in 1994 income from leasing activities as compared
with 1993 was primarily due to 1993 sales of aircraft that
resulted in pre-tax gains of $7.3 million.
PCI's marketable securities portfolio contributed pre-tax
income of $35.1 million in 1994 compared with $38.4 million and
$37.1 million in 1993 and 1992, respectively, which results
included net realized gains of $.8 million in 1994 compared with
$7 million and $7.5 million in 1993 and 1992, respectively.
Income from other activities increased during 1994 over 1993
primarily because 1993 income was reduced by a $13.5 million pre-
tax writedown related to the termination of obligations with
respect to a real estate limited partnership interest.
Expenses, before income taxes, which include interest,
depreciation and operating and administrative and general
expenses totaled $150.6 million, $159.3 million and $130.5
million for the years ended December 31, 1994, 1993 and 1992,
respectively. Of these expenses, interest was the largest single
component, amounting to $84.8 million, $77.9 million and $86.2
million in 1994, 1993 and 1992, respectively. Depreciation and
operating expenses were $55.6 million in 1994 as compared to
$66.8 million in 1993 and $34.6 million in 1992. The decrease in
1994 as compared to 1993 is primarily the result of costs related
to the 1993 aircraft partnership transaction. The decrease in
depreciation and operating expense was partially offset by
increased operating expenses incurred for aircraft not under
lease or under usage based leases.
PCI had an income tax credit in 1994 of $22.7 million,
compared to $45.1 million in 1993 and an expense of $2.5 million
in 1992. The decrease in the income tax credit from 1993 to 1994
is primarily the result of the 1993 aircraft partnership
transaction referred to above.
24
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
Investments in leased equipment of $72.1 million in 1994 included
$60 million for a one-third undivided interest in a recently-
constructed 650 megawatt (gross) baseload, coal and gas fired
power plant located in the Netherlands which was purchased and
leased back under a long term leveraged lease to a Dutch electric
utility. The remaining investment was for aircraft engine
purchases and the refurbishment and modification of existing
aircraft. Investments 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 and the refurbishment and
modification of existing aircraft. At the end of 1994, PCI had
no commitments for the purchase of additional aircraft or other
equipment leasing assets.
PCI's outstanding short-term debt totaled $48.4 million at
December 31, 1994, a decrease of $77.8 million from the $126.2
million outstanding at December 31, 1993. During 1994, PCI
issued $286.7 million in long-term debt, including non-recourse
debt, and debt repayments totaled $173.9 million. At December
31, 1994, PCI had $128.3 million available under its Medium-Term
Note Program and $320 million of unused short-term bank credit
lines.
PCI paid PEPCO a $15 million dividend in January 1994 and,
in January 1995, declared a $9 million dividend payable to PEPCO
at the end of January, resulting in cumulative dividends of $100
million paid since PCI's inception. PCI remains adequately
capitalized to support future business plans, which are designed
to supplement utility earnings and build long-term shareholder
value.
25
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, 1994 and 1993, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1994, 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 revenue in 1992.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Washington, D.C.
January 26, 1995
26
<TABLE>
Consolidated Statements of Earnings
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- --------------------------------------------------------------------------------------------------
For the year ended December 31,
1994 1993 1992
- --------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Revenue (Note 2)
Operating revenue $1,790,600 $1,702,442 $1,562,167
Interchange deliveries 32,474 22,763 39,391
---------- ---------- ----------
Total Revenue 1,823,074 1,725,205 1,601,558
---------- ---------- ----------
Operating Expenses
Fuel 392,730 354,282 345,549
Purchased energy 173,384 173,456 166,601
---------- ---------- ----------
Fuel and purchased energy 566,114 527,738 512,150
Capacity purchase payments (Note 13) 127,822 96,288 95,481
Other operation 206,106 207,814 204,481
Maintenance 92,614 93,668 90,756
Depreciation and amortization 179,986 163,607 149,785
Income taxes (Note 4) 119,859 110,176 75,272
Other taxes (Note 5) 206,080 201,252 194,180
---------- ---------- ----------
Total Operating Expenses 1,498,581 1,400,543 1,322,105
---------- ---------- ----------
Operating Income 324,493 324,662 279,453
---------- ---------- ----------
Other Income
Nonutility subsidiary (Note 15)
Income 147,006 139,341 161,154
Expenses, including interest and income taxes (127,918) (114,240) (132,993)
---------- ---------- ----------
Net earnings from nonutility subsidiary 19,088 25,101 28,161
Allowance for other funds used during construction 9,123 13,242 16,089
Other, net 4,046 10,221 1,506
---------- ---------- ----------
Total Other Income 32,257 48,564 45,756
---------- ---------- ----------
Income Before Utility Interest Charges 356,750 373,226 325,209
---------- ---------- ----------
Utility Interest Charges
Interest on debt 139,210 141,393 138,097
Allowance for borrowed funds used during construction (9,622) (9,746) (13,648)
---------- ---------- ----------
Net Utility Interest Charges 129,588 131,647 124,449
---------- ---------- ----------
Income Before Cumulative Effect of Accounting Change 227,162 241,579 200,760
Cumulative Effect of Accounting Change for Unbilled
Revenue (Net of Income Taxes of $9,458) (Note 1) - - 16,022
---------- ---------- ----------
Net Income 227,162 241,579 216,782
Dividends on Preferred Stock 16,437 16,255 14,392
---------- ---------- ----------
Earnings for Common Stock $ 210,725 $ 225,324 $ 202,390
========== ========== ==========
Average Common Shares Outstanding (000s) 118,006 115,640 112,390
Earnings Per Common Share <F1>
Before cumulative effect of accounting change $1.79 $1.95 $1.66
Cumulative effect of accounting change for unbilled
revenue - - .14
----- ----- -----
Total $1.79 $1.95 $1.80
===== ===== =====
Cash Dividends Per Common Share $1.66 $1.64 $1.60
<FN>
<F1> No material dilution would occur if all of the convertible preferred stock
and debentures were converted into common stock.
</FN>
27
</TABLE>
<TABLE>
Consolidated Balance Sheets
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- ---------------------------------------------------------------------------------------------
December 31,
Assets 1994 1993
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Property and Plant - at original cost (Notes 6 and 10)
Electric plant in service $ 5,765,210 $ 5,252,736
Construction work in progress 147,224 373,665
Electric plant held for future use 18,041 33,644
Nonoperating property 7,556 5,096
----------- -----------
5,938,031 5,665,141
Accumulated depreciation (1,639,771) (1,533,999)
----------- -----------
Net Property and Plant 4,298,260 4,131,142
----------- -----------
Current Assets
Cash and cash equivalents 7,198 7,439
Customer accounts receivable, less allowance for uncollectible
accounts of $2,432 and $2,748 107,351 100,973
Other accounts receivable, less allowance for uncollectible
accounts of $300 57,128 53,454
Accrued unbilled revenue (Note 1) 67,543 71,497
Prepaid taxes 34,352 30,531
Other prepaid expenses 10,391 6,053
Material and supplies - at average cost
Fuel 73,671 61,973
Construction and maintenance 72,447 70,262
----------- -----------
Total Current Assets 430,081 402,182
----------- -----------
Deferred Charges
Income taxes recoverable through future rates, net (Note 1) 251,357 233,431
Conservation costs, net 161,204 87,328
Unamortized debt reacquisition costs 56,725 53,868
Other 93,840 92,377
----------- -----------
Total Deferred Charges 563,126 467,004
----------- -----------
Nonutility Subsidiary Assets
Cash and cash equivalents - 2,625
Marketable securities (Notes 11 and 15) 473,608 466,153
Investment in finance leases (Note 15) 410,327 358,524
Operating lease equipment, net of accumulated depreciation
of $116,832 and $85,302 (Note 15) 544,064 565,443
Receivables, less allowance for uncollectible
accounts of $5,000 in 1994 76,426 84,726
Other investments 147,313 163,911
Other assets 22,551 23,750
----------- -----------
Total Nonutility Subsidiary Assets 1,674,289 1,665,132
----------- -----------
Total Assets $ 6,965,756 $ 6,665,460
=========== ===========
28
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
December 31,
Capitalization and Liabilities 1994 1993
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Capitalization
Common equity (Note 7)
Common stock, $1 par value - authorized 200,000,000 shares,
issued 118,248,103 and 117,797,652 shares $ 118,248 $ 117,798
Premium on stock and other capital contributions 1,020,689 1,011,778
Capital stock expense (14,163) (13,800)
Retained income 830,524 839,433
----------- -----------
Total Common Equity 1,955,298 1,955,209
Preference stock, cumulative, $25 par value -
authorized 8,800,000 shares, no shares issued or outstanding - -
Serial preferred stock (Notes 8 and 11) 125,409 125,442
Redeemable serial preferred stock (Notes 9 and 11) 143,563 147,000
Long-term debt (Notes 10 and 11) 1,723,399 1,589,621
----------- -----------
Total Capitalization 3,947,669 3,817,272
----------- -----------
Other Non-Current Liabilities
Capital lease obligation (Note 13) 136,723 -
----------- -----------
Total Other Non-Current Liabilities 136,723 -
----------- -----------
Current Liabilities
Long-term debt and preferred stock redemption
due within one year 45,445 17,977
Short-term debt (Note 12) 189,600 294,615
Accounts payable and accrued payroll 117,909 116,526
Capital lease obligation due within one year 15,233 -
Taxes accrued 20,509 25,840
Interest accrued 36,840 32,476
Customer deposits 22,563 22,296
Other 84,842 81,337
----------- -----------
Total Current Liabilities 532,941 591,067
----------- -----------
Deferred Credits
Income taxes (Notes 1 and 4) 848,456 780,723
Investment tax credits (Note 4) 68,256 71,906
Other 31,766 28,916
----------- -----------
Total Deferred Credits 948,478 881,545
----------- -----------
Nonutility Subsidiary Liabilities
Long-term debt (Notes 10 and 11) 1,140,505 1,027,705
Short-term notes payable (Note 12) 48,400 126,250
Deferred taxes and other (Note 4) 211,040 221,621
----------- -----------
Total Nonutility Subsidiary Liabilities 1,399,945 1,375,576
----------- -----------
Commitments and Contingencies (Note 13)
Total Capitalization and Liabilities $ 6,965,756 $ 6,665,460
=========== ===========
29
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
Potomac Electric Power Company and Subsidiaries
<CAPTION>
- -----------------------------------------------------------------------------------------------------
For the year ended December 31,
1994 1993 1992
- -----------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Activities
Income from utility operations $ 208,074 $ 216,478 $ 188,621
Adjustments to reconcile income to net cash
from operating activities:
Depreciation and amortization 179,986 163,607 149,785
Deferred income taxes and investment tax credits 44,641 27,711 43,414
Allowance for funds used during construction (18,745) (22,988) (29,737)
Changes in materials and supplies (13,883) 44,509 (11,144)
Changes in accounts receivable and accrued unbilled revenue (6,098) (35,399) (46,483)
Changes in accounts payable 8,257 (441) (5,716)
Changes in other current assets and liabilities (11,703) 4,317 6,325
Changes in deferred conservation costs (92,504) (59,639) (26,627)
Net other operating activities 5,303 (37,121) 8,078
Nonutility subsidiary:
Net earnings 19,088 25,101 28,161
Deferred income taxes 6,386 (32,814) 1,055
Changes in other assets and net other operating activities 47,648 56,897 7,037
--------- --------- ---------
Net Cash From Operating Activities 376,450 350,218 312,769
--------- --------- ---------
Investing Activities
Total investment in property and plant (316,890) (322,951) (357,732)
Allowance for funds used during construction 18,745 22,988 29,737
--------- --------- ---------
Net investment in property and plant (298,145) (299,963) (327,995)
Nonutility subsidiary:
Purchase of marketable securities (127,335) (254,213) (266,696)
Proceeds from sale or redemption of marketable securities 82,444 194,295 195,752
Investment in leased equipment (72,134) (32,360) (30,811)
Proceeds from sale or disposition of leased equipment 1,150 120,529 48,968
Purchase of other investments (7,191) (44,628) (7,143)
Proceeds from sale or distribution of other investments 18,429 - 42,513
Investment in promissory notes (542) (1,628) -
Proceeds from promissory notes 4,902 3,013 27,411
--------- --------- ---------
Net Cash Used by Investing Activities (398,422) (314,955) (318,001)
--------- --------- ---------
Financing Activities
Dividends on common stock (195,755) (189,837) (179,823)
Dividends on preferred stock (16,437) (16,255) (14,392)
Issuance of common stock 9,285 96,001 80,396
Issuance of preferred stock - - 50,000
Redemption of preferred stock (4,047) (1,500) (890)
Issuance of long-term debt 302,999 521,264 277,463
Reacquisition and retirement of long-term debt (144,422) (628,448) (137,387)
Proceeds from sale and leaseback of control center system 152,000 - -
Short-term debt, net (105,015) 233,015 (25,200)
Other financing activities (14,452) (26,199) (5,946)
Nonutility subsidiary:
Issuance of long-term debt 286,750 363,653 242,637
Repayment of long-term debt (173,950) (247,077) (274,991)
Short-term debt, net (77,850) (137,265) (7,390)
--------- --------- ---------
Net Cash From (Used by) Financing Activities 19,106 (32,648) 4,477
--------- --------- ---------
Net (Decrease) Increase In Cash and Cash Equivalents (2,866) 2,615 (755)
Cash and Cash Equivalents at Beginning of Year 10,064 7,449 8,204
--------- --------- ---------
Cash and Cash Equivalents at End of Year (Note 14) $ 7,198 $ 10,064 $ 7,449
========= ========= =========
30
</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.
Certain prior year amounts have been reclassified to conform
to the current year presentation.
A description of significant accounting policies follows.
Principles of Consolidation
- ---------------------------
The consolidated financial statements combine the financial
results of the Company and 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
- -------------
The Company changed its method of revenue recognition effective
January 1, 1992, to provide for the accrual of revenue for
service rendered but unbilled as of the end of each month. Prior
to 1992, revenue was recognized using the meters read method of
accounting whereby annual revenue reflected 12 monthly meter
readings for each customer. The new method was adopted to
provide a better matching of revenue 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. 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 revenue in the second quarter and
decreasing revenue in the fourth quarter.
31
The Company includes in revenue the amounts received for sales
to other utilities related to pooling and interconnection
agreements. Amounts received for such interchange deliveries are
a component of the Company's fuel rates.
In each jurisdiction, the Company's rate schedules include
fuel rates. The fuel rate provisions are designed to provide for
separately stated fuel billings which cover applicable net fuel
and interchange costs, purchased capacity in the District of
Columbia, and emission allowance costs in the Company's retail
jurisdictions, or changes in the applicable costs from levels
incorporated in base rates. Differences between applicable net
costs incurred and fuel rate revenue billed in any given period
are accounted for as other current assets or other current
liabilities in those cases where specific provision has been made
by the appropriate regulatory commission for the resolution of
such differences within one year. Where no such provision has
been made, the differences are accounted for as other deferred
charges or other deferred credits pending regulatory
determination.
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.
32
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 1994 and 1993 and 3%
for 1992.
Conservation
- ------------
In general, the Company accounts for conservation expenditures in
connection with its demand side management (DSM) program 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 through a surcharge
included in base rates which reflects current year expenditures
and lost revenue.
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 7.6% in 1994, 8.7% in 1993 and 9.1% in 1992,
compounded semiannually.
Nonutility Subsidiary Receivables
- ---------------------------------
PCI, the Company's nonutility subsidiary, continuously monitors
its receivables and establishes an allowance for doubtful
accounts against its notes receivable, when deemed appropriate,
on a specific identification basis. The direct write off method
is used when trade receivables are deemed uncollectible.
33
Income Taxes
- ------------
Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 109 entitled
"Accounting for Income Taxes" which requires the use of an asset
and liability approach for financial reporting and accounting for
deferred income taxes. Deferred taxes are recorded for all
temporary differences based upon currently enacted tax rates.
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. No valuation allowance for deferred tax assets was
required or recorded at December 31, 1994 and 1993.
34
(2) Total Revenue
-------------
The Company's retail service area includes all of the District of
Columbia and major portions of Montgomery and Prince George's
counties in suburban Maryland. The Company supplies electricity,
at wholesale, under a contract with Southern Maryland Electric
Cooperative, Inc. (SMECO), and also delivers economy energy to
the Pennsylvania-New Jersey-Maryland Interconnection Association
(PJM) of which the Company is a member. PJM is composed of
eleven electric utilities which operate on a fully integrated
basis.
Total revenue for each year was comprised as shown below.
- -----------------------------------------------------------------
1994 1993 1992
-------------------------------------------------
Amount % Amount % Amount %
- -----------------------------------------------------------------
(Thousands of Dollars)
Residential $ 524,737 29.4 $ 505,173 29.8 $ 432,797 27.8
Commercial 834,323 46.8 791,357 46.6 748,550 48.1
U.S. Government 254,030 14.2 238,192 14.0 229,586 14.8
D.C. Government 56,655 3.2 53,551 3.2 49,815 3.2
Wholesale 113,319 6.4 108,162 6.4 95,350 6.1
---------- ----- --------- ----- ---------- -----
Sales of
electricity 1,783,064 100.0 1,696,435 100.0 1,556,098 100.0
===== ===== =====
Other electric
revenue 7,536 6,007 6,069
---------- ---------- ----------
Operating
revenue 1,790,600 1,702,442 1,562,167
Interchange
deliveries 32,474 22,763 39,391
---------- ---------- ----------
Total Revenue $1,823,074 $1,725,205 $1,601,558
========== ========== ==========
- -----------------------------------------------------------------
Sales of electricity include base rate revenue and fuel rate
revenue. Fuel rate revenue was $557.4 million in 1994, $487.9
million in 1993 and $456.4 million in 1992.
35
The Company's Maryland fuel rate is based on historical net
fuel, interchange and emission allowance costs. The zero-based
rate may not be changed without prior approval of the Maryland
Public Service Commission. Application to the Commission for an
increase in the rate may only be made when the currently
calculated fuel rate, based on the most recent actual net fuel,
interchange and emission allowance costs, exceeds the currently
effective fuel rate by more than 5%. If the currently calculated
fuel rate is more than 5% below the currently effective fuel
rate, the Company must apply to the Commission for a fuel rate
reduction.
In September 1994, the Company filed for a 5.3% increase in
the Maryland fuel rate which became effective, subject to refund,
on November 1, 1994. The initial filing also included an
adjustment for a deferred fuel amortization charge to recover
over a twelve month period approximately $28.5 million of
previously unrecovered fuel costs incurred through July 31, 1994.
During the case, which is still pending, the Company updated the
proposed deferred fuel amortization, pursuant to a recommendation
of the Staff of the Maryland Public Service Commission, to
reflect a reduction in the unrecovered amount at October 31, 1994
to $21.1 million. A final order is expected during the first
quarter of 1995. Based on results for the period ended November
30, 1994, the Company filed for a fuel rate reduction in Maryland
of 5.3%.
The District of Columbia fuel rate is based upon an average
of historical and projected net fuel, interchange and emission
allowance costs and purchased capacity, and is adjusted monthly
to reflect changes in such costs.
Rates for service, at wholesale, to SMECO include a fuel
adjustment charge based upon estimated applicable fuel and
interchange costs for each billing month. The difference between
the estimated costs and the actual applicable fuel and
interchange costs incurred each month is reflected as an
adjustment to the fuel rate in the succeeding month.
Amounts received for interchange deliveries are a component
of the Company's fuel rates.
36
(3) Pensions and Other Postretirement and Postemployment
Benefits
----------------------------------------------------
The Company's General Retirement Program (Program), a
noncontributory defined benefit program, covers substantially all
full-time employees of the Company and its subsidiaries. The
Program provides for benefits to be paid to eligible employees at
retirement based primarily upon years of service with the Company
and their compensation rates for the three years preceding
retirement. Annual provisions for accrued pension cost are based
upon independent actuarial valuations. The Company's policy is
to fund accrued pension costs.
Pension expense included in net income was $14.3 million in
1994, $13.7 million in 1993 and $10.5 million in 1992. The net
periodic pension cost was computed as follows.
- -----------------------------------------------------------------
1994 1993 1992
- -----------------------------------------------------------------
(Thousands of Dollars)
Service cost-benefits earned $10,800 $10,300 $ 9,100
Interest cost on projected
benefit obligation 26,800 25,100 23,500
Actual return on Program assets (4,600) (24,300) (13,400)
Differences between actual
and expected return on
Program assets and net
amortization (18,700) 2,600 (8,700)
------- ------- -------
Pension cost $14,300 $13,700 $10,500
======= ======= =======
- -----------------------------------------------------------------
37
Program assets are stated at fair value and were comprised
of approximately 70% and 68% of cash equivalents and fixed income
investments and the balance in equity investments at December 31,
1994 and 1993, respectively. The following table sets forth the
Program's funded status and amounts recognized on the
Consolidated Balance Sheets.
- -----------------------------------------------------------------
1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Program benefits:
Vested benefits $(252,300) $(249,600)
Nonvested benefits (30,000) (35,300)
--------- ---------
Accumulated benefit obligation $(282,300) $(284,900)
========= =========
Actuarial present value of projected
benefit obligation $(338,600) $(358,600)
Program assets at fair value 289,100 282,600
--------- ---------
Projected benefit obligation in excess of
Program assets (49,500) (76,000)
Unrecognized actuarial loss 35,600 58,500
Unrecognized prior service cost 17,600 12,900
Unrecognized net obligation at
January 1, 1987, being recognized
over 18 years 400 400
--------- ---------
Prepaid pension expense/accrued
pension (liability) $ 4,100 $ (4,200)
========= =========
- -----------------------------------------------------------------
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 8.5% and 4.5% in 1994 and 7.75% and 5% in 1993,
respectively. The assumed long-term rate of return on Program
assets was 9% in 1994 and 1993.
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
38
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.
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
$8.7 million and $9.3 million in 1994 and 1993, respectively.
The cost of such benefits, recognized as an operating expense
when paid, was $5 million in 1992. The following table sets
forth the components of the postretirement expense.
- -----------------------------------------------------------------
1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Service cost-benefits attributable
to service during the year $ 2,600 $ 2,500
Interest cost on accumulated
postretirement benefit obligation 4,200 4,400
Actual loss (return) on Plan assets 200 (400)
Amortization of transition
obligation 2,500 2,800
Difference between actual and
expected return on Plan assets
and net amortization (800) -
------- -------
Net postretirement benefit cost $ 8,700 $ 9,300
======= =======
- -----------------------------------------------------------------
39
The following table sets forth the accumulated
postretirement benefit obligation reconciled to the amounts
recognized on the Consolidated Balance Sheets.
- -----------------------------------------------------------------
1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation to
Retirees and dependents $(34,600) $(29,700)
Active employees fully eligible (10,600) (10,300)
Active employees not fully
eligible (14,800) (14,800)
-------- --------
Total accumulated postretirement
benefit obligation (60,000) (54,800)
Plan assets at fair value 4,500 4,300
-------- --------
Accumulated postretirement benefit
obligation in excess of Plan assets (55,500) (50,500)
Unrecognized transition obligation 45,200 47,700
Unrecognized actuarial loss 11,100 2,800
-------- --------
Prepaid/(accrued) postretirement
benefit cost $ 800 $ -
======== ========
- -----------------------------------------------------------------
The Company's SFAS No. 106 obligation at December 31, 1994
and 1993 was based on discount rates of 8.5% and 7.75%,
respectively, and weighted average rates of increase in future
compensation levels of 4.5% and 5%, respectively. The current
health-care cost trend rate is 8% which declines to 5.5% after a
five year period. A one percentage point increase in the health-
care cost trend rate would increase the Accumulated
Postretirement Benefit Obligation by $3.7 million to
approximately $63.7 million and the sum of the service cost and
interest cost for 1994 by approximately $.5 million.
In January 1994 and 1993, the Company funded the 1994 and
1993 portions of its estimated liability for postretirement
medical and life insurance costs through the use of an Internal
Revenue Code (IRC) 401 (h) account, within the Company's pension
plan, and an IRC 501 (c)(9) Voluntary Employee Beneficiary
Association (VEBA). The Company plans to fund the 401(h) account
and the VEBA annually. Assets were comprised of cash
equivalents, fixed income investments and equity investments and
the assumed return on plan assets was 9% in 1994 and 1993.
40
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 reduced the costs of its postretirement
benefits by requiring all eligible employees who retired on or
after January 1, 1994, to share in the cost of these benefits.
These amendments were reflected in 1993.
The Company treats postretirement benefit costs as an
operating expense. The Company's Maryland tariff includes the
cost of postretirement benefits. In May 1994, the District of
Columbia Public Service Commission authorized an accounting
change for postretirement benefit costs consistent with SFAS No.
106 and adopted a three-year phase-in approach for inclusion of
these increased costs in the Company's rates.
Effective January 1, 1994, the Company adopted SFAS No. 112
entitled "Employers' Accounting for Postemployment Benefits"
which requires the accrual of the expected cost of providing
benefits to former or inactive employees after employment but
before retirement. The adoption of this pronouncement did not
have a material effect on the Company's consolidated financial
statements.
41
<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.
<CAPTION>
Provisions for Income Taxes Charged to Continuing Operations
- ------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
1994 1993 1992
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility current tax expense
Federal $ 63,395 $ 69,007 $ 50,900
State and local 8,612 9,801 7,571
--------- --------- ---------
Total utility current tax expense 72,007 78,808 58,471
--------- --------- ---------
Utility deferred tax expense
Federal 42,070 26,784 26,584
State and local 6,221 5,100 4,682
Investment tax credits (3,650) (3,469) (3,314)
--------- --------- ---------
Total utility deferred tax expense 44,641 28,415 27,952
--------- --------- ---------
Total utility income tax expense 116,648 107,223 86,423
--------- --------- ---------
Nonutility subsidiary current tax expense
Federal (29,315) (13,022) 1,461
--------- --------- ---------
Nonutility subsidiary deferred tax expense
Federal 6,758 (31,360) 1,055
State and local (138) (696) -
--------- --------- ---------
Total nonutility subsidiary deferred tax expense 6,620 (32,056) 1,055
--------- --------- ---------
Total nonutility subsidiary income tax expense (22,695) (45,078) 2,516
--------- --------- ---------
Total consolidated income tax expense 93,953 62,145 88,939
Income taxes included in other income (25,906) (48,031) 4,209
Income taxes included in cumulative effect of accounting change - - 9,458
--------- --------- ---------
Income taxes included in utility operating expenses $ 119,859 $ 110,176 $ 75,272
========= ========= =========
42
</TABLE>
<TABLE>
<CAPTION>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
- ---------------------------------------------------------------------------------------------------
1994 1993 1992
- ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Income before income taxes (including cumulative effect
of accounting change) $ 321,115 $ 303,724 $ 305,721
========= ========= =========
Utility income tax at federal statutory rate $ 113,653 $ 113,295 $ 93,515
Increases (decreases) resulting from
Depreciation 8,022 5,096 4,204
Removal costs (4,086) (4,385) (5,109)
Allowance for funds used during construction (2,411) (3,852) (4,854)
Other (4,175) (6,477) (5,888)
State income taxes, net of federal effect 9,683 9,686 8,213
Tax credits (4,038) (3,873) (3,658)
Cumulative effect of tax rate change - (2,267) -
--------- --------- ---------
Total utility income tax expense 116,648 107,223 86,423
--------- --------- ---------
Nonutility subsidiary income tax at federal statutory rate (1,262) (6,992) 10,430
Increases (decreases) resulting from
Dividends received deduction (8,487) (7,672) (6,750)
Reversal of previously accrued deferred taxes (8,206) (35,904) -
Other (4,602) (408) (1,164)
State income taxes, net of federal effect (138) (696) -
Cumulative effect of tax rate change - 6,594 -
--------- --------- ---------
Total nonutility subsidiary income tax expense (22,695) (45,078) 2,516
--------- --------- ---------
Total consolidated income tax expense 93,953 62,145 88,939
Income taxes included in other income (25,906) (48,031) 4,209
Income taxes included in cumulative effect of accounting change - - 9,458
--------- --------- ---------
Income taxes included in utility operating expenses $ 119,859 $ 110,176 $ 75,272
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
At December 31,
----------------------
1994 1993
----------------------
(Thousands of Dollars)
<S> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax basis differences $ 723,248 $ 672,625
Rapid amortization of certified pollution control
facilities 29,018 31,090
Deferred taxes on amounts to be collected through
future rates 95,465 88,787
Property taxes 11,212 10,218
Deferred fuel 177 4,644
Prepayment premium on debt retirement 21,537 11,215
Deferred investment tax credit (25,922) (27,435)
Contributions in aid of construction (24,954) (23,951)
Other 25,454 21,825
--------- ---------
Total utility deferred tax liabilities (net) 855,235 789,018
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 6,779 8,295
--------- ---------
Total utility deferred tax liabilities (net) - non current $ 848,456 $ 780,723
========= =========
Nonutility subsidiary deferred tax liabilities (assets)
Finance leases $ 134,925 130,833
Operating leases 117,782 114,134
Reversal of previously accrued taxes related
to partnerships (16,385) (16,969)
Alternative minimum tax (77,167) (75,610)
Other (24,477) (9,789)
--------- ---------
Total nonutility subsidiary deferred tax liabilities (net),
(included in Deferred taxes and other) $ 134,678 $ 142,599
========= =========
43
</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.
44
(5) Other Taxes
-----------
Taxes, other than income taxes, charged to utility operating
expenses for each period are shown below.
- ----------------------------------------------------------------
1994 1993 1992
- ----------------------------------------------------------------
(Thousands of Dollars)
Gross receipts $ 93,549 $ 88,044 $ 81,266
Property 60,443 58,193 55,965
Payroll 11,063 10,534 10,582
County fuel-energy 30,842 34,614 37,283
Environmental, use and
other 10,183 9,867 9,084
-------- -------- --------
$206,080 $201,252 $194,180
======== ======== ========
- -----------------------------------------------------------------
45
(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 $81.1 million at December 31, 1994 and
$67.1 million at December 31, 1993, includes $9.5 million and
$23.4 million of Construction Work in Progress, respectively.
The Conemaugh Generating Station is required to comply with
certain provisions of the Clean Air Act Amendments of 1990. As
of December 31, 1994 nitrogen oxide reduction equipment has been
installed on both generating units and flue gas desulfurization
equipment has been installed on Unit 1. The Unit 2 flue gas
desulfurization equipment is scheduled for completion by December
31, 1995. The Company's share of the construction costs is
approximately $38 million. The project, at December 31, 1994,
was approximately 85% complete.
46
<TABLE>
(7) Common Equity
Changes in common stock, premium on stock and retained income are summarized
below.
<CAPTION>
- ---------------------------------------------------------------------------------------
Common Stock Premium Retained
Shares Par Value on Stock Income
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance, December 31, 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
Net income before net earnings
from nonutility subsidiary - - - 208,074
Nonutility subsidiary:
Net earnings - - - 19,088
Marketable securities net
unrealized loss, net of tax - - - (23,879)
Dividends:
Preferred stock - - - (16,437)
Common stock - - - (195,755)
Conversion of preferred stock 3,845 4 29 -
Gain on acquisition of preferred
stock - - 109 -
Other capital reductions - - (66) -
Sale of common stock through
Shareholder Dividend
Reinvestment Plan 355,198 355 6,603 -
Issuance of common stock to
Employee Savings Plans 91,408 91 2,236 -
----------- ---------- ---------- ----------
Balance, December 31, 1994 118,248,103 $ 118,248 $1,020,689 $ 830,524
=========== ========== ========== ==========
47
</TABLE>
The Company's Shareholder Dividend Reinvestment Plan (DRP)
provides that shares of common stock purchased through the plan
may be original issue shares or, at the option of the Company,
shares purchased in the open market. The DRP permits additional
cash investments by plan participants limited to one investment
per month of not less than $25 and not more than $5,000.
As of December 31, 1994, 48,869 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,
2,483,222 shares for issuance under the DRP and 1,299,867 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, 1994.
48
(8) Serial Preferred Stock
----------------------
The Company has authorized 11,159,434 shares of cumulative $50
par value Serial Preferred Stock. At December 31, 1994 and 1993,
there were outstanding 5,379,433 shares and 5,461,038 shares,
respectively. The various series of Serial Preferred Stock
outstanding (excluding 2,871,251 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 1994 1993
- -----------------------------------------------------------------
(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,
8,182 and 8,838 shares,
respectively $50.00 409 442
Auction Series A, 1,000,000 shares $50.00 50,000 50,000
-------- --------
$125,409 $125,442
======== ========
- -----------------------------------------------------------------
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,
1994, 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 656 shares in 1994, 948 shares in 1993 and 3,827 shares
in 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 4.833%
($2.4165) for the period December 1, 1994 through February 28,
1995. The average annual dividend rates were 3.55% ($1.775) in
1994 and 2.8% ($1.40) in 1993.
49
(9) Redeemable Serial Preferred Stock
---------------------------------
The outstanding series of $50 par value Redeemable Serial
Preferred Stock are shown below.
- -----------------------------------------------------------------
December 31,
1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
$3.37 Series of 1987, 871,251 and
952,200 shares, respectively $ 43,563 $ 47,610
$3.89 Series of 1991, 1,000,000 shares 50,000 50,000
$3.40 Series of 1992, 1,000,000 shares 50,000 50,000
-------- --------
143,563 147,610
Redemption requirement due within
one year - (610)
-------- --------
$143,563 $147,000
======== ========
- ----------------------------------------------------------------
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.
50
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 1999 with respect to
the Redeemable Serial Preferred Stock are $1.1 million in 1997
and $1.5 million annually thereafter.
51
<TABLE>
(10) Long-Term Debt
<CAPTION>
Details of long-term debt are shown below.
- ------------------------------------------------------------------------------------------------------
Interest December 31,
Rate Maturity 1994 1993
- ------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
First Mortgage Bonds
Fixed Rate Series:
5-1/4% December 1, 1994 $ - $ 15,000
5% December 15, 1995 40,000 40,000
5-5/8% December 31, 1997 16,000 18,000
4-3/8% February 15, 1998 50,000 50,000
4-1/2% May 15, 1999 45,000 45,000
9% April 15, 2000 100,000 100,000
5-1/8% April 1, 2001 15,000 15,000
5-7/8% May 1, 2002 35,000 35,000
6-5/8% February 15, 2003 40,000 40,000
5-5/8% October 15, 2003 50,000 50,000
6-1/2% July 1, 2004 - 15,000
6-1/8% July 1, 2007 - 38,300
6-1/2% July 1, 2007 - 20,000
6-1/2% March 15, 2008 78,000 78,000
5-7/8% October 15, 2008 50,000 50,000
6-5/8% January 1, 2009 - 7,500
9-3/4% May 1, 2019 - 43,000
8-5/8% August 15, 2019 59,800 63,000
9% June 1, 2021 100,000 100,000
6% September 1, 2022 30,000 30,000
6-3/8% January 15, 2023 37,000 37,000
7-1/4% July 1, 2023 100,000 100,000
6-7/8% September 1, 2023 100,000 100,000
5-3/8% February 15, 2024 42,500 -
5-3/8% February 15, 2024 38,300 -
6-7/8% October 15, 2024 75,000 75,000
8-1/2% May 15, 2027 75,000 75,000
7-1/2% March 15, 2028 40,000 40,000
Variable Rate Series:
Adjustable rate December 1, 2001 50,000 50,000
---------- ----------
Total First Mortgage Bonds 1,266,600 1,329,800
Convertible Debentures
5% September 1, 2002 115,000 115,000
7% January 15, 2018 68,412 68,834
Medium-Term Notes
6.25% May 28, 1996 25,000 -
6.66% to 6.73% May 1997 100,000 -
9.08% July and August 1997 50,000 50,000
7.46% to 7.60% January 2002 40,000 40,000
7.64% January 17, 2007 35,000 35,000
6.25% January 20, 2009 50,000 -
7% January 15, 2024 50,000 -
---------- ----------
Total Utility Long-Term Debt 1,800,012 1,638,634
Net unamortized discount (31,168) (31,646)
Current portion (45,445) (17,367)
---------- ----------
Net Utility Long-Term Debt $1,723,399 $1,589,621
========== ==========
Nonutility Subsidiary Long-term Debt
Varying rates through 2011 $1,140,505 $1,027,705
========== ==========
52
</TABLE>
Utility Long-Term Debt
- ----------------------
The outstanding First Mortgage Bonds (bonds) are secured by a
lien on substantially all of the Company's property and plant.
Additional bonds may be issued under the mortgage as amended and
supplemented in compliance with the provisions of the indenture.
During 1994, the Company issued $80.8 million of 5-3/8%
First Mortgage Bonds and $225 million of 6-1/4% to 7% Medium-Term
Notes with various maturities. A portion of the proceeds from
these financings were used to redeem $127 million of higher cost
First Mortgage Bonds and to satisfy long-term debt maturities and
sinking fund requirements totaling $17 million.
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, 1994, the applicable interest
rate is 8.68%. The applicable interest rate was 6.657% at
December 1, 1993 and 7.733% at December 1, 1992. The Bonds were
nonredeemable prior to December 1, 1994.
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, 1994 are $45.4 million in 1995, $31 million in 1996,
$156 million in 1997, $50 million in 1998 and $45 million in
1999.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at December 31, 1994 consisted of $1.1 billion
of recourse debt from institutional lenders maturing at various
dates between 1995 and 2003. The interest rates of such
borrowings ranged from 4.7% to 10.10%. The weighted average
interest rate was 7.47% at December 31, 1994, 7.45% at December
31, 1993 and 8.13% at December 31, 1992. Annual aggregate
principal repayments are $260.4 million in 1995, $188.5 million
in 1996, $135.5 million in 1997, $177.3 million in 1998, $126.5
million in 1999 and $179.5 million thereafter.
53
Long-term debt also includes $72.7 million of non-recourse
debt, $48.7 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. Non-recourse debt of $24 million is related to PCI's
majority owned real estate partnerships of which $15.5 million is
due in consecutive monthly installments with maturity on May 11,
2001, based on a 30 year amortization period at a fixed rate of
interest of 9.05%. The remaining non-recourse real estate debt
consists of $8.5 million payable in monthly installments at a
fixed rate of interest of 9.66% with final maturity on October 1,
2011.
54
<TABLE>
(11) Fair Value of Financial Instruments
- ----------------------------------------
The estimated fair values of the Company's financial instruments at
December 31, 1994 and 1993 are shown below.
<CAPTION>
- --------------------------------------------------------------------------------------------
December 31,
1994 1993
- --------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------- ----------- ----------- -----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Utility
Capitalization and Liabilities
Serial preferred stock $ 125,409 $ 102,102 $ 125,442 $ 110,919
Redeemable serial
preferred stock 143,563 134,008 147,000 164,115
Long-term debt
First Mortgage Bonds 1,208,076 1,093,208 1,297,355 1,354,887
Medium-Term Notes 347,712 324,223 124,435 138,823
Convertible Debentures 167,611 146,098 167,831 177,107
Nonutility Subsidiary
Assets
Marketable securities $ 473,608 $ 473,608 $ 466,153 $ 473,151
Notes receivable 61,278 58,616 60,688 60,300
Liabilities
Long-term debt 1,140,505 1,122,638 1,027,705 1,080,978
- --------------------------------------------------------------------------------------------
55
</TABLE>
The methods and assumptions below were used to estimate, at
December 31, 1994 and 1993, the fair value of each class of
financial instruments shown above for which it is practicable to
estimate that value.
The fair value of the Company's long-term debt, which
includes First Mortgage Bonds, Medium-Term Notes and Convertible
Debentures, excluding amounts due within one year, was based on
the current market price, or for issues with no market price
available, was based on discounted cash flows using current rates
for similar issues with similar terms and remaining maturities.
The fair value of the Company's Serial Preferred Stock,
including Redeemable Serial Preferred Stock and excluding amounts
due within one year, was based on quoted market prices or
discounted cash flows using current rates of preferred stock with
similar terms.
The fair value of PCI's Marketable Securities was based on
quoted market prices.
The fair value of PCI's Notes Receivable was based on
discounted future cash flows using current rates and similar
terms.
The fair value of PCI's long-term debt, including non-
recourse debt, was based on current rates offered to similar
companies for debt with similar remaining maturities.
(12) Short-Term Debt
---------------
The Company's short-term financing requirements have been
satisfied principally through the sale of commercial promissory
notes.
The Company maintains a minimum 100% line of credit back-up
for its outstanding commercial promissory notes, which was unused
during 1994, 1993 and 1992.
56
Nonutility Subsidiary Short-Term Notes Payable
- ----------------------------------------------
The nonutility subsidiary's short-term financing requirements
have been satisfied principally through the sale of commercial
promissory notes.
The nonutility subsidiary maintains a minimum 100% line of
credit back-up for its outstanding commercial promissory notes,
which was unused during 1994, 1993 and 1992.
(13) Commitments and Contingencies
-----------------------------
Leases
- ------
The Company leases its general office building and certain data
processing and duplicating equipment, motor vehicles,
communication system and construction equipment under long-term
lease agreements. The lease of the general office building
expires in 2002 and leases of equipment extend for periods of up
to 6 years. Charges under such leases are accounted for as
operating expenses or construction expenditures, as appropriate.
Rents, including property taxes and insurance, net of rental
income from subleases, aggregated approximately $14.9 million in
1994, $13.6 million in 1993 and $12.6 million in 1992. The
approximate annual commitments under all operating leases,
reduced by rentals to be received under subleases are $13.4
million in 1995, $12.4 million in 1996, $5.8 million in 1997,
$5.4 million in 1998, $5.2 million in 1999 and a total of $15.5
million in the years thereafter.
During December 1994, the Company entered into a sale (at
cost) and leaseback agreement for its control center system
(system). The system is an integrated energy management system
used by the Company's power dispatchers to centrally control the
operation of the Company's electric system, which consists of all
of its generating units, the transmission system and the
distribution system. The Company has accounted for the lease of
the system as a capital lease, recorded at the present value of
future lease payments which totaled $152 million at December 31,
1994. The lease requires semi-annual payments of $7.6 million
over a 25-year period and provides for transfer of ownership of
the system to the Company for $1 at the end of the lease term.
Under SFAS No. 71, the amortization of leased assets is modified
so that the total of interest on the obligation and amortization
of the leased asset is equal to the rental expense allowed for
ratemaking purposes. This lease has been treated as an operating
lease for ratemaking purposes.
57
Fuel Contracts
- --------------
The Company has numerous coal contracts with various expiration
dates through 2003 for aggregate annual deliveries of
approximately 3.5 million tons. Deliveries under these contracts
are expected to provide approximately 58% of the estimated system
coal requirements in 1995. Approximately 42% of the estimated
system coal requirements in 1995 will be purchased under shorter
term agreements and on a spot basis from a variety of suppliers.
Prices under the Company's coal contracts are generally
determined by reference to base amounts adjusted to reflect
provisions for changes in suppliers' costs, which in turn are
determined by reference to published indices and limited by
current market prices.
Capacity Purchase Agreements
- ----------------------------
The Company's long-term capacity purchase agreements with Ohio
Edison and APS commenced June 1, 1987 and are expected to
continue at the 450 megawatt level through 2005. Under the terms
of the agreement with Ohio Edison, the Company is required to
make capacity payments, subject to certain contingencies, which
include a share of Ohio Edison's fixed operating and maintenance
cost. The approximate monthly capacity commitment under this
agreement, excluding an allocation of fixed operating and
maintenance cost, was $12,380 per megawatt through 1993, $18,060
per megawatt effective 1994 through 1998 and $25,620 per megawatt
from 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 $462,000 per month.
Environmental Contingencies
- ---------------------------
During 1993, the Company was served with Amended Complaints filed
in three jurisdictions (Prince George's County, Baltimore City,
and Baltimore County), in separate ongoing, consolidated
proceedings each denominated "In re: Personal Injury Asbestos
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
58
allegedly were exposed to asbestos while working on the Company's
property. Initially, a total of approximately four hundred and
forty-eight (448) individual plaintiffs added the Company to
their Complaints. While the pleadings are not entirely clear, it
appears that each plaintiff seeks $2 million in compensatory
damages and $4 million in punitive damages from each defendant.
In a related proceeding in the Baltimore City case, the Company
was served, in September 1993, with a third party complaint by
Owens Corning Fiberglass, Inc. (Owens Corning) alleging that
Owens Corning was in the process of settling approximately 700
individual asbestos-related cases and seeking a judgment for
contribution against the Company on the same theory of alleged
negligence set forth above in the plaintiffs' case.
Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed
a third party complaint against the Company, seeking contribution
for the same plaintiffs involved in the Owens Corning third party
complaint. Since the filings, a number of the individual suits
have been disposed of without any payment by the Company. The
third party complaints involving Pittsburgh Corning and Owens
Corning were dismissed by the Baltimore City Court during 1994
without any payment by the Company. While the aggregate amount
specified in the remaining suits would exceed $1 billion, the
Company believes the amounts are greatly exaggerated as were the
claims already disposed of. The amount of total liability, if
any, and any related insurance recovery cannot be precisely
determined at this time; however, based on information and
relevant circumstances known at this time, the Company does not
believe these suits will have a material adverse effect on its
financial position. However, an unfavorable decision rendered
against the Company could have a material adverse effect on
results of operations in the fiscal year in which a decision is
rendered.
The Company is subject to contingencies associated with
environmental matters, principally related to possible
obligations to remove or mitigate the effects on the environment
of the disposal of certain substances at the sites discussed
below.
During 1993, the Company and two other potentially
responsible parties (PRPs) completed 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. The Company and two other PRPs have entered into
settlements with third parties to recover approximately $2.4
million of this cost. EPA oversight costs, which are not
expected to be material, have not yet been assessed. While
compliance with the AO has been completed, the Company cannot
determine whether it will be subject to any future liability with
respect to this site.
59
In October 1994 a Remedial Investigation/Feasibility Study
(RI/FS) report was submitted to the EPA with respect to a site in
Philadelphia, Pennsylvania. Pursuant to an agreement among the
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 $5.6 million. The Company
has paid $836,000 to date. The report includes a number of
possible remedies, the estimated costs of which range from $2
million to $90 million. While a remedy near the lower end of the
range is possible, the Company cannot predict what remedy may be
acceptable to the EPA. In addition, the Company cannot estimate
the total extent of the EPA's administrative and oversight costs.
To date, the Company has accrued approximately $1.7 million for
its share of this contingency.
Litigation
- ----------
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.
Other
- -----
In September 1994, to further reduce future costs and staffing
levels, the Company announced a Voluntary Severance Program
(VSP). As an incentive to voluntarily sever employment no later
than the first quarter of 1995, the VSP offered a severance
payment to any full-time employee with five or more years of
service with the Company, based on two weeks of pay for each year
of service, not to exceed 52 weeks of pay. Approximately 340 of
the Company's employees will participate in the VSP. During
January 1995, approximately $7.4 million in severance costs was
expensed.
Subsidiaries of the Company and the Columbia Gas System,
Inc. have formed a joint venture partnership (the Partnership) to
own and operate natural gas and storage terminaling facilities at
Cove Point, Maryland, and an 87-mile natural gas pipeline that
extends from Cove Point to Loudoun County, Virginia. A Company
subsidiary has committed to loan the Partnership $15 million to
recommission certain existing facilities and for new
construction. As of December 31, 1994, the remaining $14.9
million of the loan commitment is yet to be drawn upon by the
Partnership.
60
Nonutility Subsidiary
- ---------------------
At December 31, 1994 a portion ($263 million carrying value) of
PCI's aircraft leasing portfolio consisted of equipment not on
lease (four L-1011 aircraft returned by TWA when leases expired
in November 1994) and equipment on short-term, and in some cases,
usage-based operating leases with monthly rentals and maintenance
payments dependent upon hours used. Under these leases, PCI is
responsible for future operating and maintenance expenses
exceeding amounts provided therefor by lessees and, during 1994,
PCI provided net charges of $8.3 million (before tax) against
earnings to establish reserves against such future estimated
expenses. Most of the usage-based and short-term leases include
provisions for early termination by PCI if more favorable
transactions become available. In January 1995, because of the
lessee's inability to make timely rental payments and to satisfy
other lease obligations, Fortunair Canada returned one B747
aircraft previously under short-term lease. PCI is continuing to
seek new leases with more favorable terms or to sell the
equipment on satisfactory terms.
All rental payments due under equipment leases are current.
Continental Airlines (Continental) has announced that it intends
to seek the termination of certain A-300 aircraft leases and,
effective February 1, 1995, the reduction of rental payments due
under certain leases of other widebody aircraft. Pending
discussions with lessors, Continental has indicated that it will
not be making payments to such lessors as required by the terms
of its contracts. Continental has approached PCI to request
discussions regarding the return of one A-300 aircraft and the
renegotiation of certain other leases of widebody aircraft.
Continental has indicated that payments under these leases could
include debt securities convertible into equity in lieu of full
cash payments. PCI has informed Continental that it expects all
lease obligations to be satisfied in full.
There can be no assurance that PCI will be able to obtain
new leases, sell or otherwise dispose of aircraft on satisfactory
terms, following scheduled or unscheduled lease terminations.
61
(14) Supplemental Cash Flow Information
----------------------------------
Listed below is supplemental disclosure of cash flow information.
- -----------------------------------------------------------------
1994 1993 1992
- -----------------------------------------------------------------
(Thousands of Dollars)
Cash paid for:
Interest, net of capitalized
interest (including nonutility
subsidiary interest of $83,724,
$76,556 and $86,917) $203,013 206,955 204,657
Income taxes $ 51,368 67,741 52,764
Nonutility subsidiary noncash
transactions:
Promissory note received in
exchange for equipment $ - - 10,000
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.
62
(15) Selected Nonutility Subsidiary Financial Information
----------------------------------------------------
Selected financial information of the Company's principal
consolidated nonutility investment subsidiary, Potomac Capital
Investment Corporation (PCI) and its subsidiaries, is presented
below. The Company's equity investment in PCI was reduced from
$295 million to $271.1 million at December 31, 1994, by a $23.9
million allowance against retained income to recognize year-end
unrealized depreciation of marketable securities on an after-tax
basis. Subsidiary equity at December 31, 1993 was $290.9
million. Dividends to the parent company were $15 million in
1994 and $14 million in 1993.
- -----------------------------------------------------------------
For the year ended
December 31,
1994 1993 1992
- -----------------------------------------------------------------
(Thousands of Dollars)
Income
Leasing activities $111,262 $114,226 $122,087
Marketable securities 35,148 38,417 37,062
Other 596 (13,302) 2,005
-------- -------- --------
147,006 139,341 161,154
-------- -------- --------
Expenses
Interest 84,783 77,861 86,156
Administrative and general 10,259 14,640 9,762
Depreciation and operating 55,571 66,817 34,559
Income tax (credit) expense (22,695) (45,078) 2,516
-------- -------- --------
127,918 114,240 132,993
-------- -------- --------
Net earnings from nonutility
subsidiary $ 19,088 $ 25,101 $ 28,161
======== ======== ========
63
Marketable Securities
- ---------------------
In January 1994, PCI adopted SFAS No. 115 entitled "Accounting
for Certain Investments in Debt and Equity Securities." At
December 31, 1994, PCI's marketable securities, all of which are
classified as available-for-sale as defined by SFAS No. 115,
consist primarily of investment grade preferred stocks with
mandatory redemption features. Pursuant to SFAS No. 115, net
unrealized gains and losses on such securities are reflected, net
of tax, in stockholder's equity.
At December 31, 1993, preferred stock with mandatory
redemption features and corporate debt securities were generally
carried at cost and amortized cost, respectively. Certain of
these securities which the Company believed had been permanently
impaired were carried at estimated net realizable value. Equity
securities at December 31, 1993 were carried at the lower of cost
or market and any unrealized losses thereon were recognized, net
of tax, in stockholder's equity.
64
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
December 31,
1994 1993
---------------------------------------------------------------
Gross
Market Unrealized Carrying Market
Cost Value Losses Value Value
- -----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Mandatory redeemable
preferred stock $ 511,791 $ 473,608 $ (38,183) $ 465,034 $ 472,633
Debt securities - - - 1,116 518
Equity securities 3 - (3) 3 -
---------- ---------- ---------- ---------- ----------
Total $ 511,794 $ 473,608 $ (38,186) $ 466,153 $ 473,151
========== ========== ========== ========== ==========
- -----------------------------------------------------------------------------------------
65
</TABLE>
Net recognized gains from marketable securities amounted to
$7 million and $7.5 million in 1993 and 1992, respectively.
At December 31, 1994, the contractual maturities (in
thousands of dollars) for mandatory redeemable preferred stock
are shown below.
Within one year $ 13,192
One to five years 50,247
Five to ten years 189,797
Over ten years 258,555
--------
Less gross unrealized 511,791
losses (38,183)
--------
$473,608
========
In determining gross realized gains and losses on sales or
maturities of securities, specific identification is used.
For the Year Ended
December 31, 1994
------------------
(Thousands of Dollars)
Gross realized gains $ 2,889
Gross realized losses (2,139)
-------
Net gain $ 750
=======
66
Leasing Activities
- ------------------
PCI's net investment in finance leases consists primarily of
direct finance leases and are summarized below.
- -----------------------------------------------------------------
December 31,
1994 1993
- -----------------------------------------------------------------
(Thousands of Dollars)
Rents receivable $517,052 $419,284
Estimated residual values 153,814 155,187
Less: Unearned and deferred income (260,539) (215,947)
-------- --------
Investment in finance leases 410,327 358,524
Less: Deferred taxes arising from
finance leases (134,925) (130,833)
-------- --------
Net investment in finance leases $275,402 $227,691
======== ========
- -----------------------------------------------------------------
Minimum lease payments receivable from finance leases,
primarily aircraft, for each of the years 1995 through 1999 are
$43.5 million, $32.3 million, $27.1 million, $31.2 million and
$30 million, respectively. Net income from leveraged leases was
$5.6 million in 1994, $1.1 million in 1993 and $7.1 million in
1992.
Rent payments receivable from aircraft equipment operating
leases for each of the years 1995 through 1999 are $49.1 million
in 1995, $44.8 million in 1996, $42.5 million in 1997, $33.8
million in 1998 and $29.1 million in 1999.
During 1994, PCI purchased and leased back to a Dutch
electric generating company a one-third undivided interest in a
recently-constructed 650 megawatt (gross) baseload, coal and gas
fired power plant located in the Netherlands. PCI's equity
investment totaled $60 million and is accounted for as a
leveraged lease.
In September 1992, PCI entered into an operating lease, as
lessee of two aircraft with monthly rental payments of
approximately $850,000. The lease is scheduled to terminate in
September 1997.
67
<TABLE>
(16) Quarterly Financial Summary (Unaudited)
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter Total
- ---------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars except Per Share Data)
<S> <C> <C> <C> <C> <C>
1994
Operating Revenue $ 374,910 458,431 605,023 352,236 1,790,600
Total Revenue $ 393,044 467,451 607,476 355,103 1,823,074
Operating Expenses $ 355,708 370,439 447,020 325,414 1,498,581
Operating Income $ 37,336 97,012 160,456 29,689 324,493
Net Income $ 14,414 64,293 134,702 13,753 227,162
Earnings for Common Stock $ 10,268 60,224 130,576 9,657 210,725
Earnings Per Common Share $ .09 .51 1.11 .08 1.79
Dividends Per Share $ .415 .415 .415 .415 1.66
1993
Operating Revenue $ 331,236 416,152 610,540 344,514 1,702,442
Total Revenue $ 339,455 419,693 614,261 351,796 1,725,205
Operating Expenses $ 302,833 332,796 442,306 322,608 1,400,543
Operating Income $ 36,622 86,897 171,955 29,188 324,662
Net Income $ 13,044 77,022 144,671 6,842 241,579
Earnings for Common Stock $ 8,931 72,974 140,631 2,788 225,324
Earnings Per Common Share $ .08 .63 1.21 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
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.
68
</TABLE>
<TABLE>
Stock Market Information
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------
1994 High Low 1993 High Low
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1st Quarter $26-5/8 $21-3/4 1st Quarter $26-1/2 $23-7/8
2nd Quarter $23-1/2 $18-1/2 2nd Quarter $27-3/8 $25-5/8
3rd Quarter $21-1/2 $18-3/8 3rd Quarter $28-7/8 $27-1/8
4th Quarter $19-3/4 $18-1/4 4th Quarter $28-3/4 $24-5/8
(Close $18-3/8) (Close $26-3/4)
Shareholders at December 31, 1994: 96,638
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990 1989 1984
- -----------------------------------------------------------------------------------------------------------------------------
(Thousands except Per Share Data)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenue $1,790,600 1,702,442 1,562,167 1,552,066 1,411,713 1,394,909 1,197,534
Total Revenue $1,823,074 1,725,205 1,601,558 1,619,315 1,501,728 1,531,024 1,363,998
Operating Expenses $1,498,581 1,400,543 1,322,105 1,329,084 1,245,579 1,256,553 1,129,148
Net Earnings from Nonutility
Subsidiary $ 19,088 25,101 28,161 23,351 5,035 31,100 6,618
Income Before Cumulative Effect of
Accounting Change $ 227,162 241,579 200,760 210,164 170,234 214,587 168,184
Cumulative Effect of Accounting
Change, Net of Income Taxes $ - - 16,022 - - - -
Net Income $ 227,162 241,579 216,782 210,164 170,234 214,587 168,184
Earnings for Common Stock $ 210,725 225,324 202,390 197,866 159,636 205,352 152,331
Average Common Shares Outstanding 118,006 115,640 112,390 105,911 98,621 95,203 94,340
Earnings Per Common Share
Utility Operations <F1> $ 1.63 1.73 1.55 1.65 1.57 1.83 1.54
Nonutility Subsidiary $ .16 .22 .25 .22 .05 .33 .07
Consolidated $ 1.79 1.95 1.80 1.87 1.62 2.16 1.61
Cash Dividends Per Common Share $ 1.66 1.64 1.60 1.56 1.52 1.46 0.97
Investment in Property
and Plant $5,938,031 5,665,141 5,367,624 5,048,121 4,659,280 4,270,718 3,201,287
Net Investment in Property
and Plant $4,298,260 4,131,142 3,931,257 3,706,866 3,397,992 3,097,532 2,374,217
Utility Assets $5,291,467 5,000,328 4,478,762 4,174,713 3,852,415 3,528,883 2,801,091
Nonutility Subsidiary Assets $1,674,289 1,665,132 1,663,508 1,679,079 1,387,247 1,113,827 264,366
Total Assets $6,965,756 6,665,460 6,142,270 5,853,792 5,239,662 4,642,710 3,065,457
Long-Term Utility Obligations
(including redeemable preferred
and preference stock) $1,866,962 1,736,621 1,727,609 1,662,157 1,516,073 1,286,429 1,096,272
- -----------------------------------------------------------------------------------------------------------------------------
<FN>
<F1> The 1992 earnings per share amount from utility operations includes $.14
as the cumulative effect of an accounting change for unbilled revenue.
</FN>
69
</TABLE>
