UNITED STATES
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 June 30, 1996
-------------
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 June 30, 1996
- ---------------------------- ----------------------------
Common Stock, $1 par value 118,496,701
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....................................... 9
(3) Capitalization..................................... 12
(4) Fair Value of Financial Instruments................ 14
(5) Marketable Securities.............................. 16
(6) Commitments and Contingencies...................... 18
Report of Independent Accountants on Review of Interim
Financial Information.................................. 23
Item 2 - Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Utility
Proposed Merger Update................................. 24
Results of Operations.................................. 25
Capital Resources and Liquidity........................ 28
Nonutility Subsidiary
Results of Operations.................................. 28
Capital Resources and Liquidity........................ 31
PART II - Other Information
Item 1 - Legal Proceedings................................. 32
Item 5 - Other Information
Other Financing Arrangements............................. 32
Base Rate Proceedings.................................... 32
Restructuring of the Bulk Power Market................... 35
Peak Load, Sales, Conservation, and Construction and
Generating Capacity.................................... 36
Selected Nonutility Subsidiary Financial Information..... 39
Statistical Data......................................... 41
Item 6 - Exhibits and Reports on Form 8-K.................. 42
Signatures................................................. 43
Computation of Earnings Per Common Share................... 44
Computation of Ratios - Parent Company Only................ 45
Computation of Ratios - Fully Consolidated................. 46
Independent Accountants Awareness Letter................... 47
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 Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
-------------------- -------------------- ----------------------
1996 1995 1996 1995 1996 1995
--------- --------- --------- --------- ---------- -----------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Revenue
Sales of electricity $ 461,002 $ 438,842 $ 843,578 $ 800,013 $1,857,355 $1,753,550
Other electric revenue 1,703 1,613 4,399 3,875 9,166 7,597
--------- --------- --------- --------- ---------- ----------
Total Operating Revenue 462,705 440,455 847,977 803,888 1,866,521 1,761,147
Interchange deliveries 39,075 4,904 90,396 6,380 137,686 11,700
--------- --------- --------- --------- ---------- ----------
Total Revenue 501,780 445,359 938,373 810,268 2,004,207 1,772,847
--------- --------- --------- --------- ---------- ----------
Operating Expenses
Fuel 74,805 69,630 167,518 153,171 369,801 328,910
Purchased energy 79,195 45,390 160,497 88,029 266,059 189,514
Capacity purchase payments 32,583 32,085 64,861 64,546 126,085 127,970
Other operation 56,263 53,198 111,982 111,434 224,577 218,495
Maintenance 21,267 21,046 42,694 43,873 91,680 90,949
--------- --------- --------- --------- ---------- ----------
Total Operation and Maintenance 264,113 221,349 547,552 461,053 1,078,202 955,838
Depreciation and amortization 54,675 48,433 110,076 96,093 219,474 190,590
Income taxes 37,808 34,815 45,979 34,394 140,044 110,056
Other taxes 49,841 49,523 95,396 96,671 201,433 204,162
--------- --------- --------- --------- ---------- ----------
Total Operating Expenses 406,437 354,120 799,003 688,211 1,639,153 1,460,646
--------- --------- --------- --------- ---------- ----------
Operating Income 95,343 91,239 139,370 122,057 365,054 312,201
--------- --------- --------- --------- ---------- ----------
Other Income (Loss)
Nonutility Subsidiary
Income 31,783 32,666 49,096 66,551 117,038 146,506
Loss on assets held for disposal - (170,078) - (170,078) - (170,078)
Expenses, including interest
and income taxes (22,736) 21,913 (37,581) (16,346) (110,046) (79,554)
--------- --------- --------- --------- ---------- ----------
Net earnings (loss) from nonutility
subsidiary 9,047 (115,499) 11,515 (119,873) 6,992 (103,126)
Allowance for other funds used during
construction and capital cost recovery factor 1,660 1,488 3,397 2,895 6,657 7,752
Other, net 1,613 622 3,368 1,716 2,334 4,307
--------- --------- --------- --------- ---------- ----------
Total Other Income (Loss) 12,320 (113,389) 18,280 (115,262) 15,983 (91,067)
--------- --------- --------- --------- ---------- ----------
Income (Loss) Before Utility Interest Charges 107,663 (22,150) 157,650 6,795 381,037 221,134
--------- --------- --------- --------- ---------- ----------
Utility Interest Charges
Long-term debt 33,291 32,353 66,725 64,659 133,687 129,222
Other 4,102 5,146 7,889 8,445 14,382 14,591
Allowance for borrowed funds used during
construction and capital cost recovery factor (1,983) (2,811) (3,951) (5,499) (9,220) (10,325)
--------- --------- --------- --------- ---------- ----------
Net Utility Interest Charges 35,410 34,688 70,663 67,605 138,849 133,488
--------- --------- --------- --------- ---------- ----------
Net Income (Loss) 72,253 (56,838) 86,987 (60,810) 242,188 87,646
Dividends on Preferred Stock 4,137 4,234 8,297 8,475 16,673 16,697
--------- --------- --------- --------- ---------- ----------
Earnings (Loss) for Common Stock 68,116 (61,072) 78,690 (69,285) 225,515 70,949
Retained Income at Beginning of Period 695,521 785,792 742,296 830,524 689,475 800,385
Dividends on Common Stock (49,153) (49,118) (98,305) (98,164) (196,610) (196,116)
Subsidiary Marketable Securities Net
Unrealized (Loss) Gain, Net of Tax (2,758) 13,873 (10,955) 26,400 (6,654) 14,257
--------- --------- --------- --------- ---------- ----------
Retained Income at End of Period $ 711,726 $ 689,475 $ 711,726 $ 689,475 $ 711,726 $ 689,475
========= ========= ========= ========= ========== ==========
Average Common Shares
Outstanding (000's) 118,496 118,415 118,496 118,333 118,493 118,215
Earnings (Loss) Per Common Share $0.57 ($0.52) $0.66 ($0.59) $1.90 $0.60
Cash Dividends Per Common Share $0.415 $0.415 $0.83 $0.83 $1.66 $1.66
Book Value Per Share $15.53 $15.35
2
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Balance Sheets
(Unaudited at June 30, 1996 and 1995)
------------------------------------------
<CAPTION>
June 30, December 31, June 30,
ASSETS 1996 1995 1995
------ ------------- ------------- -------------
(Thousands of Dollars)
<S> <C> <C> <C>
Property and Plant - at original cost
Electric plant in service $ 6,141,899 $ 6,041,203 $ 5,921,848
Construction work in progress 69,035 93,047 118,233
Electric plant held for future use 4,115 4,082 4,041
Nonoperating property 22,771 22,771 22,629
------------- ------------- -------------
6,237,820 6,161,103 6,066,751
Accumulated depreciation (1,829,828) (1,760,792) (1,687,219)
------------- ------------- -------------
Net Property and Plant 4,407,992 4,400,311 4,379,532
------------- ------------- -------------
Current Assets
Cash and cash equivalents 6,312 5,844 20,182
Customer accounts receivable, less allowance
for uncollectible accounts of $1,443, $1,669
and $1,950 163,924 137,456 138,591
Other accounts receivable, less allowance for
uncollectible accounts of $300 37,015 36,765 29,705
Accrued unbilled revenue 121,915 73,622 112,459
Prepaid taxes 3,427 36,255 2,833
Other prepaid expenses 11,535 7,562 9,783
Material and supplies - at average cost
Fuel and emission allowances 80,254 63,203 67,207
Construction and maintenance 69,852 70,497 73,904
------------- ------------- -------------
Total Current Assets 494,234 431,204 454,664
------------- ------------- -------------
Deferred Charges
Income taxes recoverable through future rates, net 239,806 244,181 241,376
Conservation costs, net 234,869 230,412 211,246
Unamortized debt reacquisition costs 56,956 58,360 55,430
Other 118,899 138,619 120,109
------------- ------------- -------------
Total Deferred Charges 650,530 671,572 628,161
------------- ------------- -------------
Nonutility Subsidiary Assets
Cash and cash equivalents - 1,594 14,107
Marketable securities 409,194 530,323 514,159
Investment in finance leases 477,813 438,795 336,994
Operating lease equipment, net of accumulated
depreciation of $99,257, $79,275 and $60,643 252,197 272,947 241,481
Assets held for disposal 20,200 104,370 104,370
Receivables, less allowance for uncollectible
accounts of $6,000, $6,000 and $5,000 77,631 74,957 75,698
Other investments 187,201 176,418 189,677
Other assets 15,599 15,659 17,354
------------- ------------- -------------
Total Nonutility Subsidiary Assets 1,439,835 1,615,063 1,493,840
------------- ------------- -------------
Total Assets $ 6,992,591 $ 7,118,150 $ 6,956,197
============= ============= =============
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization
Common stock $ 118,497 $ 118,495 $ 118,486
Other common equity 1,722,167 1,752,817 1,700,068
Serial preferred stock 125,307 125,325 125,401
Redeemable serial preferred stock 142,500 143,485 143,485
Long-term debt 1,718,361 1,817,077 1,703,370
------------- ------------- -------------
Total Capitalization 3,826,832 3,957,199 3,790,810
------------- ------------- -------------
Other Non-Current Liabilities
Capital lease obligations 164,113 165,235 166,304
------------- ------------- -------------
Total Other Non-Current Liabilities 164,113 165,235 166,304
------------- ------------- -------------
Current Liabilities
Long-term debt and preferred stock
redemption due within one year 100,985 26,280 65,000
Short-term debt 327,515 258,465 354,000
Accounts payable and accrued expenses 188,622 162,039 162,229
Capital lease obligations due within one year 20,772 20,772 20,772
Other 82,675 86,034 108,935
------------- ------------- -------------
Total Current Liabilities 720,569 553,590 710,936
------------- ------------- -------------
Deferred Credits
Income taxes 907,032 892,544 863,302
Investment tax credits 62,782 64,607 66,432
Other 37,026 35,089 31,430
------------- ------------- -------------
Total Deferred Credits 1,006,840 992,240 961,164
------------- ------------- -------------
Nonutility Subsidiary Liabilities
Long-term debt 978,911 1,047,484 1,038,053
Short-term notes payable 159,330 223,350 136,000
Deferred taxes and other 135,996 179,052 152,930
------------- ------------- -------------
Total Nonutility Subsidiary Liabilities 1,274,237 1,449,886 1,326,983
------------- ------------- -------------
Total Capitalization and Liabilities $ 6,992,591 $ 7,118,150 $ 6,956,197
============= ============= =============
3
</TABLE>
<TABLE>
POTOMAC ELECTRIC POWER COMPANY
Consolidated Statements of Cash Flows
(Unaudited)
-------------------------------------
<CAPTION>
Six Months Ended Twelve Months Ended
June 30, June 30,
----------------------- -----------------------
1996 1995 1996 1995
--------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Activities
Income from utility operations $ 75,472 $ 59,063 $ 235,196 $ 190,772
Adjustments to reconcile income to net
cash from operating activities:
Depreciation and amortization 110,076 96,093 219,474 190,590
Deferred income taxes and investment tax credits 11,492 19,758 43,508 43,695
Allowance for funds used during construction
and capital cost recovery factor (7,348) (8,394) (15,877) (18,077)
Changes in materials and supplies (16,406) 5,007 (8,995) (6,657)
Changes in accounts receivable and accrued unbilled revenue (75,011) (48,733) (42,099) 22,850
Changes in accounts payable 15,675 (18,919) 20,175 (5,738)
Changes in other current assets and liabilities 41,222 37,265 2,472 (9,601)
Changes in deferred conservation costs (26,965) (62,095) (69,667) (118,647)
Net other operating activities (6,856) (16,710) (35,808) (12,995)
Nonutility subsidiary:
Net earnings (loss) 11,515 (119,873) 6,992 (103,126)
Deferred income taxes (36,287) (70,702) (15,282) (48,769)
Loss on assets held for disposal - 170,078 - 170,078
Changes in other assets and net other operating activities 46,803 50,824 76,066 51,517
--------- --------- --------- ---------
Net Cash From Operating Activities 143,382 92,662 416,155 345,892
--------- --------- --------- ---------
Investing Activities
Total investment in property and plant (91,932) (119,887) (202,721) (266,483)
Allowance for funds used during construction
and capital cost recovery factor 7,348 8,394 15,877 18,077
--------- --------- --------- ---------
Net investment in property and plant (84,584) (111,493) (186,844) (248,406)
Nonutility subsidiary:
Purchase of marketable securities (11,252) (11,321) (35,152) (25,827)
Proceeds from sale or redemption of marketable securities 117,242 15,450 129,638 36,791
Investment in leased equipment (3,056) (7,360) (150,462) (76,457)
Proceeds from sale or disposition of leased equipment 3,658 - 3,658 -
Proceeds from assets held for disposal 29,354 - 29,354 -
Proceeds from sale of assets 285 - 6,251 -
Purchase of other investments (1,996) (2,563) (3,251) (4,161)
Proceeds from sale or distribution of other investments 1,604 14,899 2,319 28,475
Investment in promissory notes (4,388) - (8,922) (542)
Proceeds from promissory notes 7,643 3,541 12,079 6,266
--------- --------- --------- ---------
Net Cash From (Used by) Investing Activities 54,510 (98,847) (201,332) (283,861)
--------- --------- --------- ---------
Financing Activities
Dividends on common stock (98,305) (98,164) (196,610) (196,116)
Dividends on preferred stock (8,297) (8,475) (16,673) (16,697)
Issuance of common stock - 4,580 - 8,330
Redemption of preferred stock - (78) - (1,668)
Issuance of long-term debt - 15,840 172,754 15,840
Reacquisition and retirement of long-term debt (26,300) (17,548) (126,217) (34,603)
Proceeds from sale and leaseback of control center system - - - 152,000
Short-term debt, net 69,050 164,400 (26,485) 61,175
Other financing activities (2,573) (12,427) (13,757) (22,089)
Nonutility subsidiary:
Issuance of long-term debt 78,000 75,000 185,000 151,750
Repayment of long-term debt (146,573) (177,452) (244,142) (266,297)
Short-term debt, net (64,020) 87,600 23,330 108,150
--------- --------- --------- ---------
Net Cash (Used By) From Financing Activities (199,018) 33,276 (242,800) (40,225)
--------- --------- --------- ---------
Net (Decrease) Increase in Cash and Cash Equivalents (1,126) 27,091 (27,977) 21,806
Cash and Cash Equivalents at Beginning of Period 7,438 7,198 34,289 12,483
--------- --------- --------- ---------
Cash and Cash Equivalents at End of Period $ 6,312 $ 34,289 $ 6,312 $ 34,289
========= ========= ========= =========
Cash paid for interest (net of capitalized interest) and income taxes:
Interest (including nonutility subsidiary
interest of $43,682, $46,672, $96,982 and $90,024) $ 111,887 $ 109,303 $ 230,954 $ 215,059
Income taxes $ 2,559 $ 2,665 $ 44,594 $ 49,289
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.
Effective April 30, 1996, the Company reorganized its
nonutility subsidiaries whereby PEPCO Enterprises, Inc. (PEI)
became a subsidiary of Potomac Capital Investment Corporation
(PCI), the Company's wholly owned subsidiary, which was formed in
1983 to provide a permanent vehicle for the conduct of the
Company's ongoing nonutility investment programs. PCI's
principal investments have been in aircraft and power generation
equipment, equipment leasing and marketable securities, primarily
preferred stock with mandatory redemption features. PCI 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.
Certain 1995 amounts have been reclassified to conform to
the current year presentation.
A description of significant accounting policies follows.
5
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,
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.
6
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 1996, 1995 and 1994.
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 June 30, 1996,
unamortized conservation costs totaled $100.9 million in Maryland
and $134 million in the District of Columbia.
7
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
Company accrues a CCRF on the retail jurisdictional portion of
certain pollution control projects related to compliance with the
Clean Air Act (CAA). The base for calculating this return is the
amount by which the retail jurisdictional CAA expenditure balance
exceeds the CAA balance included in rate base in the Company's
most recently completed base rate proceeding. The CCRF rates for
Maryland and the District of Columbia are 9.46% and 9.09%,
respectively.
The jurisdictional AFUDC capitalization rates are determined
as prescribed by the FERC. The effective capitalization rates
were approximately 7.3%, compounded semi-annually, for the six
months ended June 30, 1996, and approximately 7.9% in 1995 and
7.6% in 1994, compounded semi-annually.
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.
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 maturities of three months or less.
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.
8
<TABLE>
(2) INCOME TAXES
- ----------------
Provision for Income Taxes
- --------------------------
<CAPTION>
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
-------------------- ----------------------- ---------------------
1996 1995 1996 1995 1996 1995
--------- --------- ---------- ---------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Utility current tax expense
Federal $ 23,234 $ 24,347 $ 31,753 $ 12,950 $ 87,294 $ 58,767
State and local 3,569 2,881 4,346 1,429 12,090 7,707
-------- -------- --------- --------- -------- --------
Total utility current tax expense 26,803 27,228 36,099 14,379 99,384 66,474
-------- -------- --------- --------- -------- --------
Utility deferred tax expense
Federal 11,208 6,966 11,487 18,435 41,391 41,176
State and local 1,202 1,564 1,830 3,147 5,767 6,168
Investment tax credits (913) (912) (1,825) (1,824) (3,650) (3,649)
-------- -------- --------- --------- -------- --------
Total utility deferred tax expense 11,497 7,618 11,492 19,758 43,508 43,695
-------- -------- --------- --------- -------- --------
Total utility income tax expense 38,300 34,846 47,591 34,137 142,892 110,169
-------- -------- --------- --------- -------- --------
Nonutility subsidiary current tax expense
Federal (5,005) (4,705) (9,039) (7,940) (36,691) (33,569)
-------- -------- --------- --------- -------- --------
Nonutility subsidiary deferred tax expense
Federal (1,561) (63,607) (36,289) (66,661) (19,744) (45,224)
State and local - - - - - 731
-------- -------- --------- --------- -------- --------
Total nonutility subsidiary deferred tax expense (1,561) (63,607) (36,289) (66,661) (19,744) (44,493)
-------- -------- --------- --------- -------- --------
Total nonutility subsidiary income tax expense (6,566) (68,312) (45,328) (74,601) (56,435) (78,062)
-------- -------- --------- --------- -------- --------
Total consolidated income tax expense 31,734 (33,466) 2,263 (40,464) 86,457 32,107
Income taxes included in other income (6,074) (68,281) (43,716) (74,858) (53,587) (77,949)
-------- -------- --------- --------- -------- --------
Income taxes included in utility operating expenses $ 37,808 $ 34,815 $ 45,979 $ 34,394 $140,044 $110,056
======== ======== ========= ========= ======== ========
9
</TABLE>
<TABLE>
Reconciliation of Consolidated Income Tax Expense
- -------------------------------------------------
<CAPTION>
Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
-------------------- ----------------------- ---------------------
1996 1995 1996 1995 1996 1995
--------- -------- --------- ---------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before income taxes $103,987 $(90,304) $ 89,250 $(101,274) $328,645 $119,753
======== ======== ========= ========= ======== ========
Utility income tax at federal
statutory rate $ 35,527 32,727 $ 43,072 $ 32,620 $132,331 $105,329
Increases (decreases) resulting from
Depreciation 2,543 2,249 5,085 4,497 9,761 8,770
Removal costs (1,170) (1,668) (1,478) (2,899) (5,783) (4,655)
Allowance for funds used during
construction 146 162 280 327 548 (346)
Other (934) (602) (1,475) (1,640) (1,449) (3,991)
State income taxes, net of federal effect 3,101 2,890 3,932 3,056 11,524 9,100
Tax credits (913) (912) (1,825) (1,824) (4,040) (4,038)
-------- -------- --------- --------- -------- --------
Total utility income tax expense 38,300 34,846 47,591 34,137 142,892 110,169
-------- -------- --------- --------- -------- --------
Nonutility subsidiary income tax at federal
statutory rate 868 (64,334) (11,835) (68,066) (17,305) (63,416)
Increases (decreases) resulting from
Dividends received deduction (4,408) (2,112) (6,044) (4,313) (10,255) (8,651)
Reversal of previously accrued deferred taxes (5,193) - (28,699) - (28,699) (1,659)
Other 2,167 (1,866) 1,250 (2,222) (176) (5,067)
State income taxes, net of federal effect - - - - - 731
-------- -------- --------- --------- -------- --------
Total nonutility subsidiary income tax expense (6,566) (68,312) (45,328) (74,601) (56,435) (78,062)
-------- -------- --------- --------- -------- --------
Total consolidated income tax expense 31,734 (33,466) 2,263 (40,464) 86,457 32,107
Income taxes included in other income (6,074) (68,281) (43,716) (74,858) (53,587) (77,949)
-------- -------- --------- --------- -------- --------
Income taxes included in utility operating expenses $ 37,808 $ 34,815 $ 45,979 $ 34,394 $140,044 $110,056
======== ======== ========= ========= ======== ========
10
</TABLE>
<TABLE>
Components of Consolidated Deferred Tax Liabilities (Assets)
- ------------------------------------------------------------
<CAPTION>
June 30, Dec. 31, June 30,
1996 1995 1995
--------- --------- ----------
(Thousands of Dollars)
<S> <C> <C> <C>
Utility deferred tax liabilities (assets)
Depreciation and other book to tax
basis differences $794,312 $773,323 $ 745,417
Rapid amortization of certified pollution
control facilities 26,068 26,640 28,252
Deferred taxes on amounts to be collected
through future rates 90,790 92,472 91,409
Property taxes 12,132 11,808 11,407
Deferred fuel (12,954) (7,154) (4,338)
Prepayment premium on debt retirement 21,543 22,080 20,970
Deferred investment tax credit (23,769) (24,464) (25,155)
Contributions in aid of construction (27,551) (27,206) (25,272)
Contributions to pension plan 11,803 10,859 -
Other 20,050 25,124 24,146
-------- -------- ---------
Total utility deferred tax liabilities (net) 912,424 903,482 866,836
Current portion of utility deferred tax liabilities
(included in Other Current Liabilities) 5,392 10,938 3,534
-------- -------- ---------
Total utility deferred tax liabilities (net) - non-current $907,032 $892,544 $ 863,302
======== ======== =========
Nonutility subsidiary deferred tax liabilities (assets)
Finance leases $161,744 $149,103 $ 133,326
Operating leases 31,682 66,802 22,256
Reversal of previously accrued taxes related
to partnerships (9,570) (11,593) (16,152)
Alternative minimum tax (88,664) (84,512) (81,730)
Other (34,417) (16,840) 21,940
-------- -------- ---------
Total nonutility subsidiary deferred tax liabilities
(net), (included in Deferred taxes and other) $ 60,775 $102,960 $ 79,640
======== ======== =========
11
</TABLE>
(3) CAPITALIZATION
--------------
Common Equity
- -------------
At June 30, 1996, 118,496,701 shares of the Company's $1 par
value Common Stock were outstanding. A total of 200 million
shares is authorized. As of June 30, 1996, 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 2,771,633 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 June 30, 1996, the Company had outstanding 5,375,838
shares of its $50 par value Serial Preferred Stock, including the
Redeemable Serial Preferred Stock. A total of 11,126,222 shares
is authorized. At June 30, 1996, the aggregate annual dividend
requirements on the Serial Preferred Stock and the Redeemable
Serial Preferred Stock were approximately $6.4 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
(6,142 shares outstanding at June 30, 1996) is convertible into
Common Stock at $8.51 per share.
At June 30, 1996, the Company had outstanding one million
shares of its Serial Preferred Stock, Auction Series A. The
annual dividend rate is 4.14% ($2.07) for the period June 1,
1996, through August 31, 1996. For the period March 1, 1996,
through May 31, 1996, the annual dividend rate was 3.99%
($1.995). The average rate at which dividends were paid during
the 12 months ended June 30, 1996, was 4.29% ($2.14).
12
At June 30, 1996, 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
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 2000 with respect to the three series of
Redeemable Serial Preferred Stock are $1 million in 1997 and $1.5
million annually thereafter.
The Company's Long-Term Debt at June 30, 1996, is summarized
below:
(Thousands of Dollars)
First Mortgage Bonds $1,341,800
Convertible Debentures 180,447
Notes Payable 325,000
Net Unamortized Discount (28,886)
Current Portion (100,000)
----------
Net Utility Long-Term Debt $1,718,361
==========
Nonutility Subsidiary Long-Term Debt $ 978,911
==========
At June 30, 1996, the aggregate annual interest requirement
on the Company's long-term debt, including debt due within one
year, was $126.2 million; and the aggregate amounts of long-term
debt maturities are $150 million in 1997, $50 million in 1998,
$45 million in 1999 and $100 million in 2000. At June 30, 1996,
long-term debt due within one year consisted of $100 million of
6.66% - 6.73% Medium-Term Notes.
Nonutility Subsidiary Long-Term Debt
- ------------------------------------
Long-term debt at June 30, 1996, consisted primarily of
unsecured borrowings from institutional lenders maturing at
various dates between 1996 and 2003. The interest rates of such
borrowings ranged from 5% to 10.1%. The weighted average
effective interest rate was 7.29% at June 30, 1996, 7.66% at
December 31, 1995, and 7.71% at June 30, 1995. Annual aggregate
principal repayments on these borrowings are $87.3 million in
1996, $194.5 million in 1997, $301.3 million in 1998, $140.5
million in 1999, $95 million in 2000 and $97.5 million
thereafter. Also included in long-term debt is $62.8 million of
non-recourse debt which is due in monthly installments with final
maturities in 2001, 2002 and 2011.
13
<TABLE>
(4) Fair Value of Financial Instruments
- ---------------------------------------
The estimated fair values of the Company's financial instruments at
June 30, 1996, December 31, 1995, and June 30, 1995, are shown below.
<CAPTION>
June 30, December 31, June 30,
1996 1995 1995
-------------------------- ------------------------- -------------------------
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 $ 125,307 110,157 125,325 114,590 125,401 111,297
========== ========= ========= ========= ========= =========
Redeemable serial
preferred stock $ 142,500 143,496 143,485 145,046 143,485 139,796
========== ========= ========= ========= ========= =========
Long-term debt
First Mortgage Bonds $1,326,975 1,291,083 1,326,560 1,385,609 1,212,289 1,203,599
Medium-Term Notes $ 223,152 216,888 323,007 336,351 322,860 326,886
Convertible Debentures $ 168,234 170,092 167,510 174,054 168,221 164,667
---------- --------- --------- --------- --------- ---------
Total long-term debt $1,718,361 1,678,063 1,817,077 1,896,014 1,703,370 1,695,152
========== ========= ========= ========= ========= =========
Nonutility Subsidiary
Assets
Marketable securities $ 409,194 409,194 530,323 530,323 514,159 514,159
========== ========= ========= ========= ========= =========
Notes receivable $ 64,298 62,168 62,175 63,184 61,188 59,380
========== ========= ========= ========= ========= =========
Liabilities
Long-term debt $ 978,911 993,426 1,047,484 1,071,354 1,038,053 1,041,401
========== ========= ========= ========= ========= =========
14
</TABLE>
The methods and assumptions below were used to estimate, at
June 30, 1996, December 31, 1995, and June 30, 1995, 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.
15
(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 95%
of the portfolio at June 30, 1996. Net unrealized gains and
losses are reflected, net of tax, in stockholder's equity. The
net unrealized (losses) gains are shown below:
As of June 30, 1996
---------------------------------------
Net
Market Unrealized
Cost Value Losses
---------- ---------- --------------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 415,550 $ 409,194 $ (6,356)
Equity securities 3 - (3)
---------- ---------- ------------
Total $ 415,553 $ 409,194 $ (6,359)
========== ========== ============
As of December 31, 1995
---------------------------------------
Net
Market Unrealized
Cost Value Gain/(Loss)
---------- ---------- --------------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 519,488 $ 530,115 $ 10,627
Equity securities 341 208 (133)
---------- ---------- ------------
Total $ 519,829 $ 530,323 $ 10,494
========== ========== ============
16
As of June 30, 1995
---------------------------------------
Net
Market Unrealized
Cost Value Gain/Loss
---------- ---------- --------------
(Thousands of Dollars)
Mandatory redeemable
preferred stock $ 510,280 $ 514,159 $ 3,879
Equity securities 3 - (3)
---------- ---------- ------------
Total $ 510,283 $ 514,159 $ 3,876
========== ========== ============
Included in net unrealized gains and losses are gross
unrealized losses of $12.5 million and gross unrealized gains of
$6.1 million at June 30, 1996; gross unrealized losses of $6.6
million and gross unrealized gains of $17.1 million at December
31, 1995; and gross unrealized losses of $9 million and gross
unrealized gains of $12.9 million at June 30, 1995.
At June 30, 1996, the contractual maturities for mandatory
redeemable preferred stock are $5.9 million within one year,
$71.4 million from one to five years, $116.3 million from five to
10 years and $222 million for over 10 years.
In determining gross realized gains and losses on sales or
maturities of securities, specific identification is used. A
summary of realized gains and losses is shown below.
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
1996 1995 1996 1995
-------- -------- -------- --------
(Thousands of Dollars)
Gross realized
gains $ 244 $ 213 $ 2,505 $ 361
Gross realized
losses (121) (196) (792) (207)
-------- -------- -------- --------
Net gain $ 123 $ 17 $ 1,713 $ 154
======== ======== ======== ========
17
(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 530,000
natural gas customers. Preliminary estimates indicate that
savings from the combined utility systems will approximate $1.3
billion over 10 years, net of costs to achieve. 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 the Company will be determined in regulatory
proceedings. 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.
Shareholders of the Company and BGE, at separate special
meetings on March 29, 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 on
April 8, 1996, with the Maryland and District of Columbia Public
Service Commissions. The Maryland Commission conducted hearings
during June 1996 and further hearings are scheduled for September
and November 1996. The case is scheduled to be before the
18
Maryland Commission for decision in December 1996. A prehearing
conference was conducted by the District of Columbia Commission
in May 1996 and a procedural schedule was published on July 19,
1996. Hearings are scheduled to take place in December 1996 and
the case is expected to be before the District of Columbia
Commission for decision in January 1997. No further action has
been taken by FERC with respect to the filing. Additional
approvals are required from the Nuclear Regulatory Commission,
the Virginia State Corporation Commission and the Pennsylvania
Public Utility Commission. Completion of the approval process is
expected to take until the end of the first quarter of 1997.
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 lose employment due to the Merger. Employees who
lose employment as a result of the Merger will receive two weeks
of pay per year of service, with a minimum payment of eight weeks
of pay. In addition, employees will receive company-sponsored
health and dental insurance for two weeks per year of service,
with a minimum of eight weeks of insurance coverage.
In December 1995, an extension of the current 1993 Labor
Agreement between the Company and Local 1900 of the International
Brotherhood of Electrical Workers was ratified by the Union
members. The 1995 Agreement extends the 1993 Agreement, which
was due to expire on June 1, 1996, for two years or until the
effective date of the Merger with BGE, whichever occurs first.
This Agreement provides severance benefits, previously approved
by the Company for exempt and non-bargaining unit employees, for
all union members and provides for a lump-sum payment of 2% of
base pay, which was paid on January 5, 1996, a lump-sum payment
of 1% of base pay, which was paid 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.
19
Environmental Contingencies
- ---------------------------
As discussed in the 1995 Form 10-K and the March 31, 1996
Form 10-Q, 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
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 1995 Form 10-K and the March 31, 1996
Form 10-Q, 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 1995 Form 10-K and the March 31,
1996 Form 10-Q, 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 June 30, 1996.
The report included a number of possible remedies, the estimated
costs of which range from $2 million to $90 million. In July
1995, the EPA announced its proposed remedial action plan for the
site and indicated it will accept comments on the plan from any
interested parties. The EPA's estimate of the costs associated
with implementation of the plan is approximately $17 million.
The Company cannot predict whether the EPA will include the plan
in its ROD as proposed or make changes as a result of comments
received. In addition, the Company cannot estimate the total
20
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 1995 Form 10-K and the March 31,
1996 Form 10-Q, 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
four hundred and forty-eight (448) individual plaintiffs added
the Company to their Complaints. While the pleadings are not
entirely clear, it appears that each plaintiff seeks $2 million
in compensatory damages and $4 million in punitive damages from
each defendant. In a related proceeding in the Baltimore City
case, the Company was served, in September 1993, with a third
party complaint by Owens Corning Fiberglass, Inc. (Owens Corning)
alleging that Owens Corning was in the process of settling
approximately 700 individual asbestos-related cases and seeking a
judgment for contribution against the Company on the same theory
of alleged negligence set forth above in the plaintiffs' case.
Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed
a third-party complaint against the Company, seeking contribution
for the same plaintiffs involved in the Owens Corning third-party
complaint. Since the initial filings in 1993, approximately
fifty (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 four hundred (400) of the individual plaintiffs
have dismissed their claims against the Company. No payments
were made by the Company in connection with the dismissals.
While the aggregate amount specified in the remaining suits would
exceed $400 million, the Company believes the amounts are greatly
exaggerated as were the claims already disposed of. The amount
of total liability, if any, and any related insurance recovery
cannot be precisely determined at this time; however, based on
information and relevant circumstances known at this time, the
Company does not believe these suits will have a material adverse
effect on its financial position. However, an unfavorable
decision rendered against the Company could have a material
adverse effect on results of operations in the fiscal year in
which a decision is rendered.
The Company is involved in other legal and administrative
(including environmental) proceedings before various courts and
agencies with respect to matters arising in the ordinary course
21
of business. Management is of the opinion that the final
disposition of these proceedings will not have a material adverse
effect on the Company's financial position or results of
operations.
Nonutility Subsidiary
- ---------------------
See the discussion on PCI in Part I, Item 2, Management's
Discussion and Analysis of Consolidated Results of Operations and
Financial Condition.
* * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * * *
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 1995
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 23) 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) and in the
Joint Proxy Statement/Prospectus constituting part of the
Registration Statement on Form S-4 (Number 33-64799) 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.
22
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 June 30, 1996 and 1995, and the related consolidated
statements of earnings and retained income for the three, six and
twelve month periods then ended and the consolidated statements
of cash flows for the six 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, 1995, 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 19, 1996, 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, 1995, 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.
July 26, 1996
23
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 Corporation (Constellation Energy). The
Company and BGE filed a joint Application for Authorization and
Approval of the Merger with the FERC on January 11, 1996, and on
April 8, 1996, with the Maryland and District of Columbia Public
Service Commissions. The Maryland Commission conducted hearings
during June 1996 and further hearings are scheduled for September
and November 1996. The case is scheduled to be before the
Maryland Commission for decision in December 1996. A prehearing
conference was conducted by the District of Columbia Commission
in May 1996 and a procedural schedule was published on July 19,
1996. Hearings are scheduled to take place in December 1996 and
the case is expected to be before the District of Columbia
Commission for decision in January 1997. No further action has
been taken by FERC with respect to the filing.
The combination of the Company and BGE will create a larger,
stronger company better able to maintain the low costs which will
be essential to compete effectively, and better able to
contribute to economic and job development in the area. The
Merger will result in lower operating costs than either company
could produce alone. Over the first 10 years following the
Merger, Constellation Energy expects to achieve net merger-
related savings of $1.3 billion. The allocation of the net
savings between customers and shareholders of the Company will be
determined in regulatory proceedings. The applications 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 includes: (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 Merger also requires approval from the Nuclear
Regulatory Commission, the Virginia State Corporation Commission
and the Pennsylvania Public Utility Commission. Completion of
the approval process is expected to take until the end of the
first quarter of 1997.
24
See Part I, Item 1, Notes to Consolidated Financial
Statements, (6) Commitments and Contingencies, for additional
information.
RESULTS OF OPERATIONS
- ---------------------
TOTAL REVENUE
Total revenue increased for the three, six and twelve months
ended June 30, 1996, as compared to the corresponding periods in
1995. The increase in revenue from sales of electricity for the
three, six and twelve months ended June 30, 1996, was primarily
due to increases in kilowatt-hour sales of 4.3%, 5.8% and 6.4%
over the corresponding periods in 1995, the effect of the July
1995 base rate increase in the District of Columbia and the
effect of the July 1995 increase in the Demand Side Management
(DSM) surcharge tariff rate in Maryland. An incentive provision
of $8.7 million was recorded in June 1995 for achieving specific
1994 energy conservation goals. The Company is presently
updating its calculation of the Maryland DSM surcharge tariff
rate which includes the incentive provision awarded for achieving
specific 1995 goals. The incentive provision is expected to
approximate the $8.7 million awarded in 1995. Approval of the
updated surcharge tariff is expected in the third quarter of 1996
and will be reflected in revenue when approved. The increase in
kilowatt-hour sales for the three, six and twelve months ended
June 30, 1996, was attributable to hotter than average weather
during the second quarter 1996 as compared to cooler than average
weather during the corresponding period in 1995. Cooling degree
hours for the quarter were 88% and 31% above the corresponding
period in 1995 and the 20-year average, respectively. In
addition, kilowatt-hour sales for the six and twelve months were
favorably impacted by the blizzard-like conditions during the
first quarter of 1996 which brought a record amount of snowfall
to the Washington D.C. area.
The increases in interchange deliveries for the three, six
and twelve months ended June 30, 1996, reflect the growth in the
number of companies involved in power sales tariff interchange
transactions where the Company buys energy from one party for the
purpose of selling that energy to a third party. The benefits
derived from interchange deliveries are passed through to the
Company's customers through a fuel clause.
25
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
District of Columbia 26,700 3.9 March/June 1994
Federal - Wholesale 2,600 2.3 January 1994
OPERATING EXPENSES
Fuel and purchased energy increased for the three, six and
twelve months ended June 30, 1996, as compared to the
corresponding periods ended June 30, 1995. Fuel expense
increased for the three, six and twelve months ended June 30,
1996, primarily as a result of increases of 6.9%, 13.8% and
19.9%, respectively, in net generation due to higher customer
usage of electricity. The increases in purchased energy for the
three, six and twelve months ended June 30, 1996, reflect 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 June
30, were as follows:
Three Six Twelve
Months Ended Months Ended Months Ended
------------ ------------ ------------
1996 1995 1996 1995 1996 1995
---- ---- ---- ---- ---- ----
System Average
Fuel Cost per MBTU $1.78 $1.66 $1.80 $1.74 $1.77 $1.80
System average unit fuel cost increased for the three and
six months ended and decreased for the twelve months ended June
30, 1996, as compared to the corresponding periods in 1995. The
increases for the three and six months ended June 30, 1996, were
primarily attributable to increased net generation due to
increased customer usage of electricity and an increased use of
major cycling units which burn higher cost fuel. The decrease in
the system average unit fuel cost for the twelve months ended
June 30, 1996, was primarily attributable to a decrease in the
cost of coal and an increase in the percent of coal contribution
to the fuel mix. The Company's major cycling and certain peaking
units can burn natural gas or oil, adding flexibility in
selecting the most cost-effective fuel mix.
26
For the twelve month periods ended June 30, 1996 and 1995,
the Company obtained 86% and 85%, respectively, of its system
generation from coal based upon percentage of Btus.
Capacity purchase payments increased slightly for the three
and six months and decreased for the twelve months ended June 30,
1996, as compared to the corresponding periods in 1995. The
increases for the three and six months ended June 30, 1996, were
primarily attributable to increases in fixed operating and
maintenance expense associated with the capacity agreements with
Ohio Edison and Allegheny Power System (APS). The decrease for
the twelve months ended June 1996, reflects the expiration of a
purchase agreement for 147 megawatts of capacity from
Pennsylvania Power and Light Company for the one year period June
1994 through May 1995.
Operating expenses other than fuel, purchased energy and
capacity purchase payments increased for the three, six and
twelve months ended June 30, 1996, as compared to the
corresponding periods in 1995. The increases were principally
due to increased income taxes due to higher taxable income,
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 and the $1.8 million and $.9 million paid on January 5,
1996 and June 7, 1996, respectively, to union members as part of
the 1995 Labor Agreement between the Company and Local 1900 of
the International Brotherhood of Electrical Workers. The
increases for the six and twelve months ended June 30, 1996, are
partially offset by a nonrecurring charge of $7.4 million taken
in January 1995 for operating costs associated with the Company's
Voluntary Severance Program. The increase in operating expenses
other than fuel, purchased energy and capacity purchase payments
for the twelve months ended June 30, 1996, also includes rent
expense associated with the December 1994 sale and leaseback of
the Company's control center system. Bad debt expense, as a
percent of revenue, was .4% for the three, six and twelve months
ended June 30, 1996, as compared to .3% for the three months
ended and .4% for the six and twelve months ended June 30, 1995.
At June 30, 1996, accounts receivable included $11.2 million, or
3.5% of outstanding receivables, due from the agencies of the
District of Columbia for electric service and maintenance, of
which $4.3 million was in arrears. As of July 24, 1996, the
District of Columbia accounts receivable balance had been reduced
to $10.6 million due to receipt of additional payments. The
Company believes that amounts owed by the District of Columbia
will be paid and, accordingly, has not established a bad debt
reserve for this receivable balance.
27
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The Company's investment in property and plant, at original
cost before accumulated depreciation, was $6.2 billion at June
30, 1996, an increase of $76.7 million from the investment at
December 31, 1995, and an increase of $171.1 million from the
investment at June 30, 1995. Cash invested in property and plant
construction, excluding AFUDC and CCRF, amounted to $84.6 million
for the six months ended June 30, 1996, and $186.8 million for
the twelve months then ended.
At June 30, 1996, the Company's capital structure, excluding
short-term debt, long-term debt and serial preferred stock
redemptions due within one year, and nonutility subsidiary debt,
consisted of 44.9% long-term debt, 3.3% serial preferred stock,
3.7% redeemable serial preferred stock and 48.1% common equity.
Cash from (used by) utility operations, after dividends, was
$14.7 million for the six months ended June 30, 1996, and $135.1
million for the twelve months then ended as compared with $(44.3)
million and $63.4 million, respectively, for the same periods
ended June 30, 1995.
Outstanding utility short-term debt totaled $327.5 million
at June 30, 1996, an increase of $69.1 million from the $258.5
million outstanding at December 31, 1995, and a decrease of $26.5
million from the $354 million outstanding at June 30, 1995. See
the discussion included in Note (3) of the Notes to Consolidated
Financial Statements, Capitalization, for additional information.
NONUTILITY SUBSIDIARY
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
PCI's earnings for the three, six and twelve months ended
June 30, 1996 were $9 million ($.07 per share), $11.5 million
($.10 per share) and $7 million ($.06 per share) compared to net
losses of $115.5 million ($.98 per share), $119.9 million ($1.01
per share) and $103.1 million ($.87 per share) for the same
periods ending June 30, 1995. PCI's losses in 1995 reflect the
implementation of PCI's May 1995 announcement of a plan to exit
the aircraft equipment leasing business, resulting in noncash,
after-tax charges of $115.2 million ($.98 per share) recorded in
the second quarter of 1995. Under the plan, PCI will make no new
investments to increase the size of the aircraft portfolio and 13
aircraft were designated for sale over 18 to 24 months from the
date the plan was announced. The book values of these aircraft
were reduced to their estimated net realizable values of
approximately $104 million and no depreciation or routine accrual
28
for repair and maintenance expenditures for these aircraft have
been recorded since the plan was adopted. As of June 30, 1996,
six of these aircraft have been sold and one has been placed on a
long-term lease. This activity, in addition to a first quarter
1996 writedown of $12.3 million ($8 million after-tax), reduced
the portfolio of assets held for disposal to $20.2 million as of
June 30, 1996.
In accordance with the plan, PCI continues to hold and
closely monitor the remainder of its aircraft leasing portfolio,
with the objective of identifying future opportunities for
disposition of these investments on favorable terms.
Satisfactory execution of the entire plan may be affected by
future market conditions and events, which may have an impact on
equipment values and sales opportunities and, in the case of the
portion of the portfolio on long-term lease, the creditworthiness
of PCI's lessees.
During the fourth quarter of 1995, as a part of its plan to
exit the aircraft equipment leasing business, PCI formed a joint
venture with an affiliate of a major institutional investor to
assist with the disposition and management of 19 portfolio
aircraft. PCI contributed 11 aircraft from its portfolio of
aircraft held for disposal, eight additional aircraft under long-
term leases, and a portfolio of preferred stocks to the joint
venture. All of the assets of the venture are fully consolidated
on PCI's financial statements with the outside investor's portion
reflected as a minority interest. Two aircraft were sold from
the joint venture during the first quarter, and four aircraft
were sold during the second quarter. As a result of joint
venture operations for the three and six months ended June 30,
1996, PCI's obligation for previously accrued deferred income
taxes was reduced, resulting in after-tax earnings of $4.3
million and $25.9 million, respectively, after provision for
transaction costs. The excess deferred income taxes were
recognized as a reduction of income tax expense. Future
operations of the joint venture may result in additional reversal
of deferred income taxes.
As a result of the first quarter 1996 implementation of SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of", a pre-tax charge of
$9.6 million ($6.2 million after-tax) was recorded related to
PCI's investment in solar electric generating systems (SEGS)
projects, reflecting revised first quarter assumptions relating
to the recoverability of the investment. No additional
adjustments were required as the result of the implementation of
this accounting standard. In addition, PCI recorded a pre-tax
charge of $9 million ($5.9 million after-tax) in the first
quarter, reflecting current assessments of the net realizable
values of real estate and oil and natural gas investments.
29
PCI has five 30-megawatt SEGS projects in the Mojave Desert
in California. The Company owns 22%, 10%, 19%, 31%, and 25% of
SEGS projects III through VII, respectively. The five SEGS power
generation projects sell electricity to Southern California
Edison Company (Edison) under 30-year Interim Standard Offer No.
4 power purchase agreements which fix the capacity charge for the
term of the agreements and fix the energy rate paid by Edison for
the first 10 years of the agreements. For the remaining term of
the agreements, energy rates are variable, based on Edison's
avoided cost of generation. The SEGS projects are scheduled to
begin supplying electricity at avoided cost rates at various
times beginning in early 1997 through the end of 1998. In
conjunction with other project investors, PCI is investigating
and pursuing alternatives for these projects, including but not
limited to, renegotiating the power purchase agreements and
restructuring the associated non-recourse debt. If current
avoided cost levels were to continue or the investors are not
successful in their pursuit of other alternatives, PCI could
experience reduced earnings or incur additional losses associated
with these projects. PCI's investment in SEGS at June 30, 1996,
was $40.7 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 $23.1 million, $47.1 million and $101.8 million for
the three, six and twelve months ended June 30, 1996,
respectively, compared to $22.1 million, $45.9 million and $108.8
million for the corresponding periods in 1995. The increase in
earnings during the three and six months period ended June 30,
1996 over the same periods in 1995 was primarily due to a third
quarter 1995 leveraged lease investment in an Australian base
load, coal-fired power plant. The decrease in earnings during
the twelve month period ended June 30, 1996 over the same period
in 1995 was primarily due to fees earned during the twelve months
ended June 30, 1995. PCI's marketable securities portfolio
contributed pre-tax income of $7.5 million, $17.5 million and
$35.1 million for the three, six and twelve months ended June 30,
1996, respectively, compared to $9.4 million, $18.6 million and
$36.5 million for the same periods in 1995. The reductions are
primarily the result of the decreased size of the portfolio.
Income from securities during the three, six and twelve months
ended June 30, 1996 included net realized gains from the sale or
call of securities of $.1 million, $1.7 million and $2 million,
respectively, compared to $.02 million, $.2 million and $.6
million for the same periods ended June 30, 1995.
Other income decreased by $17.5 million and $21.1 million
for the six and twelve months ended June 30, 1996, respectively,
compared to the same periods in 1995. The decreases during the
six and twelve month periods were primarily the result of the
previously discussed first quarter 1996 writedowns of PCI's
investments in SEGS, real estate and oil and natural gas.
30
Expenses, before income taxes, which include interest,
depreciation and operating, and administrative and general
expenses totaled $29.3 million, $82.9 million and $166.5 million
for the three, six and twelve months ended June 30, 1996,
respectively, compared to $216.5 million, $261 million and $327.7
million for the same periods in 1995. The decreases are
primarily the result of the second quarter 1995 pre-tax writedown
of $170.1 million related to the May 1995 plan to exit the
aircraft equipment leasing business. Expenses before income
taxes also decreased during the three and six months ended June
30, 1996, compared to the same periods ended June 30, 1995, due
to lower interest expense resulting from less debt outstanding.
Interest expense increased slightly for the twelve month period
ended June 30, 1996 over the same twelve month period in 1995 due
to an increase in weighted average interest rates for the period.
During the second quarter of 1996, responsibility for certain
repair and maintenance expenses was assumed by a lessee.
Accordingly, PCI reversed $6.5 million of expenses accrued in
prior periods.
PCI had income tax credits of $6.6 million, $45.3 million
and $56.4 million for the three, six and twelve months ended June
30, 1996, respectively, compared to income tax credits of $68.3
million, $74.6 million and $78.1 million for the corresponding
periods in 1995. The decreases in income tax credits in 1996
from the same periods in 1995 were primarily the result of the
pre-tax charge to earnings as a result of PCI's decision to exit
the aircraft equipment leasing business.
CAPITAL RESOURCES AND LIQUIDITY
- -------------------------------
The $409.2 million securities portfolio, consisting
primarily of investment grade preferred stocks, provides PCI with
liquidity and investment flexibility. During 1996, PCI has
reduced its marketable securities portfolio by $121.1 million
primarily as the result of calls (approximately $70.7 million)
and sales of fixed rate preferred stocks, generating net pre-tax
gains of $1.7 million. PCI's fixed rate portfolio is highly
sensitive to fluctuations in interest rates. The decision to
reduce the size of the preferred stock portfolio was made to
lessen the impact of future fluctuations in interest rates, while
still maintaining a substantial portfolio for liquidity purposes.
The proceeds from the securities activity during 1996 were used
to pay down short-term debt. In addition, proceeds from aircraft
sales also were used to pay down short-term debt.
31
PCI's outstanding short-term debt totaled $159.3 million at
June 30, 1996, a decrease of $64 million from the $223.4 million
outstanding at December 31, 1995, and an increase of $23.3
million from the $136 million outstanding at June 30, 1995.
During the six and twelve months ended June 30, 1996, PCI issued
$78 million and $185 million, respectively, in long-term debt,
including non-recourse debt. In addition, during the three, six
and twelve months ended June 30, 1996, debt repayments totaled
$87.8 million, $146.6 million and $244.1 million, respectively.
At June 30, 1996, PCI had $316.3 million available under its
Medium-Term Note Program and $400 million available under its
committed bank credit facility.
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 1996 and 1995.
BASE RATE PROCEEDINGS
- ---------------------
Maryland
- --------
Pursuant to a settlement agreement, base rate revenue was
increased by $27 million, or 3%, effective November 1, 1993. In
connection with the settlement agreement, no determination was
made with respect to rate of return. The rate of return on
common stock equity most recently determined for the Company in a
fully litigated rate case was 12.75%, established by the
Commission in a June 1991 rate increase order.
The Company's Maryland DSM Surcharge, which provides for the
recovery of conservation program costs over a five-year period
and includes provisions for the recovery of lost revenue, a CCRF,
calculated at 9.46%, on unrecovered program balances and an
incentive amount based on achieving prior-year goals was
32
increased effective July 1, 1995. The new rate resulted in an
increase in the annual surcharge recovery of approximately $33
million, including the initial amortization of 1995 projected
program costs and incentives awarded for exceeding 1994 and 1993
program goals. The Company is presently updating its calculation
of the Maryland Demand Side Management surcharge tariff rate,
within the established Maryland collaborative process. The
incentive provision of the tariff, awarded for achieving specific
1995 energy conservation goals, is expected to approximate the
$8.7 million awarded in 1995. Approval of the updated surcharge
tariff is expected in the third quarter of 1996 and will be
reflected in revenue when approved.
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 conservation
programs while limiting the impact of such programs on the price
of electricity. An Environmental Cost Recovery Rider (ECRR) was
approved to provide for full cost recovery of actual conservation
program expenditures, through a billing surcharge. Costs will be
amortized over 10 years, with a return on unamortized amounts by
means of a 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. On June 3, 1996, the Company filed an
Application for Authority with the Commission to revise its ECRR.
The proposed rate, which reflects actual costs expended from July
1993 through December 1995, is expected to increase annual
revenue by approximately $8 million. 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). Pre-July 1993 conservation costs receive base rate
treatment. Although the Commission denied the Company's request
to recover "lost revenue" due to DSM programs, through the
surcharge, a process has been established whereby the Company can
seek recovery of lost revenue in a separate proceeding. The
Commission also increased the time period for filing Least-Cost
Planning cases from two to three years.
33
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.
SMECO rates were increased by $2.3 million effective January
1, 1995. Pursuant to a new agreement with SMECO for the years
1996 through 1998, a rate reduction of $2 million from the 1995
rate level became effective January 1, 1996, 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 the other members of the Pennsylvania-New
Jersey-Maryland Interconnection Association (PJM) and other
utilities. The pricing of most PJM internal economy energy
transactions is based upon "split savings" so that the price of
such energy is halfway between the cost that the purchaser would
incur if the energy were supplied by its own sources and the cost
of production to the company actually supplying the energy.
In addition to PJM interchange activity, the Company has
interconnection agreements with APS and Virginia Power. These
agreements provide a mechanism and the flexibility to purchase
power from these parties or from others with whom they are
interconnected on an as-needed basis in amounts mutually agreed
to from time-to-time pursuant to negotiated rates, terms and
conditions. In addition, during 1995 the Company entered into an
agreement with PECO Energy Company (PECO) to purchase up to 300,
but not less than 200, megawatt-hours of energy each hour
beginning in June 1995. The purchase of energy by the Company
under this agreement was terminated on January 31, 1996.
Pursuant to the Company's long-term capacity purchase
agreements with Ohio Edison and APS, the Company is purchasing
450 megawatts of capacity and associated energy through the year
2005. The monthly capacity commitment under these agreements,
excluding an allocation of fixed operating and maintenance cost,
is $18,060 per megawatt effective January 1994, with provision
for escalation in 1999. In addition, from June 1994 through May
1995, the Company purchased 147 megawatts of capacity from
Pennsylvania Power and Light Company.
34
In early 1995, the FERC approved a power sales tariff, filed
by the Company, which allows both sales from Company-owned
generation and sales of energy purchased by the Company. This
tariff expands the Company's opportunities to participate in
direct energy sales with other utilities and power marketers.
Through the use of similar tariffs, many other parties are now in
a position to buy and sell energy. The Company is actively
encouraging this market by buying energy for its own use and for
contemporaneous resale, when economic transactions are available.
Revenue associated with the power sales tariff, which commenced
in September 1995, were $37 million, $80 million and $103
million, respectively, for the three, six and twelve months ended
June 30, 1996. The benefits derived from interchange deliveries
are passed through to the Company's customers through a fuel
clause.
RESTRUCTURING OF THE BULK POWER MARKET
- --------------------------------------
On July 9, 1996, FERC's final orders became effective with
respect to its March 1995 Notice of Proposed Rulemaking (NOPR) on
open access transmission, stranded costs and same-time
information systems. In addition, FERC issued a NOPR on Capacity
Reservation Tariffs (CRT). Order No. 888 requires the filing of
an open access transmission tariff that complies with FERC's
terms and conditions. Such filing was made by the Company on
July 9, 1996. Order No. 889 requires the Company to establish or
participate in Open Access Same-Time Information Systems and to
comply with prescribed standards of conduct by November 1, 1996.
The CRT NOPR proposes a reservation-based transmission service
which would replace the proforma tariff set forth in Order No.
888 by December 31, 1997. Compliance with Order No. 888 and 889
is not expected to have a significant impact on the Company's
results of operations.
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 by year-end 1996, 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. In November 1995, the PJM members filed with the
FERC a detailed proposal that offers to all generators and
wholesale buyers of electricity a regional energy market and open
access to PJM's control area transmission system. Under the
proposal, PJM will be transformed into an Independent System
35
Operator (ISO), which will administer a bid-priced energy spot
market that will also accommodate bilateral transactions between
participants. The ISO will operate the regional energy market
and administer transmission service. PJM filed its final plan
with FERC on July 24, 1996, with a phased-in implementation
planned to begin in January 1997 with transitional planning
beginning immediately upon filing.
PEAK LOAD, SALES, CONSERVATION, AND CONSTRUCTION
- ------------------------------------------------
AND GENERATING CAPACITY
-----------------------
Peak Load and Sales Data
- ------------------------
Kilowatt-hour sales increased 4.3%, 5.8% and 6.4% for the
three, six months and twelve months ended June 30, 1996, as
compared to sales for the corresponding periods ended June 30,
1995. The increases in sales for the three, six and twelve
months ended June 30, 1996, were primarily attributable to the
hotter than average weather during the three months ended June
30, 1996, as compared to the below average weather during the
corresponding period in 1995. Cooling degree hours for the three
months ended June 30, 1996, were 88% above the corresponding
period in 1995, and 31% above the 20-year average. In addition,
the increases in kilowatt-hour sales for the six and twelve
months ended June 30, 1996, were favorably impacted by the
blizzard-like conditions during the first quarter of 1996 which
brought a record amount of snowfall to the Washington, D.C. area.
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.
Through July 24, 1996, the 1996 summer peak demand was 5,288
megawatts. 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
6,576 megawatts. To meet the 1996 summer peak demand, the
Company had approximately 282 megawatts available from its
dispatchable energy use management programs. Based on average
weather conditions, the Company estimates that its peak demand
will grow at a compound annual rate of approximately 1%,
reflecting continuing success with conservation and energy use
management programs and anticipated service area growth trends.
The 1995-1996 winter season peak demand of 4,831 megawatts was
3.6% below the all-time winter peak demand of 5,010 megawatts
which was established in January 1994.
36
Conservation
- ------------
The Company's conservation and energy use management
programs (EUM) are designed to curb growth in demand in order to
defer the need for construction of additional generating capacity
and to cost-effectively increase the efficiency of energy use.
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.
The Company invested approximately $25 million in energy
conservation programs in the first six months of 1996 and
approximately $100 million during 1995. The Company recovers the
costs of its conservation programs in its Maryland jurisdiction
through a base rate surcharge which amortizes costs over a five-
year 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
is presently updating its calculation of the Maryland Demand Side
Management surcharge tariff rate, within the established Maryland
collaborative process. The incentive provision of the tariff,
awarded for achieving specific 1995 energy conservation goals, is
expected to approximate the $8.7 million awarded in 1995.
Approval of the updated surcharge tariff is expected in the third
quarter of 1996. The Company was awarded a bonus of $5 million
in 1994, based on 1993 performance. In the District of Columbia,
conservation costs are amortized over 10 years with an accrued
return on unamortized costs. It is estimated that, in 1995, peak
load reductions of over 600 megawatts were achieved from
conservation and energy use management programs and that
additional peak load reductions of approximately 430 megawatts
will be achieved in the next five years. The Company also
estimates that, in 1995, energy savings of more than 1.2 billion
kilowatt-hours were realized through operation of its
conservation and energy use management programs. See the
discussions included in Summary of Significant Accounting
Policies, Total Revenue, and Base Rate Proceedings, for
additional information.
Construction and Generating Capacity
- ------------------------------------
Construction expenditures, excluding AFUDC and CCRF, are
projected to total $1.1 billion for the five-year period 1996
through 2000, which includes $112 million of estimated Clean Air
Act expenditures. In 1996, construction expenditures are
projected to total $170 million, which includes $6 million of
37
estimated Clean Air Act expenditures. As a result of lower rates
of projected load growth resulting in large part from
implementing economical conservation programs, the Company
previously reduced its projected construction expenditures by
$155 million in 1994 and $425 million in 1993. The Company plans
to finance its construction program primarily through funds
provided by operations.
The Company has implemented cost-effective plans for
complying with Phase I of the Clean Air Act (CAA) which requires
the reduction of sulfur dioxide and nitrogen oxides emissions to
achieve prescribed standards. Boiler burner equipment for
nitrogen oxides emissions control has been replaced and the use
of lower-sulfur coal has been instituted at the Company's Phase I
affected stations, Chalk Point and Morgantown. Anticipated
capital expenditures for complying with the second phase of the
CAA total $112 million over the next five years. The Company's
plans call for continued replacement of boiler burner equipment
for nitrogen oxides emissions control and further use of
lower-sulfur fuel and cofiring with natural gas for sulfur
dioxide (SO2) emissions control. If economical, the Company will
purchase SO2 emission allowances in lieu of burning lower-sulfur
fuel.
A 32-megawatt municipally financed resource recovery
facility in Montgomery County, Maryland, began commercial
operation in August 1995. Under the contract covering this
project, the Company will initially purchase energy without
capacity payment obligations. In addition, the Company has an
agreement with Panda Brandywine L.P. (Panda) for a 230-megawatt
gas-fueled combined-cycle cogeneration project in Prince George's
County, Maryland, scheduled for operation in the fourth quarter
of 1996. In addition to an energy charge, the 25-year agreement
requires capacity purchase payments to Panda of approximately
$1.6 million per month from January 1, 1997, through December 31,
1998. Capacity payments in 1999 and 2000 are approximately $3
million per month and generally increase thereafter, peaking at
approximately $4.5 million per month. The project is
approximately 85% complete at June 30, 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 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.
38
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 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 $409.2 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 $183.1 million and $168.6 million at June
30, 1996 and 1995, respectively.
39
<TABLE>
Consolidated Statements of Earnings:
- -----------------------------------
<CAPTION>
Three Six Twelve
Months Ended Months Ended Months Ended
June 30, June 30, June 30,
---------------------- ---------------------- ----------------------
1996 1995 1996 1995 1996 1995
-------- --------- -------- --------- -------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Income
Leasing activities $ 23,138 $ 22,105 $ 47,055 $ 45,931 $101,764 $ 108,767
Marketable securities 7,466 9,423 17,524 18,568 35,077 36,455
Other 1,179 1,138 (15,483) 2,052 (19,803) 1,284
-------- --------- -------- --------- -------- ---------
31,783 32,666 49,096 66,551 117,038 146,506
-------- --------- -------- --------- -------- ---------
Expenses
Interest 20,844 22,806 42,973 45,119 89,491 89,089
Administrative and general 3,677 2,797 9,040 5,428 14,090 10,682
Depreciation and
operating 4,781 190,874 30,896 210,478 62,900 227,923
Income tax credit (6,566) (68,312) (45,328) (74,601) (56,435) (78,062)
-------- --------- -------- --------- -------- ---------
22,736 148,165 37,581 186,424 110,046 249,632
-------- --------- -------- --------- -------- ---------
Net earnings (loss) from
nonutility subsidiary $ 9,047 $(115,499)<F1>$ 11,515 $(119,873)<F1>$ 6,992 <F1>$(103,126)<F1>
======== ========= ======== ========= ======== =========
Per share contribution
(reduction) to earnings
(loss) of the Company $ .07 $(.98)<F1> $ .10 $(1.01)<F1> $ .06 <F1> $(.87)<F1>
===== ===== ===== ====== ===== =====
<FN>
<F1> Reflects non-recurring, noncash, after-tax charges of $115.2 million
($.98 per share) for the three months ended June 30, 1995, $117
million ($.99 per share) for the six and twelve months ended
June 30, 1995, and $5.2 million ($.04 per share) for the twelve
months ended June 30, 1996, related to the 1995 decision to exit the
aircraft equipment leasing business.
</FN>
40
</TABLE>
<TABLE>
STATISTICAL DATA
- ----------------
<CAPTION>
Three Months Ended Twelve Months Ended
June 30, June 30,
--------------------------------- -------------------------------------
1996 1995 % Change 1996 1995 % Change
-------- -------- -------- ---------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Revenue from Sales
------------------
of Electricity
--------------
(Thousands of Dollars)
Residential $131,305 $122,990 6.8 $ 566,870 $ 514,891 10.1
General Service 282,848 271,684 4.1 1,089,205 1,052,432 3.5
Large Power Service <F1> 9,391 9,048 3.8 36,431 35,516 2.6
Street Lighting 2,827 2,908 (2.8) 12,322 13,127 (6.1)
Rapid Transit 6,917 6,788 1.9 28,712 27,808 3.3
Wholesale 27,714 25,424 9.0 123,815 109,776 12.8
-------- -------- ---------- ----------
System $461,002 $438,842 5.0 $1,857,355 $1,753,550 5.9
======== ======== ========== ==========
Energy Sales
------------
(Millions of KWH)
Residential 1,521 1,394 9.1 7,121 6,337 12.4
General Service 3,772 3,708 1.7 15,586 15,110 3.2
Large Power Service <F1> 172 164 4.9 716 678 5.6
Street Lighting 35 34 2.9 165 161 2.5
Rapid Transit 99 99 - 415 403 3.0
Wholesale 569 517 10.1 2,609 2,311 12.9
-------- -------- ---------- ----------
System 6,168 5,916 4.3 26,612 25,000 6.4
======== ======== ========== ==========
Average System Revenue
----------------------
per KWH (cents per KWH) 7.47 7.42 0.7 6.98 7.01 (0.4)
-----------------------
System Peak Demand
------------------
(Thousands of KW)
Summer - - 5,732 5,660
Winter - - 4,831 4,685
Net Generation
--------------
(Millions of KWH) 4,146 3,877 20,373 16,996
Fuel Mix (% of Btu)
-------------------
Coal (%) 90 93 86 85
Oil (%) 6 1 7 7
Gas (%) 4 6 7 8
Fuel Cost per MBtu
------------------
System Average $1.78 $1.66 $1.77 $1.80
Weather Data
------------
Heating Degree Days 399 333 4,591 3,635
20 Year Average 322 3,978
Cooling Degree Hours 3,446 1,833 13,072 9,363
20 Year Average 2,635 10,986
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.
</FN>
41
</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
A Current Report on Form 8-K was filed by the
Company on April 3, 1996, providing details on the
voting results associated with the approval of the
Merger Agreement by shareholders of the Company at
a special meeting held on March 29, 1996. The item
reported on such Form 8-K was Item 5 (Other
Events).
42
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
July 26, 1996
- -------------
DATE
43
<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 June 30, 1996,
and the twelve months ended December 31, 1995 and 1994:
<CAPTION>
June 30, December 31, December 31,
1996 1995 1994
------------- ------------ ------------
<S> <C> <C> <C>
Average shares outstanding for
computation of primary earnings
per common share 118,493,338 118,412,478 118,005,847
============ ============ ============
Average shares outstanding for
fully diluted computation:
Average shares outstanding 118,493,338 118,412,478 118,005,847
Additional shares resulting from:
Conversion of Serial Preferred
Stock, $2.44 Convertible Series
of 1966 (the "Convertible
Preferred Stock") 36,115 38,255 48,110
Conversion of 7% Convertible
Debentures 2,421,539 2,469,639 2,531,244
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 124,343,492 124,312,872 123,977,701
============ ============ ============
Earnings applicable to common stock $225,515,000 $77,540,000 $210,725,000
Add: Dividends paid or accrued on
Convertible Preferred Stock 15,000 16,000 20,000
Interest paid or accrued on
Convertible Debentures,
net of related taxes 6,420,000 6,475,000 6,537,000
------------ ------------ ------------
Earnings applicable to common stock,
assuming conversion of convertible
securities $231,950,000 $84,031,000 $217,282,000
============ ============ ============
Primary earnings per common share $1.90 $0.65 $1.79
Fully diluted earnings per common share $1.87 $0.68 $1.75
<FN>
The valuation is not required by footnote 2 to paragraph 14 of APB No. 15 for the
the twelve months ended June 30, 1996 and December 31, 1994 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>
44
</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 June
30, 1996, and for each of the preceeding five years on the basis of parent
company operations only, are as follows.
<CAPTION>
Twelve
Months For The Year Ended December 31,
Ended ---------------------------------------------------------
June 30,
1996 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $235,196 $218,788 $208,074 $216,478 $172,599 $186,813
Taxes based on income 142,892 129,439 116,648 107,223 76,965 80,988
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 378,088 348,227 324,722 323,701 249,564 267,801
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 148,069 146,558 139,210 141,393 138,097 138,512
Interest factor in rentals 23,246 23,431 6,300 5,859 6,140 5,690
--------- --------- --------- --------- --------- ---------
Total fixed charges 171,315 169,989 145,510 147,252 144,237 144,202
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $549,403 $518,216 $470,232 $470,953 $393,801 $412,003
========= ========= ========= ========= ========= =========
Coverage of fixed charges 3.21 3.05 3.23 3.20 2.73 2.86
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,673 $16,851 $16,437 $16,255 $14,392 $12,298
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.61 1.59 1.56 1.50 1.45 1.43
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $26,844 $26,793 $25,642 $24,383 $20,868 $17,586
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $198,159 $196,782 $171,152 $171,635 $165,105 $161,788
========= ========= ========= ========= ========= =========
Coverage of combined fixed charges
and preferred dividends 2.77 2.63 2.75 2.74 2.39 2.55
==== ==== ==== ==== ==== ====
45
</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 June
30, 1996, 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 ---------------------------------------------------------
June 30,
1996 1995 1994 1993 1992 1991
--------- --------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Net income before cumulative effect
of accounting change $242,188 $94,391 $227,162 $241,579 $200,760 $210,164
Taxes based on income 86,457 43,731 93,953 62,145 79,481 80,737
--------- --------- --------- --------- --------- ---------
Income before taxes and cumulative effect
of accounting change 328,645 138,122 321,115 303,724 280,241 290,901
--------- --------- --------- --------- --------- ---------
Fixed charges:
Interest charges 238,161 238,724 224,514 221,312 226,453 225,323
Interest factor in rentals 24,796 26,685 9,938 9,257 6,599 6,080
--------- --------- --------- --------- --------- ---------
Total fixed charges 262,957 265,409 234,452 230,569 233,052 231,403
--------- --------- --------- --------- --------- ---------
Nonutility subsidiary capitalized interest (601) (529) (521) (2,059) (2,200) (6,542)
--------- --------- --------- --------- --------- ---------
Income before income taxes, cumulative
effect of accounting change and
fixed charges $591,001 $403,002 $555,046 $532,234 $511,093 $515,762
======== ======== ======== ======== ======== ========
Coverage of fixed charges 2.25 1.52 2.37 2.31 2.19 2.23
==== ==== ==== ==== ==== ====
Preferred dividend requirements $16,673 $16,851 $16,437 $16,255 $14,392 $12,298
--------- --------- --------- --------- --------- ---------
Ratio of pre-tax income to net income 1.36 1.46 1.41 1.26 1.40 1.38
--------- --------- --------- --------- --------- ---------
Preferred dividend factor $22,675 $24,602 $23,176 $20,481 $20,149 $16,971
--------- --------- --------- --------- --------- ---------
Total fixed charges and preferred dividends $285,632 $290,011 $257,628 $251,050 $253,201 $248,374
======== ======== ======== ======== ======== ========
Coverage of combined fixed charges
and preferred dividends 2.07 1.39 2.15 2.12 2.02 2.08
==== ==== ==== ==== ==== ====
July 25, 1996
46
</TABLE>
Exhibit 15
July 26, 1996
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 July 26, 1996, (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, and 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. 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.
47
<TABLE> <S> <C>
<ARTICLE> UT
<SUBSIDIARY>
<NUMBER> 1
<NAME> POTOMAC CAPITAL INVESTMENT CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> JUN-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,386,007
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 494,234
<TOTAL-DEFERRED-CHARGES> 650,530
<OTHER-ASSETS> 1,461,820
<TOTAL-ASSETS> 6,992,591
<COMMON> 118,497
<CAPITAL-SURPLUS-PAID-IN> 1,010,441
<RETAINED-EARNINGS> 711,726
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,840,664
142,500
125,307
<LONG-TERM-DEBT-NET> 1,718,361
<SHORT-TERM-NOTES> 3,540<F1>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 323,975<F1>
<LONG-TERM-DEBT-CURRENT-PORT> 100,000
985
<CAPITAL-LEASE-OBLIGATIONS> 164,113
<LEASES-CURRENT> 20,772
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,552,374
<TOT-CAPITALIZATION-AND-LIAB> 6,992,591
<GROSS-OPERATING-REVENUE> 938,373
<INCOME-TAX-EXPENSE> 45,979
<OTHER-OPERATING-EXPENSES> 753,024
<TOTAL-OPERATING-EXPENSES> 799,003
<OPERATING-INCOME-LOSS> 139,370
<OTHER-INCOME-NET> 18,280
<INCOME-BEFORE-INTEREST-EXPEN> 157,650
<TOTAL-INTEREST-EXPENSE> 70,663
<NET-INCOME> 86,987
8,297
<EARNINGS-AVAILABLE-FOR-COMM> 78,690
<COMMON-STOCK-DIVIDENDS> 98,305
<TOTAL-INTEREST-ON-BONDS> 126,200<F2>
<CASH-FLOW-OPERATIONS> 143,382
<EPS-PRIMARY> $.66
<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 June 30, 1996.
<F3>No material dilution would occur if all the convertible preferred stock and
debentures were converted into common stock.
</FN>
</TABLE>
