SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
Quarterly Report Under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For Quarter Ended March 31, 1997
--------------
Commission file number 1-1072
------
Potomac Electric Power Company
- ----------------------------------------------------------------
(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0127880
- ----------------------------------------------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1900 Pennsylvania Avenue, N.W., Washington, D.C. 20068
- ----------------------------------------------------------------
(Address of principal executive office) (Zip Code)
(202) 872-2000
- ----------------------------------------------------------------
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
and (2) has been subject to such filing requirements for the past
90 days. Yes /X/. No / /.
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of the latest practicable
date.
Class Outstanding at March 31, 1997
- -------------------------- -----------------------------
Common Stock, $1 par value 118,497,098
TABLE OF CONTENTS
PART I - Financial Information Page
Item 1 - Consolidated Financial Statements
Consolidated Statements of Earnings and Retained Income.. 2
Consolidated Balance Sheets.............................. 3
Consolidated Statements of Cash Flows.................... 4
Notes to Consolidated Financial Statements
(1) Summary of Significant Accounting Policies......... 5
(2) Income Taxes....................................... 10
(3) Capitalization..................................... 13
(4) Fair Value of Financial Instruments................ 15
(5) Marketable Securities.............................. 17
(6) Commitments and Contingencies...................... 18
Report of Independent Accountants on Review of Interim
Financial Information.................................. 25
Item 2 - Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Utility
Proposed Merger Update................................. 26
Results of Operations.................................. 28
Capital Resources and Liquidity........................ 30
New Accounting Standards............................... 31
Nonutility Subsidiary
Results of Operations.................................. 31
Capital Resources and Liquidity........................ 34
PART II - Other Information
Item 1 - Legal Proceedings................................. 35
Item 5 - Other Information
Other Financing Arrangements............................. 35
Base Rate Proceedings.................................... 35
Restructuring of the Bulk Power Market................... 38
Competition.............................................. 40
Peak Load, Sales, Conservation, and Construction and
Generating Capacity.................................... 41
Selected Nonutility Subsidiary Financial Information..... 44
Statistical Data......................................... 46
Unaudited Pro Forma Combined Condensed Financial
Information............................................ 47
Item 6 - Exhibits and Reports on Form 8-K.................. 55
Signatures................................................. 56
Computations of Earnings Per Common Share.................. 57
Computation of Ratios - Parent Company Only................ 58
Computation of Ratios - Fully Consolidated................. 59
Independent Accountants Awareness Letter................... 60
1
<TABLE>
Part I FINANCIAL INFORMATION
- ------ ---------------------
Item 1 CONSOLIDATED FINANCIAL STATEMENTS
- ------ ---------------------------------
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Earnings and Retained Income
(Unaudited)
-------------------------------------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
-------------------- ----------------------
1997 1996 1997 1996
--------- --------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Revenue
Sales of electricity $ 369,653 $ 382,576 $1,811,818 $1,835,195
Other electric revenue 4,833 2,696 12,252 9,076
--------- --------- ---------- ----------
Total Operating Revenue 374,486 385,272 1,824,070 1,844,271
Interchange deliveries 14,574 51,321 138,708 103,514
--------- --------- ---------- ----------
Total Revenue 389,060 436,593 1,962,778 1,947,785
--------- --------- ---------- ----------
Operating Expenses
Fuel 78,507 92,713 313,586 364,626
Purchased energy 51,074 81,302 305,751 232,254
Capacity purchase payments 35,944 32,278 129,452 125,586
Other operation 51,836 55,719 219,443 221,513
Maintenance 21,173 21,427 91,270 91,459
--------- --------- ---------- ----------
Total Operation and Maintenance 238,534 283,439 1,059,502 1,035,438
Depreciation and amortization 57,600 55,401 225,215 213,232
Income taxes 5,295 8,171 131,208 137,051
Other taxes 45,409 45,555 200,219 201,114
--------- --------- ---------- ----------
Total Operating Expenses 346,838 392,566 1,616,144 1,586,835
--------- --------- ---------- ----------
Operating Income 42,222 44,027 346,634 360,950
--------- --------- ---------- ----------
Other Income (Loss)
Nonutility Subsidiary
Income 39,807 17,313 137,460 117,919
Loss on assets held for disposal - (12,320) (424) (182,398)
Expenses, including interest
and income taxes (26,357) (2,525) (109,160) (53,076)
--------- --------- ---------- ----------
Net earnings (loss) from nonutility
subsidiary 13,450 2,468 27,876 (117,555)
Allowance for other funds used during
construction and capital cost recovery factor 1,660 1,737 6,495 6,484
Other, net 686 1,755 3,388 1,344
--------- --------- ---------- ----------
Total Other Income (Loss) 15,796 5,960 37,759 (109,727)
--------- --------- ---------- ----------
Income Before Utility Interest Charges 58,018 49,987 384,393 251,223
--------- --------- ---------- ----------
Utility Interest Charges
Long-term debt 34,744 33,434 134,416 132,748
Other 2,098 3,787 12,144 15,426
Allowance for borrowed funds used during
construction and capital cost recovery factor (1,806) (1,968) (7,375) (10,048)
--------- --------- ---------- ----------
Net Utility Interest Charges 35,036 35,253 139,185 138,126
--------- --------- ---------- ----------
Net Income 22,982 14,734 245,208 113,097
Dividends on Preferred Stock 4,145 4,160 16,590 16,769
--------- --------- ---------- ----------
Earnings for Common Stock 18,837 10,574 228,618 96,328
Retained Income at Beginning of Period 760,285 742,296 695,521 785,792
Dividends on Common Stock (49,148) (49,152) (196,607) (196,576)
Subsidiary Marketable Securities Net
Unrealized Gain (Loss), Net of Tax 223 (8,197) 2,665 9,977
--------- --------- ---------- ----------
Retained Income at End of Period $ 730,197 $ 695,521 $ 730,197 $ 695,521
========= ========= ========== ==========
Average Common Shares
Outstanding (000's) 118,499 118,495 118,498 118,473
Earnings Per Common Share $0.16 $0.09 $1.93 $0.81
Cash Dividends Per Common Share $0.415 $0.415 $1.66 $1.66
Book Value Per Share $15.69 $15.40
2
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Balance Sheets
(Unaudited at March 31, 1997 and 1996)
--------------------------------------
<CAPTION>
March 31, December 31, March 31,
ASSETS 1997 1996 1996
------ ------------- ------------- -------------
(Thousands of Dollars)
<S> <C> <C> <C>
Property and Plant - at original cost
Electric plant in service $ 6,244,707 $ 6,232,049 $ 6,069,071
Construction work in progress 74,292 62,469 103,015
Electric plant held for future use 4,170 4,152 4,096
Nonoperating property 22,976 22,921 22,771
------------- ------------- -------------
6,346,145 6,321,591 6,198,953
Accumulated depreciation (1,920,609) (1,898,342) (1,800,460)
------------- ------------- -------------
Net Property and Plant 4,425,536 4,423,249 4,398,493
------------- ------------- -------------
Current Assets
Cash and cash equivalents 1,263 2,174 11,400
Customer accounts receivable, less allowance
for uncollectible accounts of $673, $1,298
and $1,482 119,047 128,600 133,053
Other accounts receivable, less allowance for
uncollectible accounts of $300 30,491 38,490 37,810
Accrued unbilled revenue 62,976 70,214 63,015
Prepaid taxes 18,004 34,202 27,489
Other prepaid expenses 3,599 4,613 4,200
Material and supplies - at average cost
Fuel 74,243 68,232 66,222
Construction and maintenance 69,026 69,541 70,513
------------- ------------- -------------
Total Current Assets 378,649 416,066 413,702
------------- ------------- -------------
Deferred Charges
Income taxes recoverable through future rates, net 238,517 238,467 240,320
Conservation costs, net 229,684 233,793 234,460
Unamortized debt reacquisition costs 54,851 55,552 57,658
Other 168,268 159,139 149,024
------------- ------------- -------------
Total Deferred Charges 691,320 686,951 681,462
------------- ------------- -------------
Nonutility Subsidiary Assets
Cash and cash equivalents 53,280 804 3,545
Marketable securities 310,473 377,237 417,377
Investment in finance leases 493,761 484,972 476,879
Operating lease equipment, net of accumulated
depreciation of $127,856, $117,705 and $89,629 188,974 199,124 262,025
Assets held for disposal 5,900 10,300 28,300
Receivables, less allowance for uncollectible
accounts of $6,000 66,622 87,745 63,004
Other investments 185,880 193,002 156,481
Other assets 16,133 12,436 15,416
------------- ------------- -------------
Total Nonutility Subsidiary Assets 1,321,023 1,365,620 1,423,027
------------- ------------- -------------
Total Assets $ 6,816,528 $ 6,891,886 $ 6,916,684
============= ============= =============
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization
Common stock $ 118,497 $ 118,500 $ 118,495
Other common equity 1,740,630 1,770,692 1,706,011
Serial preferred stock 125,297 125,298 125,319
Redeemable serial preferred stock 142,500 142,500 143,485
Long-term debt 1,718,310 1,767,598 1,817,727
------------- ------------- -------------
Total Capitalization 3,845,234 3,924,588 3,911,037
------------- ------------- -------------
Other Noncurrent Liabilities
Capital lease obligations 162,322 162,936 164,677
------------- ------------- -------------
Total Other Noncurrent Liabilities 162,322 162,936 164,677
------------- ------------- -------------
Current Liabilities
Long-term debt and preferred stock
redemption due within one year 200,985 152,445 25,000
Short-term debt 173,540 131,390 286,940
Accounts payable and accrued expenses 143,565 179,289 163,481
Capital lease obligations due within one year 20,772 20,772 20,772
Other 79,939 83,135 77,527
------------- ------------- -------------
Total Current Liabilities 618,801 567,031 573,720
------------- ------------- -------------
Deferred Credits
Income taxes 986,453 973,642 896,258
Investment tax credits 60,045 60,958 63,695
Other 39,398 35,658 36,193
------------- ------------- -------------
Total Deferred Credits 1,085,896 1,070,258 996,146
------------- ------------- -------------
Nonutility Subsidiary Liabilities
Long-term debt 989,480 996,232 1,066,688
Short-term notes payable 1,000 51,650 73,230
Deferred taxes and other 113,795 119,191 131,186
------------- ------------- -------------
Total Nonutility Subsidiary Liabilities 1,104,275 1,167,073 1,271,104
------------- ------------- -------------
Total Capitalization and Liabilities $ 6,816,528 $ 6,891,886 $ 6,916,684
============= ============= =============
3
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
-------------------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
----------------------- -----------------------
1997 1996 1997 1996
--------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Activities
Income from utility operations $ 9,532 $ 12,266 $ 217,332 $ 230,652
Adjustments to reconcile income to net
cash from operating activities:
Depreciation and amortization 57,600 55,401 225,215 213,232
Deferred income taxes and investment tax credits 12,275 (5) 93,775 39,629
Allowance for funds used during construction
and capital cost recovery factor (3,466) (3,705) (13,870) (16,532)
Changes in materials and supplies (5,496) (3,035) (6,534) (3,775)
Changes in accounts receivable and accrued unbilled revenue 24,790 13,965 21,364 (38,537)
Changes in accounts payable (21,180) 9,850 (17,406) 10,146
Changes in other current assets and liabilities (1,165) 1,526 3,168 (940)
Changes in deferred conservation costs (7,644) (15,829) (41,219) (95,115)
Net other operating activities (9,870) (7,705) (50,840) (37,718)
Nonutility subsidiary:
Net earnings (loss) 13,450 2,468 27,876 (117,555)
Deferred income taxes (21,738) (34,724) (23,412) (81,890)
Loss on assets held for disposal - 12,320 424 182,398
Changes in other assets and net other operating activities 28,565 33,778 31,045 98,944
--------- --------- --------- ---------
Net Cash From Operating Activities 75,653 76,571 466,918 382,939
--------- --------- --------- ---------
Investing Activities
Total investment in property and plant (42,609) (41,538) (195,108) (207,802)
Allowance for funds used during construction
and capital cost recovery factor 3,466 3,705 13,870 16,532
--------- --------- --------- ---------
Net investment in property and plant (39,143) (37,833) (181,238) (191,270)
Nonutility subsidiary:
Purchase of marketable securities (23,133) (11,252) (31,561) (44,404)
Proceeds from sale or redemption of marketable securities 95,502 113,177 149,853 134,701
Investment in leased equipment (7,480) - (10,536) (148,148)
Proceeds from sale or disposition of leased equipment - - 3,658 24,500
Proceeds from assets held for disposal - - 9,654 -
Proceeds from sale of assets 1,600 24,785 1,315 6,251
Purchase of other investments (15,963) (932) (38,029) (4,153)
Proceeds from sale or distribution of other investments 4,723 1,385 37,205 5,978
Investment in promissory notes (12) (2,593) (1,664) (10,548)
Proceeds from promissory notes 30,019 1,980 44,714 8,288
--------- --------- --------- ---------
Net Cash From (Used by) Investing Activities 46,113 88,717 (16,629) (218,805)
--------- --------- --------- ---------
Financing Activities
Dividends on common stock (49,148) (49,152) (196,607) (196,576)
Dividends on preferred stock (4,145) (4,160) (16,590) (16,769)
Issuance of common stock - - - 2,685
Redemption of preferred stock - - - (78)
Issuance of long-term debt - - 99,500 172,754
Reacquisition and retirement of long-term debt (1,460) (1,300) (26,480) (101,282)
Short-term debt, net 42,150 28,475 (113,400) 49,415
Other financing activities (196) (728) (4,823) (20,343)
Nonutility subsidiary:
Issuance of long-term debt - 78,000 105,000 185,000
Repayment of long-term debt (6,752) (58,796) (185,058) (272,065)
Short-term debt, net (50,650) (150,120) (72,233) 45,830
--------- --------- --------- ---------
Net Cash Used By Financing Activities (70,201) (157,781) (410,691) (151,429)
--------- --------- --------- ---------
Net Increase in Cash and Cash Equivalents 51,565 7,507 39,598 12,705
Cash and Cash Equivalents at Beginning of Period 2,978 7,438 14,945 2,240
--------- --------- --------- ---------
Cash and Cash Equivalents at End of Period $ 54,543 $ 14,945 $ 54,543 $ 14,945
========= ========= ========= =========
Cash paid for interest (net of capitalized interest) and income taxes:
Interest (including nonutility subsidiary
interest of $31,331, $34,800, $79,920 and $86,803) $ 73,246 $ 78,791 $ 211,421 $ 218,675
Income taxes $ 1,761 $ 2,559 $ 27,732 $ 44,638
4
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
------------------------------------------
The Company is engaged in the generation, transmission,
distribution and sale of electric energy in the Washington, D.C.
metropolitan area. The Company's retail service territory
includes all of the District of Columbia and major portions of
Montgomery and Prince George's counties in suburban Maryland.
Potomac Capital Investment Corporation (PCI), the Company's
wholly owned subsidiary, was formed in 1983 to provide a
permanent vehicle for the conduct of the Company's ongoing
nonutility investment programs. Effective April 30, 1996, the
Company reorganized its nonutility subsidiaries whereby PEPCO
Enterprises, Inc. (PEI) became a subsidiary of PCI. PCI's
principal investments have been in aircraft and power generation
equipment, equipment leasing and marketable securities, primarily
preferred stock with mandatory redemption features. PCI is also
involved with activities, through PEI, which provide utility-
related telecommunication and energy services. In addition, PCI
has investments in real estate properties in the Washington, D.C.
metropolitan area.
The Company's utility operations are regulated by the
Maryland and District of Columbia Public Service Commissions and
its wholesale business by the Federal Energy Regulatory
Commission (FERC). The Company complies with the Uniform System
of Accounts prescribed by the FERC and adopted by the Maryland
and District of Columbia regulatory commissions. Based upon the
regulatory framework in which it operates, the Company currently
applies the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71 entitled "Accounting for the Effects of
Certain Types of Regulation" in accounting for certain deferred
charges and credits to be recognized in future customer billings
pursuant to regulatory authorization, principally deferred income
taxes, unamortized conservation costs and unamortized debt
reacquisition costs.
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenue and expenses during the reporting
period. Actual results could differ from those estimates and
assumptions.
5
Certain 1996 amounts have been reclassified to conform to
the current year presentation.
A description of significant accounting policies follows.
Principles of Consolidation
- ---------------------------
The consolidated financial statements combine the financial
results of the Company and PCI. All material intercompany
balances and transactions have been eliminated.
Total Revenue
- -------------
Revenue is accrued for service rendered but unbilled as of
the end of each month. The Company includes in revenue the
amounts received for sales of energy, and resales of purchased
energy, to other utilities and to power marketers. Amounts
received for such interchange deliveries are a component of the
Company's fuel rates.
In each jurisdiction, the Company's rate schedules include
fuel rates. The fuel rate provisions are designed to provide for
separately stated fuel billings which cover applicable net fuel
and interchange costs, purchased capacity in the District of
Columbia, and emission allowance costs in the Company's retail
jurisdictions, or changes in the applicable costs from levels
incorporated in base rates. Differences between applicable net
costs incurred and fuel rate revenue billed in any given period
are accounted for as other current assets or other current
liabilities in those cases where specific provision has been made
by the appropriate regulatory commission for the resolution of
such differences within one year. Where no such provision has
been made, the differences are accounted for as other deferred
charges or other deferred credits pending regulatory
determination.
In the District of Columbia, pre-July 1993 conservation
costs receive rate base treatment. Conservation expenditures for
the period July 1993 to December 1994 are recovered through a
surcharge mechanism which initially became effective July 11,
1995, and which is scheduled to be updated annually on June 1 to
recover 1995 and subsequent conservation expenditures, including
a capital cost recovery factor (CCRF), which is a mechanism that
enables the Company to earn a return on certain costs,
principally unamortized Demand Side Management (DSM) costs not in
rate base. A procedure has been established to consider lost
revenue without the need for base rate proceedings. In Maryland,
conservation costs are recovered through a surcharge rate which
reflects amortization of program costs, including costs in the
year during which the surcharge commences, a CCRF, incentives,
6
applicable taxes and estimated lost revenue. The surcharge is
established annually in a collaborative process with the recovery
of lost revenue subject to an earnings test performed on a
quarterly basis.
Leasing Transactions
- --------------------
Income from PCI investments in direct finance and leveraged
lease transactions, in which PCI is an equity participant, is
reported using the financing method. In accordance with the
financing method, investments in leased property are recorded as
a receivable from the lessee to be recovered through the
collection of future rentals. For direct finance leases,
unearned income is amortized to income over the lease term at a
constant rate of return on the net investment. Income, including
investment tax credits on leveraged equipment leases, is
recognized over the life of the lease at a level rate of return
on the positive net investment.
PCI investments in equipment under operating leases are
stated at cost less accumulated depreciation, except that assets
held for disposal are carried at estimated fair value less
estimated costs to sell. Depreciation is recorded on a straight
line basis over the equipment's estimated useful life. No
depreciation is taken on assets held for disposal.
Property and Plant
- ------------------
The cost of additions to, and replacements or betterments
of, retirement units of property and plant is capitalized. Such
cost includes material, labor, the capitalization of an Allowance
for Funds Used During Construction (AFUDC) and applicable
indirect costs, including engineering, supervision, payroll taxes
and employee benefits. The original cost of depreciable units of
plant retired, together with the cost of removal, net of salvage,
is charged to accumulated depreciation. Routine repairs and
maintenance are charged to operating expenses as incurred.
The Company uses separate depreciation rates for each
electric plant account. The rates, which vary from jurisdiction
to jurisdiction, were equivalent to a system-wide composite
depreciation rate of approximately 3.1% for 1997, 1996 and 1995.
7
Conservation
- ------------
In general, the Company accounts for conservation
expenditures in connection with its DSM program as a deferred
charge, and amortizes the costs over five years in Maryland and
10 years in the District of Columbia. At March 31, 1997,
unamortized conservation costs totaled $91.7 million in Maryland
and $138 million in the District of Columbia.
Allowance for Funds Used During Construction and Capital Cost
- -------------------------------------------------------------
Recovery Factor
---------------
In general, the Company capitalizes AFUDC with respect to
investments in Construction Work in Progress with the exception
of expenditures required to comply with federal, state or local
environmental regulations (pollution control projects), which are
included in rate base without capitalization of AFUDC. The
jurisdictional AFUDC capitalization rates are determined as
prescribed by the FERC. The effective capitalization rates were
approximately 7.3%, compounded semiannually, for the three months
ended March 31, 1997, and approximately 7.4% in 1996 and 7.9% in
1995, compounded semiannually.
In Maryland, the Company accrues a CCRF on the retail
jurisdictional portion of certain pollution control expenditures
related to compliance with the Clean Air Act (CAA). The base for
calculating this return is the amount by which the Maryland
jurisdictional CAA expenditure balance exceeds the CAA balance
being recovered in base rates. The CCRF rate for Maryland is
9.46%. In the District of Columbia, the carrying costs of CAA
expenditures not in rate base are recovered through a base rate
surcharge.
Amortization of Debt Issuance and Reacquisition Costs
- -----------------------------------------------------
The Company defers and amortizes expenses incurred in
connection with the issuance of long-term debt, including
premiums and discounts associated with such debt, over the lives
of the respective issues. Costs associated with the
reacquisition of debt are also deferred and amortized over the
lives of the new issues.
8
Cash and Cash Equivalents
- -------------------------
For purposes of the consolidated financial statements, cash
and cash equivalents include cash on hand, money market funds and
commercial paper with original maturities of three months or
less.
New Accounting Standards
- ------------------------
In October 1996, the American Institute of Certified Public
Accountants issued Statement of Position (SOP) 96-1 entitled
"Environmental Remediation Liabilities," which became effective
January 1, 1997. SOP 96-1 provides authoritative guidance for
recognition, measurement, display and disclosure of environmental
remediation liabilities in financial statements. Adoption of
this pronouncement did not have an effect on the Company's
financial statements.
In February 1997, the Financial Accounting Standards Board
issued SFAS No. 128 and 129 entitled "Earnings Per Share" and
"Disclosure of Information about Capital Structure,"
respectively. SFAS No. 128 simplifies the earnings per share
(EPS) computation and replaces the presentation of primary EPS
with a presentation of basic EPS. This statement also requires
dual presentation of basic and diluted EPS on the face of the
income statement for entities with a complex capital structure
and requires a reconciliation of the numerator and denominator
used for the basic and diluted EPS computation. SFAS No. 128 is
required to be implemented in the fourth quarter of 1997 and will
not have a significant impact on the calculation of the Company's
EPS. SFAS No. 129, which is also effective for calendar year
1997 financial statements, essentially consolidates disclosures
required by several other pronouncements. The Company's
disclosures are already in compliance with such pronouncements
and, accordingly, SFAS No. 129 will not require any change to
existing disclosures.
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.
9
<TABLE>
(2) INCOME TAXES
- ----------------
Provision for Income Taxes
- --------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
--------------------- ----------------------
1997 1996 1997 1996
-------- -------- -------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Utility current tax expense
Federal $ (6,443) $ 8,519 $ 32,273 $ 88,408
State and local (851) 777 4,653 11,402
-------- -------- -------- ---------
Total utility current tax expense (7,294) 9,296 36,926 99,810
-------- -------- -------- ---------
Utility deferred tax expense
Federal 11,403 279 85,885 37,149
State and local 1,784 628 11,539 6,129
Investment tax credits (912) (912) (3,649) (3,649)
-------- -------- -------- ---------
Total utility deferred tax expense 12,275 (5) 93,775 39,629
-------- -------- -------- ---------
Total utility income tax expense 4,981 9,291 130,701 139,439
-------- -------- -------- ---------
Nonutility subsidiary current tax expense
Federal 7,206 (4,034) (7,012) (36,392)
-------- -------- -------- ---------
Nonutility subsidiary deferred tax expense
Federal (20,188) (34,728) (21,833) (81,789)
State and local - - - -
-------- -------- -------- ---------
Total nonutility subsidiary deferred tax expense (20,188) (34,728) (21,833) (81,789)
-------- -------- -------- ---------
Total nonutility subsidiary income tax expense (12,982) (38,762) (28,845) (118,181)
-------- -------- -------- ---------
Total consolidated income tax expense (8,001) (29,471) 101,856 21,258
Income taxes included in other income (13,296) (37,642) (29,352) (115,793)
-------- -------- -------- ---------
Income taxes included in utility operating expenses $ 5,295 $ 8,171 $131,208 $ 137,051
======== ======== ======== =========
10
</TABLE>
<TABLE>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
---------------------- ----------------------
1997 1996 1997 1996
-------- -------- -------- --------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Income (loss) before income taxes $ 14,981 $(14,737) $347,064 $ 134,355
======== ======== ======== =========
Utility income tax at federal
statutory rate $ 5,079 $ 7,545 $121,811 $ 129,532
Increases (decreases) resulting from
Depreciation 2,522 2,542 9,847 9,467
Removal costs (1,392) (308) (4,658) (6,281)
Allowance for funds used during
construction 205 134 762 564
Other (1,128) (541) (3,705) (1,117)
State income taxes, net of federal effect 607 831 10,525 11,313
Tax credits (912) (912) (3,881) (4,039)
-------- -------- -------- ---------
Total utility income tax expense 4,981 9,291 130,701 139,439
-------- -------- -------- ---------
Nonutility subsidiary income tax at federal
statutory rate 164 (12,703) (339) (82,508)
Increases (decreases) resulting from
Dividends received deduction (1,522) (1,636) (7,000) (7,959)
Reversal of previously accrued deferred taxes (10,125) (23,506) (17,423) (23,506)
Other (1,499) (917) (4,083) (4,208)
-------- -------- -------- ---------
Total nonutility subsidiary income tax credit (12,982) (38,762) (28,845) (118,181)
-------- -------- -------- ---------
Total consolidated income tax expense (8,001) (29,471) 101,856 21,258
Income taxes, included in other income (13,296) (37,642) (29,352) (115,793)
-------- -------- -------- ---------
Income taxes included in utility operating expenses $ 5,295 $ 8,171 $131,208 $ 137,051
======== ======== ======== =========
11
</TABLE>
<TABLE>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
<CAPTION>
Mar. 31, Dec. 31, Mar. 31,
1997 1996 1996
--------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax
basis differences $832,877 $821,656 $787,327
Rapid amortization of certified pollution
control facilities 24,426 24,816 26,147
Deferred taxes on amounts to be collected
through future rates 90,302 90,284 90,985
Property taxes 12,878 12,664 11,969
Deferred fuel (14,855) (14,663) (12,621)
Prepayment premium on debt retirement 20,759 21,025 21,809
Deferred investment tax credit (22,733) (23,079) (24,115)
Contributions in aid of construction (28,811) (28,719) (27,325)
Contributions to pension plan 16,170 16,170 11,329
Conservation costs (demand side management) 43,435 41,106 -
Other 21,701 21,653 15,023
-------- -------- --------
Total utility deferred tax liabilities (net) 996,149 982,913 900,528
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 9,696 9,271 4,270
-------- -------- --------
Total utility deferred tax liabilities (net) - noncurrent $986,453 $973,642 $896,258
======== ======== ========
Nonutility subsidiary deferred tax liabilities (assets)
Finance leases $142,572 $144,667 $119,384
Operating leases 39,192 57,006 65,872
Alternative minimum tax (97,109) (97,109) (80,933)
Other (45,204) (43,496) (40,501)
-------- -------- --------
Total nonutility subsidiary deferred tax liabilities
(net), (included in Deferred taxes and other) $ 39,451 $ 61,068 $ 63,822
======== ======== ========
12
</TABLE>
(3) CAPITALIZATION
--------------
Common Equity
- -------------
At March 31, 1997, 118,497,098 shares of the Company's $1
par value Common Stock were outstanding. A total of 200 million
shares is authorized. As of March 31, 1997, 2,324,721 shares
were reserved for issuance under the Shareholder Dividend
Reinvestment Plan; 1,221,624 shares were reserved for issuance
under the Employee Savings Plans; and 2,769,412 and 3,392,500
shares were reserved for conversion of the 7% and 5% Convertible
Debentures, respectively. Under the Stock Option Agreement with
Baltimore Gas and Electric Company, 23,579,900 shares could
become issuable, contingent upon specific events associated with
termination of the Merger Agreement. (See Note 6 - Commitments
and Contingencies for additional information.)
Serial Preferred, Redeemable Serial Preferred and Preference
- ------------------------------------------------------------
Stock and Long-Term Debt
------------------------
At March 31, 1997, the Company had outstanding 5,375,642
shares of its $50 par value Serial Preferred Stock, including the
Redeemable Serial Preferred Stock. A total of 11,125,649 shares
is authorized. At March 31, 1997, the aggregate annual dividend
requirements on the Serial Preferred Stock and the Redeemable
Serial Preferred Stock were approximately $6.3 million and $10.2
million, respectively. Also, the Company has a total of
8,800,000 shares of cumulative, $25 par value, Preference Stock
authorized and unissued.
The Company's $2.44 Convertible Preferred Stock, 1966 Series
(5,946 shares outstanding at March 31, 1997) is convertible into
Common Stock at $8.51 per share.
At March 31, 1997, the Company had outstanding one million
shares of its Serial Preferred Stock, Auction Series A. The
annual dividend rate is 3.92% ($1.96) for the period March 1,
1997, through May 31, 1997. For the period December 1, 1996,
through February 28, 1997, the annual dividend rate was 4.20%
($2.10). The average rate at which dividends were paid during
the 12 months ended March 31, 1997, was 4.12% ($2.06).
At March 31, 1997, the Company had outstanding three series
of $50 par value Redeemable Serial Preferred Stock. There are
one million shares of the $3.89 (7.78%) Series of 1991 on which
the sinking fund requirement commences June 1, 2001; one million
shares of the $3.40 (6.80%) Series of 1992 on which the sinking
fund requirement commences September 1, 2002; and 869,696 shares
13
of the $3.37 (6.74%) Series of 1987 on which the sinking fund
requires redemption, beginning June 1993, at par, of not less
than 30,000 nor more than 60,000 shares annually. Sinking fund
requirements through 2001 with respect to the three series of
Redeemable Serial Preferred Stock are $1 million in 1997, $1.5
million in 1998 through 2000 and $9.8 million in 2001.
The Company's Long-Term Debt at March 31, 1997, is
summarized below:
(Thousands of Dollars)
First Mortgage Bonds $1,341,800
Convertible Debentures 178,907
Notes Payable 425,000
Net Unamortized Discount (27,397)
Current Portion (200,000)
----------
Net Utility Long-Term Debt $1,718,310
==========
Nonutility Subsidiary Long-Term Debt $ 989,480
==========
At March 31, 1997, the aggregate annual interest requirement
on the Company's long-term debt, including debt due within one
year, was $132.9 million; and the aggregate amounts of long-term
debt maturities are $150 million in 1997, $50 million in 1998,
$45 million in 1999, $100 million in 2000 and $165 million in
2001. At March 31, 1997, long-term debt due within one year
consisted of $100 million of 6.66% - 6.73% Medium-Term Notes, $50
million of 9.08% Medium-Term Notes and $50 million of 4-3/8%
First Mortgage Bonds.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at March 31, 1997, consisted primarily of
unsecured borrowings from institutional lenders maturing at
various dates between 1997 and 2003. The interest rates of such
borrowings ranged from 5% to 10.1%. The weighted average
effective interest rate was 7.45% at March 31, 1997, 7.44% at
December 31, 1996, and 7.51% at March 31, 1996. Annual aggregate
principal repayments on these borrowings are $189 million in
1997, $300.7 million in 1998, $170 million in 1999, $115 million
in 2000, $54 million in 2001 and $98.5 million thereafter. Also
included in long-term debt is $62.2 million of non-recourse debt
which is due in monthly installments with final maturities in
2001, 2002 and 2011.
14
<TABLE>
(4) FAIR VALUE OF FINANCIAL INSTRUMENTS
- ---------------------------------------
The estimated fair values of the Company's financial instruments at
March 31, 1997, December 31, 1996, and March 31, 1996, are shown below.
<CAPTION>
March 31, December 31, March 31,
1997 1996 1996
-------------------------- ------------------------- -------------------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
----------- ---------- ---------- ---------- ---------- ----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Utility
Capitalization and Liabilities
Serial preferred stock $ 125,297 112,171 125,298 113,285 125,319 110,261
========== ========= ========= ========= ========= =========
Redeemable serial
preferred stock $ 142,500 142,131 142,500 146,491 143,485 148,612
========== ========= ========= ========= ========= =========
Long-term debt
First mortgage bonds $1,277,596 1,229,691 1,327,389 1,319,976 1,326,767 1,305,270
Medium-term notes $ 272,879 263,457 272,788 274,242 323,081 324,542
Convertible debentures $ 167,835 169,771 167,421 171,880 167,879 171,906
---------- --------- --------- --------- --------- ---------
Total long-term debt $1,718,310 1,662,919 1,767,598 1,766,098 1,817,727 1,801,718
========== ========= ========= ========= ========= =========
Nonutility Subsidiary
Assets
Marketable securities $ 310,473 310,473 377,237 377,237 417,377 417,377
========== ========= ========= ========= ========= =========
Notes receivable $ 57,226 58,029 72,251 71,593 63,515 60,575
========== ========= ========= ========= ========= =========
Liabilities
Long-term debt $ 989,480 994,462 996,232 1,011,814 1,066,688 1,089,373
========== ========= ========= ========= ========= =========
15
</TABLE>
The methods and assumptions below were used to estimate, at
March 31, 1997, December 31, 1996, and March 31, 1996, the fair
value of each class of financial instruments shown above for
which it is practicable to estimate that value.
The fair value of the Company's 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, 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.
The carrying amounts of all other financial instruments
approximate fair value.
16
(5) MARKETABLE SECURITIES
---------------------
PCI's marketable securities are classified as available-for-
sale for financial reporting purposes. Investment grade
preferred stocks with mandatory redemption features made up 94%
of the portfolio at March 31, 1997. Net unrealized gains or
losses on such securities are reflected, net of tax, in
stockholder's equity. The net unrealized gains (losses) are
shown below:
As of March 31, 1997
-------------------------------------
Net
Market Unrealized
Cost Value Gain
--------- --------- -----------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 308,490 $ 310,473 $ 1,983
========= ========= =========
As of December 31, 1996
-------------------------------------
Net
Market Unrealized
Cost Value Gain (Loss)
--------- --------- -----------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 375,595 $ 377,237 $ 1,642
Equity securities 3 - (3)
--------- --------- ---------
Total $ 375,598 $ 377,237 $ 1,639
========= ========= =========
As of March 31, 1996
-------------------------------------
Net
Market Unrealized
Cost Value Loss
--------- --------- -----------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 419,153 $ 417,112 $ (2,041)
Equity securities 341 265 (76)
--------- --------- ---------
Total $ 419,494 $ 417,377 $ (2,117)
========== ========= =========
17
Included in net unrealized gains and losses are gross
unrealized gains of $7.7 million and gross unrealized losses of
$5.7 million at March 31, 1997; gross unrealized gains of $9.9
million and gross unrealized losses of $8.3 million at December
31, 1996; and gross unrealized gains of $8.1 million and gross
unrealized losses of $10.2 million at March 31, 1996.
At March 31, 1997, the contractual maturities for mandatory
redeemable preferred stock are $26 million within one year, $91
million from one to five years, $77.7 million from five to 10
years and $113.8 million for over 10 years.
In determining gross realized gains and losses on sales or
calls of securities, specific identification is used. A summary
of realized gains and losses is shown below.
Three Months Ended Three Months Ended
March 31, 1997 March 31, 1996
------------------ ------------------
(Thousands of Dollars)
Gross realized
gains $ 5,884 $ 2,261
Gross realized
losses (623) (671)
--------- ----------
Net gain $ 5,261 $ 1,590
========= ==========
(6) COMMITMENTS AND CONTINGENCIES
-----------------------------
Proposed Merger
- ---------------
The Company entered into an Agreement and Plan of Merger
with Baltimore Gas and Electric Company (BGE) in September 1995.
This Agreement provides for a strategic business combination in
which each company will merge into Constellation Energy
Corporation (Constellation Energy), a newly formed company, to
create an integrated, non-holding company structure (the Merger).
Each outstanding share of the Company's common stock will be
converted into the right to receive .997 of a share of common
stock of Constellation Energy and each outstanding share of BGE
common stock will be converted into the right to receive one
share of Constellation Energy's common stock. This transaction
is expected to qualify as a tax-free exchange of shares for the
holders of each company's common stock and as a pooling of
interests for accounting purposes. Constellation Energy will
serve a population of approximately 4.5 million with
approximately 1.8 million electric customers and over 557,000
natural gas customers. Preliminary estimates indicate that
savings from the combined utility systems will approximate $1.3
billion over 10 years following the Merger. These savings are
18
net of costs to achieve, which are presently estimated to be
approximately $150 million. Approximately two-thirds of the
projected savings are expected to result from reduced labor
costs, with the remaining savings split between nonfuel
purchasing and corporate and administrative programs. The
allocation of the net savings between customers and shareholders
of Constellation Energy will be determined in regulatory
proceedings. The applications for approval of the Merger, filed
with the various regulatory commissions, set forth the proposed
plans for Constellation Energy to share the benefits of the
Merger with customers in the District of Columbia and Maryland.
The proposal included: 1) a freeze on base electric rates until
at least January 1, 2000, 2) a unique bill credit for all
customers if Constellation Energy achieves certain financial
targets, 3) an array of economic development incentives and 4)
programs to address the energy needs of low-income customers.
The development of estimated savings resulting from the Merger
was based upon assumptions which involve judgments with respect
to, among other things, future national and regional economic and
competitive conditions, inflation rates, regulatory treatment,
weather conditions, financial market conditions, interest rates,
future business decisions and other uncertainties, all of which
are difficult to predict and many of which are beyond the control
of the Company and BGE. Accordingly, while the Company believes
that such assumptions are reasonable for purposes of the
development of estimates of potential savings, there can be no
assurance that such assumptions will approximate actual
experience or that all such savings will be realized. At March
31, 1997, the Company had deferred $33.6 million in costs related
to the Merger. If the Merger is not completed, certain Merger
related costs would be written off as a charge against the
Company's results of operations.
Shareholders of the Company and BGE, at separate special
meetings during March 1996, approved the Merger Agreement. The
Company and BGE filed a joint Application for Authorization and
Approval of the Merger with the FERC on January 11, 1996, and
with the Maryland and District of Columbia Public Service
Commissions on April 8, 1996.
On April 16, 1997, FERC announced its finding that the
proposed Merger would be in the public interest and approved the
transaction without conditions. FERC held that the Merger would
not adversely affect competition in the long- or short-term
wholesale capacity markets. In addition, FERC indicated that
evaluation of the effect of the Merger on retail markets would be
left to the Maryland and District of Columbia Public Service
Commissions.
Also on April 16, 1997, the Maryland Public Service
Commission unanimously approved the proposed Merger and ordered
Constellation Energy to reduce rates by $56 million ($44 million
for BGE and $12 million for PEPCO), beginning on the effective
19
date of the Merger, with base rates to be frozen for three years
thereafter. The reductions are premised on an 11.4% return on
equity (ROE). In addition, the Commission ordered that 50% of
earnings above an 11.4% ROE be used to further reduce customer
rates.
The Company and BGE believe that the Maryland Order contains
elements that must be revised for the Merger to take place. The
two companies proposed a regulatory plan designed to share Merger
benefits equitably between shareholders and customers. In
addition to ordering the rate decrease, the Order also denies the
two companies the opportunity to recover the full costs for
purchased power contracts previously approved by the Commission.
The Maryland Order would put in place a plan that would eliminate
any reasonable opportunity for shareholders to share in the
benefits.
On May 2, 1997, the companies filed a request for
reconsideration of the Maryland Order. In the request, the
companies detailed areas of the Order that need to be revised for
the Merger to proceed and proposed a modified plan to address
these concerns. Highlights of this modified plan include: (1) a
$26 million rate reduction for Constellation Energy's Maryland
customers upon completion of the Merger, followed by a four-year
base-rate freeze; (2) a comprehensive surcharge that permits full
cost recovery of power purchase contracts the Commission had
previously approved; (3) a synergy sharing mechanism premised on
an 11.9% ROE that splits Merger benefits on a 50/50 basis between
customers and investors, allowing further customer rate
reductions if the new company's operations result in additional
savings; and (4) an opportunity for recovery of Merger costs over
the four-year, base-rate freeze period via the synergy sharing
mechanism. Under this proposal, Constellation Energy would write
off Merger costs in the year the Merger is consummated. There
can be no assurance that the Commission will grant the request
for reconsideration or that the Commission's Order will be
changed. On May 1, 1997, the International Brotherhood of
Electrical Workers, Local 1900, filed an appeal of the Maryland
Commission's decision with the Circuit Court of Baltimore County.
The District of Columbia Commission conducted hearings on the
proposed Merger in February and March 1997. The case was placed
before the District of Columbia Commission for decision in March
1997.
The Company is unable to predict when final decisions will
be reached by the Maryland and District of Columbia Public
Service Commissions or the Circuit Court of Baltimore County.
The Merger will not proceed unless the regulatory approvals
conform to the fundamental requirement that shareholders have a
reasonable opportunity to share in the expected benefits of the
Merger.
20
The waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act was terminated on January 29, 1997. The Nuclear
Regulatory Commission has approved the transfer of BGE's
ownership interest in the operating licenses for the two
generating units at the Calvert Cliffs Nuclear Power Plant to
Constellation Energy at the effective time of the Merger. In
addition, the State Corporation Commission in Virginia has
approved the Merger. The Merger also requires approval from the
Pennsylvania Public Utility Commission.
If the Merger Agreement is terminated by either the Company
or BGE due to a material breach by the other party, the breaching
party must pay the non-breaching party, as liquidated damages,
$10 million in cash in respect of out-of-pocket expenses. The
Merger Agreement also requires payment of a termination fee of
$75 million in cash, plus $10 million in cash in respect of out-
of-pocket expenses, by one party to the other if the Merger
Agreement is terminated under certain circumstances including, if
either the Company or BGE terminates the Merger Agreement after
the Board of Directors of the other party withdraws or adversely
modifies its recommendation of the transaction. The termination
fees payable by the Company under these provisions and the
aggregate amount which could be payable by the Company upon a
required repurchase of an option (or shares of common stock
issued pursuant to the exercise of the option) granted by the
Company to BGE in connection with entry into the Merger Agreement
may not exceed $125 million in the aggregate.
The Company has approved, in conjunction with the Merger
with BGE, a severance plan for all exempt and non-bargaining unit
employees who are not offered a position in Constellation Energy.
Such employees will receive two weeks of pay per year of service,
with a minimum payment of eight weeks of pay. In addition,
employees will receive company-sponsored health and dental
insurance for two weeks per year of service, with a minimum of
eight weeks of insurance coverage; employees will also not be
obligated to reimburse the Company for tuition payments made by
the Company on their behalf within two years of termination.
An extension of the current 1993 Labor Agreement between the
Company and Local 1900 of the International Brotherhood of
Electrical Workers was ratified by the Union members in December
1995. The 1995 Agreement extends the 1993 Agreement, which was
due to expire on June 1, 1996, for two years or until the
effective date of the Merger with BGE, whichever occurs first.
This Agreement provides severance benefits, previously approved
by the Company for exempt and non-bargaining unit employees, for
all union members and provided for a lump-sum payment of 2% of
base pay on January 5, 1996, a lump-sum payment of 1% of base pay
on June 7, 1996, and a lump-sum payment of 3% of base pay on June
6, 1997, or the effective date of the Merger, whichever occurs
first.
21
On March 31, 1997, the Company signed a contract to purchase
land in downtown Washington, D.C. to build a $90 million regional
headquarters for Constellation Energy.
Environmental Contingencies
- ---------------------------
As discussed in the 1996 Form 10-K, the Company received
notice in December 1995 from the U.S. Environmental Protection
Agency (EPA) that it is a Potentially Responsible Party (PRP)
under the Comprehensive Environmental Response Compensation and
Liability Act (CERCLA or Superfund) with respect to the release
or threatened release of radioactive and mixed radioactive and
hazardous wastes at a site in Denver, Colorado, operated by RAMP
Industries, Inc. Evidence indicates that the Company's
connection to the site arises from an agreement with a vendor to
package, transport and dispose of two laboratory instruments
containing small amounts of radioactive material at a Nevada
facility. While the Company cannot predict its liability at this
site, the Company believes that it will not have a material
adverse effect on its financial position or results of
operations.
As discussed in the 1996 Form 10-K, the Company received
notice from the EPA in October 1995 that it, along with several
hundred other companies, may be a PRP in connection with the
Spectron Superfund Site located in Elkton, Maryland. The site
was operated as a hazardous waste disposal, recycling, and
processing facility from 1961 to 1988. A group of PRPs allege,
based on records they have collected, that the Company's share of
liability at this site is .0042%. The EPA has also indicated
that a de minimis settlement is likely to be appropriate for this
site. While the outcome of negotiations and the ultimate
liability with respect to this site cannot be predicted, the
Company believes that its liability at this site will not have a
material adverse effect on its financial position or results of
operations.
As also discussed in the 1996 Form 10-K, a Remedial
Investigation/Feasibility Study (RI/FS) report was submitted to
the EPA in October 1994, with respect to a site in Philadelphia,
Pennsylvania. Pursuant to an agreement among the PRPs, the
Company is responsible for 12% of the costs of the RI/FS. Total
costs of the RI/FS and associated activities prior to the
issuance of a Record of Decision (ROD) by the EPA, including
legal fees, are currently estimated to be $7.5 million. The
Company has paid $.9 million as of March 31, 1997. The report
included a number of possible remedies, the estimated costs of
which range from $2 million to $90 million. In July 1995, the
EPA announced its proposed remedial action plan for the site and
indicated it will accept comments on the plan from any interested
parties. The EPA's estimate of the costs associated with
implementation of the plan is approximately $17 million. The
22
Company cannot predict whether the EPA will include the plan in
its ROD as proposed or make changes as a result of comments
received. In addition, the Company cannot estimate the total
extent of the EPA's administrative and oversight costs. To date,
the Company has accrued $1.7 million for its share of this
contingency.
As also discussed in the 1996 Form 10-K, during 1993 the
Company was served with Amended Complaints filed in three
jurisdictions (Prince George's County, Baltimore City and
Baltimore County), in separate ongoing, consolidated proceedings
each denominated "In re: Personal Injury Asbestos Case." The
Company (and other defendants) were brought into these cases on a
theory of premises liability under which plaintiffs argue that
the Company was negligent in not providing a safe work
environment for employees of its contractors who allegedly were
exposed to asbestos while working on the Company's property.
Initially, a total of approximately 448 individual plaintiffs
added the Company to their Complaints. While the pleadings are
not entirely clear, it appears that each plaintiff seeks $2
million in compensatory damages and $4 million in punitive
damages from each defendant.
In a related proceeding in the Baltimore City case, the
Company was served, in September 1993, with a third party
complaint by Owens Corning Fiberglass, Inc. (Owens Corning)
alleging that Owens Corning was in the process of settling
approximately 700 individual asbestos-related cases and seeking a
judgment for contribution against the Company on the same theory
of alleged negligence set forth above in the plaintiffs' case.
Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed
a third-party complaint against the Company, seeking contribution
for the same plaintiffs involved in the Owens Corning third-party
complaint. Since the initial filings in 1993, approximately 50
individual suits have been filed against the Company. The third
party complaints involving Pittsburgh Corning and Owens Corning
were dismissed by the Baltimore City Court during 1994 without
any payment by the Company. In 1995 and 1996, approximately 400
of the individual plaintiffs have dismissed their claims against
the Company. No payments were made by the Company in connection
with the dismissals. While the aggregate amount specified in the
remaining suits would exceed $400 million, the Company believes
the amounts are greatly exaggerated as were the claims already
disposed of. The amount of total liability, if any, and any
related insurance recovery cannot be precisely determined at this
time; however, based on information and relevant circumstances
known at this time, the Company does not believe these suits will
have a material adverse effect on its financial position.
However, an unfavorable decision rendered against the Company
could have a material adverse effect on results of operations in
the fiscal year in which a decision is rendered.
23
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.
* * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *
The information furnished in the accompanying Consolidated
Statements of Earnings and Retained Income, Consolidated Balance
Sheets and Consolidated Statements of Cash Flows reflects all
adjustments (which consist only of normal recurring accruals)
which are, in the opinion of management, necessary to a fair
presentation of the results of operations for the interim
periods. The accompanying consolidated financial statements and
notes thereto should be read in conjunction with the consolidated
financial statements and notes included in the Company's 1996
Annual Report to the Securities and Exchange Commission on Form
10-K.
* * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *
This Quarterly Report on Form 10-Q, including the report of
Price Waterhouse LLP (on page 25) will automatically be
incorporated by reference in the Prospectuses constituting part
of the Company's Registration Statements on Forms S-3
(Registration Nos. 33-58810 and 33-61379) and Forms S-8
(Registration Nos. 33-36798, 33-53685 and 33-54197), in the Joint
Proxy Statement/Prospectus constituting part of the Registration
Statement on Form S-4 (Number 33-64799) of Constellation Energy
Corporation and in the Prospectuses constituting parts of the
Registration Statements on Form S-3 (333-24705 and 333-24855) of
Constellation Energy Corporation filed under the Securities Act
of 1933. Such report of Price Waterhouse LLP, however, is not a
"report" or "part of the Registration Statement" within the
meaning of Sections 7 and 11 of the Securities Act of 1933 and
the liability provisions of Section 11(a) of such Act do not
apply.
24
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Shareholders of
Potomac Electric Power Company
We have reviewed the accompanying consolidated balance sheets of
Potomac Electric Power Company and consolidated subsidiaries (the
Company) at March 31, 1997 and 1996, and the related consolidated
statements of earnings and retained income for the three and
twelve month periods then ended and the consolidated statements
of cash flows for the three and twelve month periods then ended.
These financial statements are the responsibility of the
Company's management.
We conducted our review in accordance with standards established
by the American Institute of Certified Public Accountants. A
review of interim financial information consists principally of
applying analytical procedures to financial data and making
inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing
standards, the objective of which is the expression of an opinion
regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material
modifications that should be made to the accompanying financial
information for it to be in conformity with generally accepted
accounting principles.
We have previously audited, in accordance with generally accepted
auditing standards, the consolidated balance sheet as of December
31, 1996, and the related consolidated statement of earnings and
consolidated statement of cash flows for the year then ended (not
presented herein); and in our report dated January 17, 1997, we
expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of
December 31, 1996, is fairly stated, in all material respects, in
relation to the consolidated balance sheet from which it has been
derived.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Washington, D.C.
May 14, 1997
25
Part I FINANCIAL INFORMATION
- ------ ---------------------
Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
- ------ ----------------------------------------------------
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
---------------------------------------------
UTILITY
- -------
PROPOSED MERGER UPDATE
- ----------------------
Shareholders of the Company and BGE, at separate special
meetings during March 1996, approved the Merger to form
Constellation Energy.
On April 16, 1997, FERC announced its finding that the
proposed Merger would be in the public interest and approved the
transaction without conditions. FERC held that the Merger would
not adversely affect competition in the long- or short-term
wholesale capacity markets. In addition, FERC indicated that
evaluation of the effect of the Merger on retail markets would be
left to the Maryland and District of Columbia Public Service
Commissions.
Also on April 16, 1997, the Maryland Public Service
Commission unanimously approved the proposed Merger and ordered
Constellation Energy to reduce rates by $56 million ($44 million
for BGE and $12 million for PEPCO), beginning on the effective
date of the Merger, with base rates to be frozen for three years
thereafter. The reductions are premised on an 11.4% return on
equity (ROE). In addition, the Commission ordered that 50% of
earnings above an 11.4% ROE be used to further reduce customer
rates.
The Company and BGE believe that the Maryland Order contains
elements that must be revised for the Merger to take place. The
two companies proposed a regulatory plan designed to share Merger
benefits equitably between shareholders and customers. In
addition to ordering the rate decrease, the Order also denies the
two companies the opportunity to recover the full costs for
purchased power contracts previously approved by the Commission.
The Maryland Order would put in place a plan that would eliminate
any reasonable opportunity for shareholders to share in the
benefits.
On May 2, 1997, the companies filed a request for
reconsideration of the Maryland Order. In the request, the
companies detailed areas of the Order that need to be revised for
the Merger to proceed and proposed a modified plan to address
these concerns. Highlights of this modified plan include: (1) a
$26 million rate reduction for Constellation Energy's Maryland
customers upon completion of the Merger, followed by a four-year
26
base-rate freeze; (2) a comprehensive surcharge that permits full
cost recovery of power purchase contracts the Commission had
previously approved; (3) a synergy sharing mechanism premised on
an 11.9% ROE that splits Merger benefits on a 50/50 basis between
customers and investors, allowing further customer rate
reductions if the new company's operations result in additional
savings; and (4) an opportunity for recovery of Merger costs over
the four-year, base-rate freeze period via the synergy sharing
mechanism. Under this proposal, Constellation Energy would write
off Merger costs in the year the Merger is consummated. There
can be no assurance that the Commission will grant the request
for reconsideration or that the Commission's Order will be
changed. On May 1, 1997, the International Brotherhood of
Electrical Workers, Local 1900, filed an appeal of the Maryland
Commission's decision with the Circuit Court of Baltimore County.
The District of Columbia Commission conducted hearings on the
proposed Merger in February and March 1997. The case was placed
before the District of Columbia Commission for decision in March
1997.
The Company is unable to predict when final decisions will
be reached by the Maryland and District of Columbia Public
Service Commissions or the Circuit Court of Baltimore County.
The Merger will not proceed unless the regulatory approvals
conform to the fundamental requirement that shareholders have a
reasonable opportunity to share in the expected benefits of the
Merger.
The waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act was terminated on January 29, 1997. The Nuclear
Regulatory Commission has approved the transfer of BGE's
ownership interest in the operating licenses for the two
generating units at the Calvert Cliffs Nuclear Power Plant to
Constellation Energy at the effective time of the Merger. In
addition, the State Corporation Commission of Virginia has
approved the Merger. The Merger also requires approval from the
Pennsylvania Public Utility Commission. At March 31, 1997, the
Company has deferred $33.6 million in costs related to the
Merger. If the Merger is not completed, certain Merger related
costs would be written off as a charge against the Company's
results of operations.
See Part I, Item 1, Notes to Consolidated Financial
Statements, (6) Commitments and Contingencies, for additional
information.
27
RESULTS OF OPERATIONS
- ---------------------
TOTAL REVENUE
Total revenue decreased for the three months ended March 31,
1997, as compared to the corresponding period in 1996. The
decrease in revenue from sales of electricity for the three
months ended March 31, 1997, was primarily due to a 4.7% decrease
in kilowatt-hour sales from the corresponding period in 1996.
The decrease in kilowatt-hour sales for the three months ended
March 31, 1997, was primarily attributable to milder than average
winter weather in the first quarter of 1997, as compared to
frigid temperatures during the blizzard-like conditions in the
corresponding period in 1996, which brought a record amount of
snowfall to the Washington, D.C. area. Heating degree days for
the three months ended March 31, 1997, were 22% below the
corresponding period in 1996 and were 15% below the 20-year
average for this period.
Total revenue increased slightly for the twelve months ended
March 31, 1997, as compared to the corresponding period in 1996.
Revenue from sales of electricity for the twelve months ended
March 31, 1997, decreased primarily due to a 2.9% decrease in
kilowatt-hour sales, partially offset by the continued effects of
the August 1996 increase in the DSM surcharge tariff rate in
Maryland and the July 1995 base rate increase in the District of
Columbia. Pursuant to the surcharge tariff, an incentive
provision of $8.9 million was recorded in August 1996 for
achieving specific 1995 energy conservation goals. An incentive
provision of $8.7 million was recorded in June 1995 for achieving
specific 1994 goals. The decrease in kilowatt-hour sales for the
twelve months ended March 31, 1997, was primarily attributable to
the effects of milder than average winter weather during the
first quarter of 1997 and cooler than average summer weather
during 1996. Cooling degree hours for the twelve months ended
March 31, 1997, were 19% below the corresponding period ended in
1996 and 17% below the 20-year average for this period. Also,
heating degree days for the twelve months ended March 31, 1997,
were 16% below the corresponding period in 1996 and 6% below the
20-year average for this period.
Interchange deliveries decreased for the three months and
increased for the twelve months ended March 31, 1997. These
changes principally reflected changes in the level of activity in
purchase-for-resale agreements under the Company's wholesale
power sales tariff. Beginning in January 1997, and pursuant to
FERC's Order No. 888, the Company implemented an open access
transmission tariff and terminated the purchase-for-resale
agreements. Under the new open access transmission tariff, the
Company is receiving revenue from service agreements, classified
as "Other electric revenue", which in the three and twelve months
ended March 31, 1997, aggregated $1.4 million. The benefits
28
derived from interchange deliveries and revenue under the open
access transmission tariff are passed through to the Company's
customers through a fuel adjustment clause.
Recent rate orders received by the Company provided for
changes in annual base rate revenue as shown in the table below:
Rate
(Decrease)
Increase % Effective
Regulatory Jurisdiction ($000) Change Date
- ----------------------- ---------- ------- ---------------
Federal - Wholesale $(2,000) (1.7)% January 1996
District of Columbia 27,900 3.8 July 1995
Federal - Wholesale 2,300 1.8 January 1995
OPERATING EXPENSES
Fuel and purchased energy decreased for the three months
ended and increased for the twelve months ended March 31, 1997,
as compared to the corresponding periods ended March 31, 1996.
Fuel expense decreased for the three and twelve months ended
March 31, 1997, as compared to the corresponding periods in 1996,
primarily as the result of decreases of 17.7% and 14.9%,
respectively, in net generation; partially offset by increases in
the system average fuel cost. The decrease in purchased energy
for the three months ended and increase for the twelve months
ended March 31, 1997, reflects changes in levels and prices of
energy purchased from PJM and other utilities, primarily the
purchases related to the power sales tariff interchange
transactions.
The unit fuel costs for the comparative periods ended March
31, were as follows:
Three Twelve
Months Ended Months Ended
March 31, March 31,
------------ ------------
1997 1996 1997 1996
---- ---- ---- ----
System Average
Fuel Cost per MBTU $1.83 $1.82 $1.80 $1.74
System average unit fuel cost increased for the three and
twelve months ended March 31, 1997, as compared to the
corresponding periods in 1996. The increases were primarily
attributable to an increase in the cost of coal, partially offset
by a decrease in the usage of higher-cost residual oil.
29
For the twelve month periods ended March 31, 1997 and 1996,
the Company obtained 90% and 86%, respectively, of its system
generation from coal based upon percentage of Btus. The
Company's major cycling and certain peaking units can burn either
natural gas or oil, adding flexibility in selecting the most
cost-effective fuel mix.
Capacity purchase payments increased for the three and
twelve months ended March 31, 1997, as compared to the
corresponding periods in 1996. These increases reflect capacity
payments made under the Panda contract, which commenced January
1, 1997, and increases in fixed operating and maintenance expense
associated with the capacity agreements with Ohio Edison and
Allegheny Power System (APS).
Operating expenses other than fuel, purchased energy and
capacity purchase payments decreased for the three months and
increased for the twelve months ended March 31, 1997, as compared
to the corresponding periods in 1996. The decrease for the three
months ended March 31, 1997, was principally due to a decline in
other operating expenses resulting from lower labor costs,
including the effect of the $1.8 million paid to union members on
January 5, 1996, as part of the 1995 Labor Agreement between the
Company and Local 1900 of the International Brotherhood of
Electrical Workers and decreased income taxes due to lower
taxable income, partially offset by increased depreciation and
amortization expense due to additional investment in property and
plant and amortization of increased amounts of conservation costs
associated with the Company's DSM program. The increase for the
twelve months ended March 31, 1997, was principally due to
increased depreciation and amortization expense due to additional
investment in property and plant and amortization of increased
amounts of conservation costs associated with the Company's DSM
program, partially offset by a reduction in other operating
expenses resulting from lower labor costs and a decrease in
income taxes due to lower taxable income.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's investment in property and plant, at original
cost before accumulated depreciation, was $6.3 billion at March
31, 1997, an increase of $24.6 million from the investment at
December 31, 1996, and an increase of $147.2 million from the
investment at March 31, 1996. Cash invested in property and
plant construction, excluding AFUDC and CCRF, amounted to $39.1
million for the three months ended March 31, 1997, and $181.2
million for the twelve months then ended.
30
At March 31, 1997, the Company's capital structure,
excluding short-term debt, long-term debt and serial preferred
stock redemption due within one year, and nonutility subsidiary
debt, consisted of 44.7% long-term debt, 3.3% serial preferred
stock, 3.7% redeemable serial preferred stock and 48.3% common
equity.
Cash from utility operations, after dividends, was $2.1
million for the three months ended March 31, 1997, and $217.8
million for the twelve months then ended as compared with $9.4
million and $87.7 million, respectively, for the same periods
ended March 31, 1996.
Outstanding utility short-term debt totaled $173.5 million
at March 31, 1997, an increase of $42.1 million from the $131.4
million outstanding at December 31, 1996, and an decrease of
$113.4 million from the $286.9 million outstanding at March 31,
1996. See the discussion included in Note (3) of the Notes to
Consolidated Financial Statements, Capitalization, for additional
information.
NEW ACCOUNTING STANDARDS
- ------------------------
See the discussion included in Note (1) of the Notes to
Consolidated Financial Statements, Summary of Significant
Accounting Policies.
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's earnings for the first quarter of 1997 were $13.5
million ($.11 per share) compared to earnings of $2.5 million
($.02 per share) for the same period in 1996. PCI's earnings of
$27.9 million ($.24 per share) for the twelve months ended March
31, 1997, compared to a net loss of $117.6 million ($.99 per
share) for the twelve months ended March 31, 1996. The
improvement in earnings for the three month period ended March
31, 1997, over the corresponding period in 1996 was primarily as
a result of first quarter 1996 writedowns of aircraft held for
disposal and other investments. The improvement in PCI's
earnings for the twelve months ended March 31, 1997, over the
twelve months ended March 31, 1996, was primarily a result of
noncash after-tax charges of $121 million associated with the
implementation of PCI's 1995 plan with respect to the aircraft
leasing business. During the first quarter of 1997, two L-1011
airframes were sold, at book value, from the joint venture which
was formed in the fourth quarter of 1995 to assist PCI with the
disposition and management of certain aircraft. As a result of
joint venture operations for the three months ended March 31,
31
1997, PCI's obligation for previously accrued deferred income
taxes was reduced, resulting in after-tax earnings of $7.4
million after the provision for transaction costs. The remaining
portfolio of assets held for disposal at March 31, 1997, was $5.9
million. In April 1997, PCI sold an additional L-1011 aircraft
from its portfolio of assets held for disposal at its approximate
book value. First quarter results also include capital gains
totaling $3.4 million after-tax related primarily to tender
offers accepted by PCI which reduced the cost basis of its
preferred stock marketable securities portfolio by $90.2 million.
Purchases of preferred stock during the quarter totaled $23.1
million. The cost basis of the marketable securities portfolio
at March 31, 1997, was $308.5 million and market value was $310.5
million.
On December 1, 1996, Canadian Airlines (Canadian)
unilaterally announced a three month suspension of lease payments
to its operating lessors citing an anticipated temporary cash
deficiency in early 1997. PCI has two aircraft on operating
lease to Canadian with a combined book value of $42.2 million at
March 31, 1997. Canadian resumed lease payments to PCI as
scheduled on March 1, 1997. It is expected that Canadian will
repay deferred rents of $1.3 million with accrued interest at the
higher of the prime rate plus 1% or 8.56% be repaid to PCI in six
installments with the final installment due at the time of the
lease terminations in April 2000.
PCI has limited partnership interests in five 30-megawatt
SEGS projects in the Mojave Desert in California and owns 22%,
10%, 19%, 31% and 25% of SEGS projects III through VII,
respectively. During 1996, the lenders to SEGS III and SEGS IV
filed suit against the SEGS III and IV partnerships to restrain
them from making distributions of 1996 profits. Due to the
uncertainty associated with the litigation and the lack of
success in reaching a negotiated settlement with the lenders, PCI
wrote off its investments in SEGS III and IV at year end 1996. A
decision was reached by the Court in late January 1997 in favor
of the partnerships. Thereafter, the lenders immediately issued
new default notices based on alleged maintenance deficiencies,
again delaying the ability of the partners to distribute 1996
partnership profits. The partnerships continue to work toward a
negotiated settlement with the lenders. PCI's current
projections of future distributions from SEGS V, VI and VII
indicate a recovery of its remaining March 31, 1997 investment
balance of $26.7 million.
PCI generates income primarily from its leasing activities
and securities investments. Income from leasing activity, which
includes rental income, gains on asset sales, interest income and
fees totaled $21.1 million and $88.9 million for the three and
twelve months ended March 31, 1997, respectively, compared to
$23.9 million and $104 million for the corresponding periods in
1996. The decrease for the three month period ended March 31,
32
1997, over the corresponding period in 1996 was primarily due to
reduced rental income and the decrease for the twelve month
period ended March 31, 1997, over the corresponding period in
1996 was primarily due to reduced fee income in 1997. PCI's
marketable securities portfolio contributed pretax income of
$11.7 million and $35.4 million for the three and twelve months
ended March 31, 1997, respectively, compared to $10.1 million and
$37 million for the same periods in 1996, which results include
net realized gains of $5.3 million and $7.3 million for the three
and twelve months ended March 31, 1997, compared to $1.6 million
and $1.9 million for the three and twelve months ended March 31,
1996, respectively.
Other income increased by $23.6 million and $36.3 million
for the three and twelve months ended March 31, 1997,
respectively, compared to the same periods in 1996. The increase
is primarily the result of the first quarter 1996 writedowns of
PCI's investments in SEGS, real estate and oil and natural gas.
Included in the twelve months ended March 31, 1997, results is an
$8.8 million gain ($6.7 million after-tax) related to the sale of
PCI's $2.8 million (20%) interest in a Florida-based technology
company during the fourth quarter of 1996. During the three
months ended March 31, 1997, PCI earned $.6 million in net income
from investments made by Pepco Enterprises, Inc. (PEI), a wholly
owned subsidiary with business interests that include
telecommunications, liquefied natural gas storage facilities,
underground cable construction and maintenance services and an
energy management services company. Other income for the three
months ended March 31, 1997, includes $5.3 million in revenue
from PEI activities, and expenses, including income taxes,
includes $4.7 million in PEI related expenses, of which $.5
million is income tax expense.
Expenses, before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $39.3 million and $138.4 million for the three
and twelve months ended March 31, 1997, respectively, compared to
$53.6 million and $353.7 million for the same periods in 1996.
The decreases during the three and twelve months ended March 31,
1997, compared to the same periods in 1996 were primarily due to
the $12.3 million pretax first quarter 1996 writedown of assets
held for disposal and the second quarter 1995 pretax writedown of
$170.1 million related to the implementation of the plan with
respect to the aircraft leasing business. Interest expense
decreased for the three and twelve months ended March 31, 1997,
over the corresponding periods in 1996 as a result of reduced
debt as proceeds from sales of aircraft and marketable securities
have been used to pay down debt. Depreciation and operating
expenses decreased by $25.4 million for the twelve months ended
March 31, 1997, as a result of previously accrued repair and
maintenance expenses during the twelve months ended March 31,
1996.
33
PCI had income tax credits of $13 million and $28.8 million
for the three and twelve months ended March 31, 1997,
respectively, and $38.8 million and $118.2 million for the
corresponding periods in 1996. The decrease in income tax
credits for the three month period 1997 over 1996 was primarily
the result of the deferred tax reversal of $10.1 million during
the first quarter of 1997 compared to $23.5 million in the first
quarter of 1996. The decrease in income tax credits for the
twelve month period ended March 31, 1997, over 1996 was primarily
due to the pretax charge to earnings during the second quarter of
1995 associated with the implementation of PCI's plan with
respect to the aircraft leasing business.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
A $310.5 million securities portfolio at March 31, 1997,
consisting primarily of investment grade preferred stocks,
provides PCI with liquidity and investment flexibility. During
the first quarter of 1997, PCI reduced the cost basis of its
marketable securities portfolio by $67.1 million as the result of
calls and acceptance of tender offers ($90.2 million) offset by
purchases of $23.1 million. PCI's fixed rate portfolio is
sensitive to fluctuations in interest rates. The reduced size of
the preferred stock portfolio lessens the impact of future
fluctuations in interest rates, while still maintaining a
substantial portfolio for liquidity purposes. The proceeds from
the securities activity during the first quarter were used to pay
down short-term debt and acquire short-term investments. During
the first quarter of 1997, PCI received $25.7 million in cash
proceeds from the sale of notes receivable from World Airways
(World) and recorded an after-tax charge to earnings of $.4
million. The sale of the notes further reduces PCI's exposure to
the ongoing credit risk associated with the airline industry as
well as the inherent uncertainty regarding the future value of
the aircraft which secured the repayment of the notes.
PCI's outstanding short-term debt totaled $1 million at
March 31, 1997, a decrease of $50.7 million from the $51.7
million outstanding at December 31, 1996, and a decrease of $72.2
million from the $73.2 million outstanding at March 31, 1996.
During the three and twelve months ended March 31, 1997, long-
term debt repayments totaled $6.8 million and $185.1 million,
respectively. At March 31, 1997, PCI had $236.3 million
available under its Medium-Term Note Program and $400 million of
unused short-term bank credit lines.
34
Part II OTHER INFORMATION
- ------- -----------------
Item 1 LEGAL PROCEEDINGS
- ------ -----------------
See Part I, Item 1, Notes to Consolidated Financial
Statements, (6) Commitments and Contingencies, for information on
various legal proceedings.
Item 5 OTHER INFORMATION
- ------ -----------------
OTHER FINANCING ARRANGEMENTS - Credit Agreements
- ------------------------------------------------
The Company and PCI satisfy their short-term financing
requirements through the sale of commercial promissory notes.
The Company and PCI maintain minimum 100 percent lines of credit
back-up for their outstanding commercial promissory notes. These
lines of credit were unused during 1997 and 1996.
BASE RATE PROCEEDINGS
- ---------------------
Maryland
- --------
Effective August 27, 1996, the Maryland DSM surcharge tariff
was increased, providing approximately $18 million annually in
increased revenue. The surcharge includes provisions for the
recovery of lost revenue, amortization of pre-1996 actual program
expenditures plus the initial amortization of 1996 projected
program costs, a CCRF of 9.46% on unamortized balances and an
incentive of $8.9 million awarded for exceeding 1995 energy
saving goals. Previously, an incentive of $8.7 million was
awarded for exceeding 1994 energy saving goals. Maryland DSM
program goals for 1996 have been reduced to reflect lower DSM
expenditures. Consequently, the performance bonus in 1997 is
expected to be significantly lower than amounts awarded for
performance in prior years.
On November 8, 1996, the Company filed a request with the
Maryland Public Service Commission for approval of a purchased
capacity surcharge, which is designed to recover changes in the
level of purchased capacity costs from levels included in base
rates. The filing was made to recover capacity payments under a
contract with Panda Brandywine L.P. (Panda) for a 230-megawatt
gas-fueled combined-cycle cogeneration project in Prince George's
County, Maryland. Capacity payments commenced in January 1997
and are estimated to total approximately $20 million for the
year, of which the Maryland portion is $10.5 million. In
connection with its Order approving the proposed Merger, the
Maryland Commission denied the surcharge. As stated previously,
35
on May 2, 1997, the Company and BGE filed a request for
reconsideration of the Order in which the denial of the recovery
of the costs associated with Panda capacity was included. (See
Part I, Item 1, Notes to Consolidated Financial Statements, (6)
Commitments and Contingencies, for additional information.) 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 Formal Case No. 939, the Commission, in June 1995,
authorized a $27.9 million, or 3.8%, increase in base rate
revenue effective July 1995. The authorized rates are based on a
9.09% rate of return on average rate base, including an 11.1%
return on common stock equity and a capital structure which
excludes short-term debt. In addition, the Commission approved
the Company's Least-Cost Plan filed in June 1994. A four-year
DSM spending cap for the period 1995-1998 was approved,
consistent with the Company's proposal to narrow the scope of DSM
activities by discontinuing operation of certain DSM programs and
by reducing expenditures on the remaining programs. This will
enable the Company to implement cost-effective DSM programs while
limiting the impact of such programs on the price of electricity.
An Environmental Cost Recovery Rider (ECRR) was approved to
provide for full cost recovery of actual DSM program
expenditures, through a billing surcharge. Costs will be
amortized over 10 years, with a return on unamortized amounts by
means of a CCRF computed at the authorized rate of return. The
initial rate, which reflects actual costs expended from July 1993
through December 1994, resulted in additional annual revenue of
approximately $15 million. Although the Commission denied the
Company's request to recover "lost revenue" due to DSM programs,
through a surcharge, a process has been established whereby the
Company can seek recovery of lost revenue in a separate
proceeding. The Commission also increased the time period for
filing Least-Cost Planning cases from two to three years. The
Company, in June 1996, filed an Application for Authority with
the Commission to revise its ECRR. The proposed rate, which
reflects actual costs expended during 1995, is expected to
increase annual revenue by approximately $8 million. No action
has been taken by the District of Columbia Public Service
Commission on the revised ECRR. Subsequent rate updates are
scheduled to be filed annually on June 1 to reflect the prior
year's actual costs, subject to the annual surcharge recovery
limit within the four-year spending cap for the period 1995-1998
(amounts spent in excess of the annual surcharge recovery limit,
but within the four-year spending cap, are deferred for future
recovery). Remaining allowable expenditures under the spending
cap totaled $14.2 million at March 31, 1997. Pre-July 1993 DSM
costs receive base rate treatment.
36
Federal - Wholesale
- -------------------
The Company has a 10-year full service power supply contract
with Southern Maryland Electric Cooperative, Inc. (SMECO), a
wholesale customer. The contract period is to be extended for an
additional year on January 1 of each year, unless notice is given
by either party of termination of the contract at the end of the
10-year period. The full service obligation can be reduced by
SMECO by up to 20% of its annual requirements with a five-year
advance notice for each such reduction.
Pursuant to an agreement for the years 1996 through 1998,
SMECO rates were reduced by $2 million effective January 1, 1996,
with an additional $2.5 million rate reduction scheduled to
become effective January 1, 1998. SMECO has agreed not to give
the Company a notice of reduction or termination of service prior
to December 15, 1998.
Federal - Interchange and Purchased Energy
- ------------------------------------------
The Company's generating and transmission facilities are
interconnected with those of other members of the Pennsylvania-
New Jersey-Maryland Interconnection Association (PJM) power pool
and other utilities. Historically, the pricing of most PJM-
dispatched internal economy energy transactions was based upon
"split savings" whereby such energy was priced halfway between
the cost that the purchaser would incur if the energy were
supplied by its own sources and the cost of production to the
company actually supplying the energy. On April 1, 1997, PJM
members implemented an interim restructuring plan which provides
for poolwide transmission service under a pool tariff and a bid-
price based energy market whereby all energy that clears through
the market will be priced at the margin. Prior to this plan, the
Company, since July 1996, was providing transmission service with
its open access tariff in compliance with FERC Order No. 888. On
February 28, 1997, the FERC ordered the PJM member companies to
implement a poolwide open access transmission tariff based on a
proposal made by PJM supporting companies in December 1996. From
this point forward, all transmission service in PJM would be
administered by the PJM Interconnection Office. In the initial
phase of this plan, bids would be based on cost. Bilateral
transactions would also be permitted. The restructured PJM is
now a Limited Liability Corporation governed by an independent
board of directors with membership open to eligible entities.
In addition to interchange with PJM, the Company is actively
participating in the emerging bilateral energy sales marketplace.
The Company's wholesale power sales tariff allows both sales from
Company-owned generation and sales of energy purchased by the
Company from other market participants. Over 40 utilities and
marketers have executed service agreements allowing them to
37
arrange purchases under this tariff. The Company has also
executed service agreements allowing it to purchase energy under
other market participants' power sales tariffs. These agreements
greatly expand the opportunities for economic transactions.
During the first quarter of 1997, the Company entered into
purchases and sales producing approximately $1.5 million in
savings that were passed along to customers.
The Company continues to purchase energy from Ohio Edison
under the Company's 1987 long-term capacity purchase agreements
with Ohio Edison and APS, and from the Northeast Maryland Waste
Disposal Authority under an avoided cost-based purchase agreement
for a 32-megawatt Montgomery County Resource Recovery Facility.
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.
Capacity payments for the Montgomery County Resource Recovery
facility are not expected to commence until after the year 2000.
In August 1996, the Company began purchasing energy from the
Panda facility, pursuant to a 25-year power purchase agreement
for 230 megawatts of capacity supplied by a gas-fueled combined-
cycle cogenerator. The Panda facility achieved full commercial
operation in October 1996. Capacity payments under this
agreement commenced in January 1997. The capacity expense under
these agreements, including an allocation of a portion of Ohio
Edison's fixed operating and maintenance costs, was $34.6 million
for the three months ended March 31, 1997, and is estimated at
$141 million in 1997. Commitments under these agreements are
estimated at $139 million in 1998, $200 million in 1999 and 2000,
$211 million in 2001 and $212 million in 2002.
The Company has a purchase agreement with Southern Maryland
Electric Cooperative, Inc. (SMECO), through 2015, for 84
megawatts of capacity supplied by a combustion turbine installed
and owned by SMECO at the Company's Chalk Point Generating
Station. The Company is responsible for all costs associated
with operating and maintaining the facility. The capacity
payment to SMECO is approximately $5.5 million per year. The
Company is also selling capacity to PECO Energy (PECO) in the
amount of 100 megawatts per month for the period of January
through May 1997. In addition, on April 24, 1997, the Company
signed an agreement to sell capacity to Delmarva Power & Light
Co. in the amount of 100 megawatts per month for the period June
1, 1997, through May 31, 1998.
RESTRUCTURING OF THE BULK POWER MARKET
- --------------------------------------
In April 1996, the FERC issued its Final Rulemaking Orders
No. 888 and No. 889. Both rulemakings address achieving greater
competition in the wholesale energy market. Order No. 888
required utilities to file open access transmission tariffs by
July 9, 1996. Such filing was made by the Company and was
38
accepted by the FERC. Order No. 889 requires utilities to
establish or participate in an Open Access Same-Time Information
System (OASIS) which requires transmission owners to post certain
transmission availability, pricing and service information on an
open-access communications medium such as the Internet. On
January 3, 1997, the Company's OASIS became operational and is
accessible through the PJM OASIS on the Internet. Order No. 889
also required the Company to establish a code of conduct that
complies with FERC's prescribed standards in order to separate
utilities' transmission system operations and wholesale marketing
functions. The Company's filed code of conduct became effective
on January 3, 1997.
PJM has many years of experience in providing economically
efficient transmission and generation services throughout the
mid-Atlantic region, and has achieved for its members, including
the Company, significant cost savings through shared generating
reserves and integrated operations. In order to meet the FERC's
goals, the PJM members plan to implement significant market-
oriented changes in 1997, which will support broader market
participation and achieve even greater efficiencies. The PJM
members are working to transform today's coordinated cost-based
pool dispatch into a vigorous price-based regional energy market
operating under a standard of transmission service comparability.
On July 24, 1996, nine of the 10 PJM member companies (the
Supporting Companies), excluding PECO, filed, with the FERC, a
comprehensive proposal including the contracts and tariff that
would establish an Independent System Operator (ISO) to
administer transmission service under a PJM control area
transmission tariff and operate the energy market in a manner
that assures comparable treatment for all participants. Under
the Supporting Companies' proposal, reliability of the pool will
be maintained under an installed capacity obligation. The ISO
will administer a bid-priced energy spot market that will also
accommodate bilateral transactions, and the ISO will provide
transmission service on a poolwide basis. In early August 1996,
PECO filed a competing plan opposing certain key features of the
Supporting Companies' proposal.
On November 13, 1996, the FERC found that it could not
accept either the Supporting Companies' proposal or PECO's
opposing proposal. Consequently, FERC ordered the PJM members to
amend its proposals to comport with Order No. 888 on ISOs and to
attempt to reach a consensus with other stakeholders. At a
minimum, FERC ordered that PJM file a poolwide pro forma open
access transmission tariff by December 31, 1996, and amend
existing PJM pooling agreements for compatibility with the Order.
On December 31, 1996, the PJM member companies filed a joint
response to FERC's Order. This compliance filing established a
single poolwide transmission tariff and modified the membership
and governance provisions of the PJM Agreement. The PJM members
39
noted areas of disagreement in the filing and indicated that the
compliance filing was an interim solution until a more
comprehensive proposal could be developed.
On February 28, 1997, the FERC ruled on areas of
disagreement between the PJM members and ordered that PJM
implement an open access transmission tariff and a bid-based
energy market by March 1, 1997. A new PJM Operating Agreement
was filed on March 31, 1997 superseding the original PJM
Agreement. This Agreement opens PJM's membership to eligible
entities. PJM formed a Limited Liability Corporation on
March 31, 1997. The members elected an independent board of
directors to govern the PJM Interconnection Office. The PJM
members subsequently moved the implementation date to April 1,
1997. Through mid-1997, the PJM stakeholders are expected to
continue development of an Independent System Operator. These
changes are not expected to have a material effect on the
operating results of the Company.
COMPETITION
- -----------
The electric utility industry is subject to increasing
competitive pressures, stemming from a combination of increasing
independent power production and regulatory and legislative
initiatives intended to increase bulk power competition,
including the Energy Policy Act of 1992. Since the early 1980s,
the Company has pursued strategies which achieve financial
flexibility through conservation and 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.
Pursuant to an August 1995 order in a generic proceeding
dealing with electric industry structure and the advent of
competition, the Maryland Public Service Commission found that
competition at the wholesale level holds the greatest potential
for producing significant benefits, while competition at the
retail level would carry many potential problems and difficult-
to-find solutions. The Commission stated that it was intrigued
by a restructuring concept suggested by the Company, which calls
for functionally dividing the utility into generation and
transmission/distribution segments. The Commission encouraged
the Company to develop the concept further and suggested that
other electric utilities in the state develop similar proposals
specific to their competitive positions. In October 1996, the
Maryland Commission reopened a generic proceeding to review
regulatory and competitive issues affecting the electricity
40
industry. The Commission cited the evolving nature of the
electric industry as the basis for continuing its investigation.
As part of this investigation, the Commission directed its Staff
to submit a report on or before May 31, 1997, containing, among
other things, recommendations regarding regulatory and
competitive issues facing the electric industry in Maryland. The
Commission also directed the four major electric utilities in
Maryland to prepare unbundled cost studies and model unbundled
retail service tariffs prior to August 1, 1997. The District of
Columbia Public Service Commission initiated a proceeding to
investigate issues regarding electricity industry structure and
competition in late 1995. In September 1996, the Commission
issued an order designating the issues to be examined in the
proceeding. Initial comments regarding the designated issues
were filed with the Commission in January 1997, and reply
comments were filed in March 1997.
PEAK LOAD, SALES, CONSERVATION, AND CONSTRUCTION
- ------------------------------------------------
AND GENERATING CAPACITY
-----------------------
Peak Load and Sales Data
- ------------------------
Kilowatt-hour sales decreased 4.7% and 2.9%, for the three
and twelve months ended March 31, 1997, respectively, as compared
to sales for the corresponding periods in 1996. The decreases in
sales were primarily attributable to milder than average winter
weather in the first quarter of 1997, as compared to the
blizzard-like conditions in the corresponding period in 1996.
The decline in sales for the twelve months ended March 31, 1997,
was also affected by cooler than average summer weather in 1996.
Heating degree days for the three and twelve months ended March
31, 1997, were 22% and 16%, respectively, below the corresponding
period in 1996 and 15% and 6%, respectively, below the 20-year
averages. 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 1996 summer peak demand of 5,288 megawatts occurred on
June 17, 1996. This compares with the 1995 summer peak demand of
5,732 megawatts, and the all-time summer peak demand of 5,769
megawatts which occurred in July 1991. The Company's present
generation capability, including capacity purchase contracts, is
6,716 megawatts. To meet the 1996 summer peak demand, the
Company had approximately 265 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 1.5%,
reflecting continuing success with demand side management (DSM)
and energy use management (EUM) programs and anticipated service
41
area growth trends. The 1996-1997 winter season peak demand of
4,632 megawatts was 7.5% below the all-time winter peak demand of
5,010 megawatts which was established in January 1994.
Conservation
- ------------
The Company's DSM and EUM programs are designed to curb
growth in demand in order to defer the need for construction of
additional generating capacity and to cost-effectively increase
the efficiency of energy use. To reduce the near-term upward
pressure on customer rates and bills, the Company has, since
1994, phased out several conservation programs and reduced rebate
levels for others. By narrowing its conservation offerings and
limiting conservation spending, the Company expects to continue
to encourage its customers to use energy efficiently without
significantly increasing electricity prices.
In Maryland, the Company invested approximately $5.5 million
and $28.5 million in DSM programs for the three and twelve months
ended March 31, 1997, respectively. The Company recovers the
costs of Maryland DSM programs through a base rate surcharge
which amortizes costs over a five-year period and permits the
Company to earn a return on its conservation investment while
receiving compensation for lost revenue. In addition, when the
Company's performance exceeds its annual goals, the Company earns
a performance bonus. The Company was awarded a bonus of $8.9
million in 1996, based on 1995 performance, which followed a
bonus of $8.7 million in 1995, based on 1994 performance.
Maryland DSM program goals for 1996 were reduced to reflect lower
DSM expenditures. Consequently, the performance bonus in 1997 is
expected to be significantly lower than amounts awarded for
performance in prior years. Investment in District of Columbia
DSM programs totaled approximately $.8 million and $11.8 million
for the three and twelve months ended March 31, 1997,
respectively. These DSM costs are amortized over 10 years with
an accrued return on unamortized costs.
It is estimated that peak load reductions of over 700
megawatts have been achieved to date from DSM and EUM programs
and that additional peak load reductions of approximately 400
megawatts will be achieved in the next five years. The Company
also estimates that, in 1996, energy savings of more than 1.6
billion kilowatt-hours were realized through operation of its DSM
and EUM programs. See the discussions included in Summary of
Significant Accounting Policies, Total Revenue, and Base Rate
Proceedings, for additional information.
42
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC and CCRF, are
projected to total $1.2 billion for the five-year period 1997
through 2001, which includes $18 million of estimated Clean Air
Act (CAA) expenditures. In 1997, construction expenditures are
projected to total $215 million, which includes $4 million of
estimated CAA expenditures. The Company plans to finance its
construction program primarily through funds provided by
operations. Actual construction expenditures during the period
1997 through 2001 may vary from projections once the Merger with
BGE becomes effective.
The Company has implemented cost-effective plans for
complying with Phase I of the Acid Rain portion of the CAA which
requires the reduction of sulfur dioxide and nitrogen oxides
emissions to achieve prescribed standards. Boiler burner
equipment for nitrogen oxides emissions control has been replaced
and the use of lower-sulfur coal has been instituted at the
Company's Phase I affected stations, Chalk Point and Morgantown.
Anticipated capital expenditures for complying with the second
phase of the CAA total $18 million over the next five years.
Plans for complying with the second phase of the CAA are being
reviewed in anticipation of the pending Merger with BGE. If
economical, continued use of lower-sulfur coal, cofiring with
natural gas and the purchase of sulfur dioxide (SO2) emission
allowances is expected. Nitrogen oxides emissions reductions
will be achieved by installing control equipment in the most
cost-effective manner after considering the characteristics of
each of the merged company's boilers. In addition to the Acid
Rain portion of the CAA, the State of Maryland and District of
Columbia are required, by Title I of the CAA, to achieve
compliance with ambient air quality standards for ground-level
ozone. This provision is likely to result in further nitrogen
oxides emissions reductions from the Company's boilers; however,
the extent of reductions and associated cost cannot be estimated
at this time.
A 32-megawatt municipally financed resource recovery
facility in Montgomery County, Maryland, began commercial
operation in August 1995. The Company has been purchasing energy
under the agreement covering this project without capacity
payment obligations, which are not expected to commence until
after the year 2000. In addition, the Company has a 25-year
agreement with Panda for a 230-megawatt gas-fueled combined-cycle
cogeneration project in Prince George's County, Maryland. The
Panda facility achieved full commercial operation in October
1996. The Company projects that existing contracts for
nonutility generation and the Company's commitment to
conservation will provide adequate reserve margins to meet
customers' needs well beyond the year 2000. In 1995, the
Maryland Public Service Commission issued an order that requires
43
electric utilities to competitively procure future capacity
resources. The Company believes that completion of the first
combined-cycle unit at its Station H facility in Dickerson,
Maryland, currently scheduled for 2004, is likely to be the most
cost-effective alternative for the next increment of capacity.
This will add a steam cycle to the two existing combustion
turbine units.
SELECTED NONUTILITY SUBSIDIARY FINANCIAL INFORMATION
- ----------------------------------------------------
The Company's wholly owned nonutility subsidiary, Potomac
Capital Investment Corporation (PCI), was organized in late 1983
to provide a permanent vehicle for ongoing nonutility investment
business. The principal assets of PCI are portfolios of
securities and equipment leases, and to a lesser extent real
estate and other investments. The $310.5 million securities
portfolio, consisting primarily of investment grade preferred
stocks, provides PCI with significant liquidity and flexibility
to participate in additional investment opportunities. The
Company's equity investment in PCI was $210.2 million, $196.3
million and $162.7 million, at March 31, 1997, December 31, 1996,
and March 31, 1996, respectively.
44
<TABLE>
Consolidated Statements of Earnings:
- -----------------------------------
<CAPTION>
Three Twelve
Months Ended Months Ended
March 31, March 31,
---------------------- ----------------------
1997 1996 1997 1996
-------- --------- -------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Income
Leasing activities $ 21,115 $ 23,917 $ 88,859 $ 103,956
Marketable securities 11,742 10,058 35,374 37,035
Other 6,950 (16,662) 13,227 (23,072)
-------- --------- -------- ---------
39,807 17,313 137,460 117,919
-------- --------- -------- ---------
Expenses
Interest 19,026 22,129 80,339 91,454
Administrative and general 6,354 5,363 16,520 13,208
Depreciation and operating 13,959 13,795 41,146 66,595
Loss on assets held for
disposal - 12,320 424 182,398
Income tax credit (12,982) (38,762) (28,845) (118,181)
-------- --------- -------- ---------
26,357 14,845 109,584 235,474
-------- --------- -------- ---------
Net earnings (loss) from
nonutility subsidiary $ 13,450 $ 2,468 $ 27,876 $(117,555)<F1>
======== ========= ======== =========
Per share contribution
(reduction) to earnings
of the Company $ .11 $ .02 $ .24 $(.99)<F1>
===== ===== ===== =====
<FN>
<F1>Reflects non-recurring, noncash, after-tax charges of $121 million
($1.03 per share) related to the 1995 plan to dispose of certain
aircraft in its equipment leasing business.
</FN>
45
</TABLE>
<TABLE>
STATISTICAL DATA
- ----------------
<CAPTION>
Three Months Ended Twelve Months Ended
March 31, March 31,
--------------------------------- -------------------------------------
1997 1996 % Change 1997 1996 % Change
-------- -------- -------- ---------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Revenue from Sales
------------------
of Electricity
--------------
(Thousands of Dollars)
Residential $113,809 $126,567 (10.1) $ 536,389 $ 558,555 (4.0)
General Service 208,359 204,728 1.8 1,080,233 1,078,041 0.2
Large Power Service <F1> 7,342 7,194 2.1 35,815 36,088 (0.8)
Street Lighting 3,281 3,190 2.9 12,560 12,403 1.3
Rapid Transit 6,553 6,691 (2.1) 28,569 28,583 -
Wholesale 30,309 34,206 (11.4) 118,252 121,525 (2.7)
-------- -------- ---------- ----------
System $369,653 $382,576 (3.4) $1,811,818 $1,835,195 (1.3)
======== ======== ========== ==========
Energy Sales
------------
(Millions of KWH)
Residential 1,729 1,987 (13.0) 6,624 6,994 (5.3)
General Service 3,655 3,657 (0.1) 15,183 15,522 (2.2)
Large Power Service <F1> 176 176 - 687 708 (3.0)
Street Lighting 46 45 2.2 165 164 0.6
Rapid Transit 100 103 (2.9) 409 415 (1.4)
Wholesale 683 738 (7.5) 2,515 2,557 (1.6)
-------- -------- ---------- ----------
System 6,389 6,706 (4.7) 25,583 26,360 (2.9)
======== ======== ========== ==========
Average System Revenue
----------------------
per KWH (cents per KWH) 5.79 5.70 1.6 7.08 6.96 1.7
-----------------------
System Peak Demand <F2>
------------------
(Thousands of KW)
Summer - - 5,288 5,732
Winter - - 4,632 4,831
Net Generation
--------------
(Millions of KWH) 4,333 5,265 17,109 20,104
Fuel Mix (% of Btu)
-------------------
Coal (%) 92 89 90 86
Oil (%) 7 11 6 7
Gas (%) 1 - 4 7
Fuel Cost per MBtu
------------------
System Average $1.83 $1.82 $1.80 $1.74
Weather Data
------------
Heating Degree Days 1,925 2,466 3,809 4,525
20 Year Average 2,252 4,033
Cooling Degree Hours - - 9,247 11,459
20 Year Average 11 11,109
Heating Degree Days - The daily difference in degrees by which
the mean temperature is below 65 degrees Fahrenheit (dry bulb).
Cooling Degree Hours - The daily sum of the differences, by hours, by
which the temperature (effective temperature) for each hour
exceeds 71 degrees Fahrenheit (effective temperature).
<FN>
<F1> Large Power Service customers are served at a voltage of 66KV or
higher.
<F2> At March 31, 1997, the generation capability, including capacity
purchase contracts, was 6,716 MW.
</FN>
46
</TABLE>
UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL INFORMATION
- ------------------------------------------------------------
The following unaudited pro forma condensed information
combines the historical consolidated balance sheets and
statements of income of Potomac Electric Power Company (PEPCO)
and Baltimore Gas and Electric Company (BGE), including their
respective subsidiaries, after giving effect to the proposed
merger (the Merger) of the two companies into Constellation
Energy Corporation. As previously disclosed, the Merger is
expected to close as soon as all necessary regulatory approvals,
on terms satisfactory to PEPCO and BGE, are obtained. As of the
date of this filing, the Merger has not closed. The unaudited
pro forma combined condensed balance sheet at March 31, 1997,
gives effect to the Merger as if it had occurred at March 31,
1997. The unaudited pro forma combined condensed statement of
income for the three months ended March 31, 1997, gives effect to
the Merger as if it had occurred at January 1, 1997. These
statements are prepared on the basis of accounting for the Merger
as a pooling of interests and are based on the assumptions set
forth in the notes thereto. The registrant, Constellation Energy
Corporation, was formed September 22, 1995, and has no assets or
operations. Therefore, the registrant has no financial
statements and, in turn, there has been no audit of such
statements.
The following pro forma financial information has been
prepared from, and should be read in conjunction with, the
historical consolidated financial statements and related notes
thereto of PEPCO and BGE, which are contained in their respective
1934 Act reports for prior periods. The following information is
not necessarily indicative of the financial position or operating
results that would have occurred if the Merger had been
consummated on the dates, or at the beginning of the periods, for
which the Merger is being given effect nor is it necessarily
indicative of future financial position or operating results.
The following unaudited pro forma combined condensed
financial information of Constellation Energy Corporation is set
forth below:
Balance Sheet as of March 31, 1997
Income Statement for the Three Months Ended March 31, 1997
Notes to Consolidated Financial Statements
The following PEPCO financial information is also set forth
below:
Reclassifying Balance Sheet as of March 31, 1997
Reclassifying Income Statement for the Three Months Ended
March 31, 1997
47
Other Information
- -----------------
Both PEPCO and BGE file annual and quarterly reports with
the Securities and Exchange Commission (SEC). These are
available at the SEC's public reference rooms in Washington, D.C.
and New York, New York (call 1-800-SEC-0330 for more
information); and at the SEC's web site at http://www.sec.gov.
48
<TABLE>
CONSTELLATION ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET
MARCH 31, 1997
(IN THOUSANDS)
----------------------------------------------------
<CAPTION>
PEPCO
BGE (As Reclassified) Pro Forma Pro Forma
(As Reported) (See Note 1) Adjustments Combined
-------------- ----------------- ------------- -------------
<S> <C> <C> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents $ 69,946 $ 54,543 $ - $ 124,489
Accounts Receivable - net 419,719 221,910 - 641,629
Materials and Supplies 153,645 143,269 - 296,914
Prepayments and Other 175,964 21,603 - 197,567
------------- ---------------- ------------ ------------
Total Current Assets 819,274 441,325 - 1,260,599
------------- ---------------- ------------ ------------
Investments and Other Assets
Notes Receivable - 57,226 - 57,226
Real Estate Projects 519,688 72,476 - 592,164
Power Generation Systems 397,815 847 - 398,662
Financial Instruments 127,511 - - 127,511
Marketable Securities 36,943 310,473 - 347,416
Investment in Finance Leases 29,135 493,761 - 522,896
Operating Lease Equipment - net - 188,974 - 188,974
Assets Held for Disposal - 5,900 - 5,900
Other Investments 373,501 112,557 - 486,058
------------- ---------------- ------------ ------------
Total Investments and Other Assets 1,484,593 1,242,214 - 2,726,807
------------- ---------------- ------------ ------------
Utility Plant
Plant in Service
Electric 6,598,858 6,244,707 - 12,843,565
Gas 798,645 - - 798,645
Common 545,019 - - 545,019
------------- ---------------- ------------ ------------
Total Plant in Service 7,942,522 6,244,707 - 14,187,229
Accumulated Depreciation (2,653,844) (1,919,736) - (4,573,580)
------------- ---------------- ------------ ------------
Net Plant in Service 5,288,678 4,324,971 - 9,613,649
Construction Work in Progress 141,813 74,292 - 216,105
Nuclear Fuel - net 123,521 - - 123,521
Other Plant - net 25,470 26,273 - 51,743
------------- ---------------- ------------ ------------
Net Utility Plant 5,579,482 4,425,536 - 10,005,018
------------- ---------------- ------------ ------------
Deferred Charges
Regulatory Assets 488,249 465,953 - 954,202
Other 98,331 181,455 - 279,786
------------- ---------------- ------------ ------------
Total Deferred Charges 586,580 647,408 - 1,233,988
------------- ---------------- ------------ ------------
Total Assets $ 8,469,929 $ 6,756,483 $ - $ 15,226,412
============= ================ ============ ============
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term Borrowings $ 145,685 $ 174,540 $ - $ 320,225
Current Portion of Long-term Debt,
Preferred Stock and Preference Stock 272,954 533,807 - 806,761
Accounts Payable 155,012 211,451 - 366,463
Other 258,629 100,711 - 359,340
------------- ---------------- ------------ ------------
Total Current Liabilities 832,280 1,020,509 - 1,852,789
------------- ---------------- ------------ ------------
Deferred Credits and Other Liabilities
Deferred Income Taxes 1,291,898 1,025,904 - 2,317,802
Capital Lease Obligations - 162,322 - 162,322
Pension and Postemployment Benefits 176,852 - - 176,852
Other 101,851 45,856 - 147,707
------------- ---------------- ------------ ------------
Total Deferred Credits and Other
Liabilities 1,570,601 1,234,082 - 2,804,683
------------- ---------------- ------------ ------------
Capitalization
Long-term Debt 2,862,277 2,374,968 - 5,237,245
Preferred Stock - 267,797 - 267,797
Preference Stock 344,500 - - 344,500
Common Shareholders' Equity 2,860,271 1,859,127 - 4,719,398
------------- ---------------- ------------ ------------
Total Capitalization 6,067,048 4,501,892 - 10,568,940
------------- ---------------- ------------ ------------
Total Liabilities and Capitalization $ 8,469,929 $ 6,756,483 $ - $ 15,226,412
============= ================ ============ ============
<FN>
See accompanying Notes to Unaudited Pro Forma Combined
Condensed Financial Statements.
</FN>
49
</TABLE>
<TABLE>
CONSTELLATION ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED CONDENSED INCOME STATEMENT
THREE MONTHS ENDED MARCH 31, 1997
(In thousands, except per share amounts)
-------------------------------------------------------
<CAPTION>
PEPCO
BGE (As Reclassified) Pro Forma Pro Forma
(As Reported) (See Note 5) Adjustments Combined
------------- ----------------- ------------ -------------
<S> <C> <C> <C> <C>
Revenue
Electric $ 517,297 $ 389,060 $ - $ 906,357
Gas 213,708 - - 213,708
Diversified businesses 156,681 39,807 - 196,488
------------ ----------------- ----------- ------------
Total Revenue 887,686 428,867 - 1,316,553
------------ ----------------- ----------- ------------
Operating Expenses
Electric fuel and purchased energy 135,173 165,525 - 300,698
Gas purchased for resale 133,254 - - 133,254
Operations 131,874 51,836 - 183,710
Maintenance 39,545 21,173 - 60,718
Diversified business expenses 140,080 20,313 - 160,393
Depreciation and amortization 85,599 57,600 - 143,199
Taxes other than income taxes 58,245 45,409 - 103,654
------------ ----------------- ----------- ------------
Total Operating Expenses 723,770 361,856 - 1,085,626
------------ ----------------- ----------- ------------
Income from Operations 163,916 67,011 - 230,927
Total Other Income 963 2,032 - 2,995
------------ ----------------- ----------- ------------
Income Before Interest and Income Taxes 164,879 69,043 - 233,922
Net Interest Expense 53,350 54,062 - 107,412
------------ ----------------- ----------- ------------
Income Before Income Taxes 111,529 14,981 - 126,510
Income Taxes 39,418 (8,001) - 31,417
------------ ----------------- ----------- ------------
Net Income 72,111 22,982 - 95,093
Preferred and Preference Stock Dividends 7,884 4,145 - 12,029
------------ ----------------- ----------- ------------
Earnings Applicable to Common Stock $ 64,227 $ 18,837 $ - $ 83,064
============ ================= =========== ============
Average Shares of Common Stock Outstanding 147,667 118,499 265,811
Earnings Per Share of Common Stock $0.43 $0.16 $0.31
<FN>
See accompanying Notes to Unaudited Pro Forma Combined
Condensed Financial Statements.
</FN>
50
</TABLE>
Notes to Unaudited Pro Forma Combined Condensed Financial
- ---------------------------------------------------------
Statements
- ----------
1. The revenue, expenses, assets, and liabilities of PEPCO's
nonregulated subsidiaries have been reclassified to conform
with the presentation used by BGE. The effect of accounting
policy differences are immaterial and have not been adjusted
in the pro forma combined condensed financial statements.
2. Pro forma per common share amounts give effect to the
conversion of each share of PEPCO and BGE Common Stock into
.997 share and 1 share, respectively, of Constellation Energy
Corporation Common Stock. The pro forma combined condensed
financial statements are presented as if the companies were
combined during all periods included therein.
3. The allocation between PEPCO and BGE and their customers of
the estimated cost savings resulting from the Merger, net of
the costs incurred to achieve such savings, will be subject
to regulatory review and approval. None of these estimated
cost savings, the costs to achieve such savings, or
transaction costs have been reflected in the pro forma
combined condensed financial statements.
4. Intercompany transactions between PEPCO and BGE during the
periods presented were not material and, accordingly, no pro
forma adjustments were made to eliminate such transactions.
5. The PEPCO reclassifying information reflects the
reclassifying entries necessary to adjust PEPCO's
consolidated balance sheet and statement of income
presentation to be consistent with the presentation expected
to be used by Constellation Energy Corporation.
51
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
RECLASSIFYING BALANCE SHEET
MARCH 31, 1997
(In Thousands)
------------------------------
<CAPTION>
PEPCO PEPCO PEPCO
(As Reported) (Reclasses) (As Reclassified)
-------------- -------------- -----------------
<S> <C> <C> <C>
ASSETS
Current Assets
Cash and Cash Equivalents $ 1,263 $ 53,280 $ 54,543
Accounts Receivable - net - 221,910 221,910
Customer Accounts Receivable - net 119,047 (119,047) -
Other Accounts Receivable - net 30,491 (30,491) -
Accrued Unbilled Revenue 62,976 (62,976) -
Materials and Supplies - 143,269 143,269
Fuel 74,243 (74,243) -
Construction and Maintenance 69,026 (69,026) -
Prepayments and Other - 21,603 21,603
Prepaid Taxes 18,004 (18,004) -
Other Prepaid Expenses 3,599 (3,599) -
------------- ------------- ----------------
Total Current Assets 378,649 62,676 441,325
------------- ------------- ----------------
Investments and Other Assets
Notes Receivable - 57,226 57,226
Real Estate Projects - 72,476 72,476
Power Generation Systems - 847 847
Marketable Securities - 310,473 310,473
Investment in Finance Leases - 493,761 493,761
Operating Lease Equipment - net - 188,974 188,974
Assets Held for Disposal - 5,900 5,900
Other Investments - 112,557 112,557
------------- ------------- ----------------
Total Investments and Other Assets - 1,242,214 1,242,214
------------- ------------- ----------------
Utility Plant
Plant in Service
Electric 6,244,707 - 6,244,707
Construction Work in Progress 74,292 (74,292) -
Electric Plant Held for Future Use 4,170 (4,170) -
Nonoperating Property 22,976 (22,976) -
------------- ------------- ----------------
Total Plant in Service 6,346,145 (101,438) 6,244,707
Accumulated Depreciation (1,920,609) 873 (1,919,736)
Construction Work in Progress - 74,292 74,292
Other Plant - net - 26,273 26,273
------------- ------------- ----------------
Net Utility Plant 4,425,536 - 4,425,536
------------- ------------- ----------------
Deferred Charges
Regulatory Assets - 465,953 465,953
Income Taxes Recoverable through Future Rates, net 238,517 (238,517) -
Conservation Costs, net 229,684 (229,684) -
Unamortized Debt Reacquisition Costs 54,851 (54,851) -
Other 168,268 13,187 181,455
------------- ------------- ----------------
Total Deferred Charges 691,320 (43,912) 647,408
------------- ------------- ----------------
Nonutility Subsidiary Assets
Cash and Cash Equivalents 53,280 (53,280) -
Marketable Securities 310,473 (310,473) -
Investment in Finance Leases 493,761 (493,761) -
Operating Lease Equipment - net 188,974 (188,974) -
Assets Held for Disposal 5,900 (5,900) -
Receivables - net 66,622 (66,622) -
Other Investments 185,880 (185,880) -
Other Assets 16,133 (16,133) -
------------- ------------- ----------------
Total Nonutility Subsidiary Assets 1,321,023 (1,321,023) -
------------- ------------- ----------------
Total Assets $ 6,816,528 $ (60,045) $ 6,756,483
============= ============= ================
52
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
RECLASSIFYING BALANCE SHEET
MARCH 31, 1997
(In Thousands)
------------------------------
<CAPTION>
PEPCO PEPCO PEPCO
(As Reported) (Reclasses) (As Reclassified)
-------------- ------------ -----------------
<S> <C> <C> <C>
LIABILITIES AND CAPITALIZATION
Current Liabilities
Short-term Borrowings $ 173,540 $ 1,000 $ 174,540
Current Portion of Long-term Debt and Preferred Stock 200,985 332,822 533,807
Accounts Payable and Accrued Expenses 143,565 67,886 211,451
Capital Lease Obligations Due within One Year 20,772 (20,772) -
Other 79,939 20,772 100,711
------------- ----------- ----------------
Total Current Liabilities 618,801 401,708 1,020,509
------------- ----------- ----------------
Deferred Credits and Other Liabilities
Deferred Income Taxes 986,453 39,451 1,025,904
Deferred Investment Tax Credits 60,045 (60,045) -
Capital Lease Obligations - 162,322 162,322
Other 39,398 6,458 45,856
------------- ----------- ----------------
Total Deferred Credits and Other Liabilities 1,085,896 148,186 1,234,082
------------- ----------- ----------------
Other Noncurrent Liabilities
Capital Lease Obligations 162,322 (162,322) -
------------- ----------- ----------------
Total Other Noncurrent Liabilities 162,322 (162,322) -
------------- ----------- ----------------
Capitalization
Long-term Debt 1,718,310 656,658 2,374,968
Preferred Stock - 267,797 267,797
Serial Preferred Stock 125,297 (125,297) -
Redeemable Serial Preferred Stock 142,500 (142,500) -
Common Shareholders' Equity - 1,859,127 1,859,127
Common Stock 118,497 (118,497) -
Other Common Equity 1,740,630 (1,740,630) -
------------- ----------- ----------------
Total Capitalization 3,845,234 656,658 4,501,892
------------- ----------- ----------------
Nonutility Subsidiary Liabilities
Long-term Debt 989,480 (989,480) -
Short-term Notes Payable 1,000 (1,000) -
Deferred Taxes and Other 113,795 (113,795) -
------------- ----------- ----------------
Total Nonutility Subsidiary Liabilities 1,104,275 (1,104,275) -
------------- ----------- ----------------
Total Liabilities and Capitalization $ 6,816,528 $ (60,045) $ 6,756,483
============= =========== ================
53
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
RECLASSIFYING STATEMENT OF INCOME
THREE MONTHS ENDED MARCH 31, 1997
(In thousands, except per share amounts)
----------------------------------------
<CAPTION>
PEPCO PEPCO PEPCO
(As Reported) (Reclasses) (As Reclassified)
------------- ------------- -----------------
<S> <C> <C> <C>
Revenue
Electric $ 389,060 $ - $ 389,060
Gas - - -
Diversified businesses - 39,807 39,807
------------ ------------ ----------------
Total Revenue 389,060 39,807 428,867
------------ ------------ ----------------
Operating Expenses
Electric fuel and purchased energy - 165,525 165,525
Fuel 78,507 (78,507) -
Purchased energy 51,074 (51,074) -
Capacity purchase payments 35,944 (35,944) -
Gas purchased for resale - - -
Operations 51,836 - 51,836
Maintenance 21,173 - 21,173
Diversified business expenses - 20,313 20,313
Loss on assets held for disposal - - -
Depreciation and amortization 57,600 - 57,600
Income taxes 5,295 (5,295) -
Taxes other than income taxes 45,409 - 45,409
------------ ------------ ----------------
Total Operating Expenses 346,838 15,018 361,856
------------ ------------ ----------------
Income from Operations 42,222 24,789 67,011
------------ ------------ ----------------
Other Income
Nonutility Subsidiary Income 39,807 (39,807) -
Loss on assets held for disposal - - -
Expenses, including interest and income taxes (26,357) 26,357 -
------------ ------------ ----------------
Net earnings from nonutility subsidiary 13,450 (13,450) -
Allowance for other funds used during construction
and capital cost recovery factor 1,660 - 1,660
Other, net 686 (314) 372
------------ ------------ ----------------
Total Other Income 15,796 (13,764) 2,032
------------ ------------ ----------------
Income Before Interest and Income Taxes 58,018 11,025 69,043
------------ ------------ ----------------
Interest Expense
Interest on debt 34,744 - 34,744
Other 2,098 - 2,098
Subsidiary interest expense - 19,026 19,026
Allowance for borrowed funds used during construction
and capital cost recovery factor (1,806) - (1,806)
------------ ------------ ----------------
Net Interest Expense 35,036 19,026 54,062
------------ ------------ ----------------
Income before income taxes 22,982 (8,001) 14,981
------------ ------------ ----------------
Income taxes - Utility - 5,295 5,295
Income taxes - Nonoperating - (314) (314)
Income taxes - Subsidiary - (12,982) (12,982)
------------ ------------ ----------------
Total Income Taxes - (8,001) (8,001)
------------ ------------ ----------------
Net Income 22,982 - 22,982
Preferred Dividends 4,145 4,145
------------ ----------------
Earnings Applicable to Common Stock $ 18,837 $ 18,837
============ ================
Average Shares of Common Stock Outstanding 118,499 118,499
Earnings Per Share of Common Stock $0.16 $0.16
54
</TABLE>
Item 6 EXHIBITS AND REPORTS ON FORM 8-K
- ------ --------------------------------
(a) Exhibits
Exhibit 11 - Computation of Earnings Per Common
Share - filed herewith.
Exhibit 12 - Computation of ratios - filed
herewith.
Exhibit 15 - Letter re unaudited interim
financial information - filed
herewith.
Exhibit 27 - Financial data schedule - filed
herewith.
(b) Reports on Form 8-K
None.
55
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 thereunto duly authorized.
Potomac Electric Power Company
------------------------------
Registrant
By /s/ D. R. Wraase
------------------------------
(D. R. Wraase)
Senior Vice President and
Chief Financial Officer
May 14, 1997
- --------------
DATE
56
<TABLE>
Exhibit 11 Computations of Earnings Per Common Share
- ---------- -----------------------------------------
The following is the basis for the computation of primary and fully
diluted earnings per common share for the twelve months ended March 31, 1997,
and the twelve months ended December 31, 1996 and 1995:
<CAPTION>
March 31, December 31, December 31,
1997 1996 1995
------------- ------------ ------------
<S> <C> <C> <C>
Average shares outstanding for
computation of primary earnings
per common share 118,497,650 118,496,683 118,412,478
============ ============ ============
Average shares outstanding for
fully diluted computation:
Average shares outstanding 118,497,650 118,496,683 118,412,478
Additional shares resulting from:
Conversion of Serial Preferred
Stock, $2.44 Convertible Series
of 1966 (the "Convertible
Preferred Stock") 34,962 34,986 38,255
Conversion of 7% Convertible
Debentures 2,364,559 2,418,579 2,469,639
Conversion of 5% Convertible
Debentures 3,392,500 3,392,500 3,392,500
------------ ------------ ------------
Average shares outstanding for
computation of fully diluted
earnings per common share 124,289,671 124,342,748 124,312,872
============ ============ ============
Earnings applicable to common stock $228,618,000 $220,356,000 $77,540,000
Add: Dividends paid or accrued on
Convertible Preferred Stock 15,000 15,000 16,000
Interest paid or accrued on
Convertible Debentures,
net of related taxes 6,358,000 6,416,000 6,475,000
------------ ------------ ------------
Earnings applicable to common stock,
assuming conversion of convertible
securities $234,991,000 $226,787,000 $84,031,000
============ ============ ============
Primary earnings per common share $1.93 $1.86 $0.65
Fully diluted earnings per common share $1.89 $1.82 $0.68
<FN>
The valuation is not required by footnote 2 to paragraph
14 of APB No. 15 for the the twelve months ended March 31,
1997, and December 31, 1996, because it results in
dilution of less than 3%. In addition, this calculation
is submitted in accordance with Regulation S-K item 601
(b)(11) although it is contrary to paragraph 40 of APB No.
15 because it produces an antidilutive result for the
twelve months ended December 31, 1995.
</FN>
57
</TABLE>
<TABLE>
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 the twelve months ended March
31, 1997, and for each of the preceding five years on the basis of parent
company operations only, are as follows.
<CAPTION>
Twelve
Months For The Year Ended December 31,
Ended ---------------------------------------------------------
Mar. 31,
1997 1996 1995 1994 1993 1992
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $217,332 $220,066 $218,788 $208,074 $216,478 $172,599
Taxes based on income 130,701 135,011 129,439 116,648 107,223 76,965
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 348,033 355,077 348,227 324,722 323,701 249,564
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 146,560 146,939 146,558 139,210 141,393 138,097
Interest factor in rentals 23,409 23,560 23,431 6,300 5,859 6,140
--------- --------- --------- --------- --------- ---------
Total fixed charges 169,969 170,499 169,989 145,510 147,252 144,237
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $518,002 $525,576 $518,216 $470,232 $470,953 $393,801
========= ========= ========= ========= ========= =========
Coverage of fixed charges 3.05 3.08 3.05 3.23 3.20 2.73
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,590 $16,604 $16,851 $16,437 $16,255 $14,392
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.60 1.61 1.59 1.56 1.50 1.45
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $26,544 $26,732 $26,793 $25,642 $24,383 $20,868
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $196,513 $197,231 $196,782 $171,152 $171,635 $165,105
========= ========= ========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 2.64 2.66 2.63 2.75 2.74 2.39
==== ==== ==== ==== ==== ====
58
</TABLE>
<TABLE>
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 the twelve months ended March
31, 1997, and for each of the preceding five years on a fully consolidated
basis, are as follows.
<CAPTION>
Twelve
Months For The Year Ended December 31,
Ended ---------------------------------------------------------
Mar. 31,
1997 1996 1995 1994 1993 1992
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $245,208 $236,960 $94,391 $227,162 $241,579 $200,760
Taxes based on income 101,856 80,386 43,731 93,953 62,145 79,481
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 347,064 317,346 138,122 321,115 303,724 280,241
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 227,500 231,029 238,724 224,514 221,312 226,453
Interest factor in rentals 23,669 23,943 26,685 9,938 9,257 6,599
--------- --------- --------- --------- --------- ---------
Total fixed charges 251,169 254,972 265,409 234,452 230,569 233,052
--------- --------- --------- --------- --------- ---------
Nonutility subsidiary capitalized interest (601) (649) (529) (521) (2,059) (2,200)
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $597,632 $571,669 $403,002 $555,046 $532,234 $511,093
======== ======== ======== ======== ======== ========
Coverage of fixed charges 2.38 2.24 1.52 2.37 2.31 2.19
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,590 $16,604 $16,851 $16,437 $16,255 $14,392
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.42 1.34 1.46 1.41 1.26 1.40
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $23,558 $22,249 $24,602 $23,176 $20,481 $20,149
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $274,727 $277,221 $290,011 $257,628 $251,050 $253,201
======== ======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.18 2.06 1.39 2.15 2.12 2.02
==== ==== ==== ==== ==== ====
59
</TABLE>
Exhibit 15
May 14, 1997
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Ladies and Gentlemen:
We are aware that Potomac Electric Power Company has incorporated
by reference our report dated May 14, 1997, (issued pursuant to
the provisions of Statement on Auditing Standards No. 71) in the
Prospectuses constituting parts of the Registration Statements
(Numbers 33-36798, 33-53685 and 33-54197) on Forms S-8 filed on
September 12, 1990, May 18, 1994 and June 17, 1994, respectively,
and (Numbers 33-58810 and 33-61379) on Forms S-3 filed on
February 26, 1993 and July 28, 1995, respectively, in the Joint
Proxy Statement/Prospectus constituting part of the Registration
Statement (Number 33-64799) on Form S-4 of Constellation Energy
Corporation filed on December 7, 1995, and in the Prospectuses
constituting parts of the Registration Statements on Form S-3
(333-24705 and 333-24855) of Constellation Energy Corporation
filed on April 7, 1997, and April 9, 1997, respectively. We are
also aware of our responsibilities under the Securities Act of
1933.
Very truly yours,
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Washington, D.C.
60
<TABLE> <S> <C>
<ARTICLE> UT
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> MAR-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,403,433
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 378,649
<TOTAL-DEFERRED-CHARGES> 691,320
<OTHER-ASSETS> 1,343,126
<TOTAL-ASSETS> 6,816,528
<COMMON> 118,497
<CAPITAL-SURPLUS-PAID-IN> 1,010,433
<RETAINED-EARNINGS> 730,197
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,859,127
142,500
125,297
<LONG-TERM-DEBT-NET> 1,718,310
<SHORT-TERM-NOTES> 8,090<F1>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 165,450<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 200,000
985
<CAPITAL-LEASE-OBLIGATIONS> 162,322
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,413,675
<TOT-CAPITALIZATION-AND-LIAB> 6,816,528
<GROSS-OPERATING-REVENUE> 389,060
<INCOME-TAX-EXPENSE> 5,295
<OTHER-OPERATING-EXPENSES> 341,543
<TOTAL-OPERATING-EXPENSES> 346,838
<OPERATING-INCOME-LOSS> 42,222
<OTHER-INCOME-NET> 15,796
<INCOME-BEFORE-INTEREST-EXPEN> 58,018
<TOTAL-INTEREST-EXPENSE> 35,036
<NET-INCOME> 22,982
4,145
<EARNINGS-AVAILABLE-FOR-COMM> 18,837
<COMMON-STOCK-DIVIDENDS> 49,148
<TOTAL-INTEREST-ON-BONDS> 132,900<F2>
<CASH-FLOW-OPERATIONS> 75,653
<EPS-PRIMARY> $.16
<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 March 31, 1997.
<F3>No material dilution would occur if all the convertible preferred stock and
debentures were converted into common stock.
</FN>
</TABLE>
