UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 1-3382
CAROLINA POWER & LIGHT COMPANY
_______________________________________________________
(Exact name of registrant as specified in its charter)
North Carolina 56-0165465
________________________________________________________________
(State or other jurisdiction of incorporation (I.R.S. Employer
or organization) Identification No.)
411 Fayetteville Street, Raleigh, North Carolina 27601-1748
_____________________________________________________________
(Address of principal executive offices) (Zip Code)
919-546-6111
____________
(Registrant's telephone number, including area code)
_________________________________________________________________
(Former name, former address and former fiscal year, if changed
since last report)
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
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X . No .
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of the latest practicable
date.
Common Stock (Without Par Value) shares outstanding at
October 31, 1994: 156,535,522
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
______ ____________________
Reference is made to the attached Appendix containing the
Interim Financial Statements for the periods ended September 30,
1994. The amounts are unaudited but, in the opinion of management,
reflect all transactions necessary to fairly present the
Company's financial position and results of operations for the
interim periods.
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
______ _________________________________________________
Results of Operations
For the Three, Nine and Twelve Months Ended
September 30, 1994, As Compared With the
Corresponding Periods One Year Earlier
___________________________________________
Operating Revenues and Expenses: Revenues decreased for
the three months ended September 30, 1994, primarily due to weather
that was cooler than normal. In addition, as of July 1994, the
Company has completed recovery of the portion of abandoned plant
costs addressed under a special rider resulting from the 1990
North Carolina Utilities Commission Remand Order. This reduction
in revenue was approximately $17 million for the three months
ended September 30, 1994, and did not significantly impact net
income due to a corresponding decrease in amortization expense.
Fuel for generation decreased for the three, nine and
twelve months ended September 30, 1994, due to a change in the
generation mix. Nuclear generation increased and higher-cost
fossil generation decreased due to greater availability of the
Company's nuclear generating facilities.
In the third quarter of 1994, the Company reached
settlement agreements with regulators and agreed to forgo $8
million of deferred fuel cost. In the third quarter of 1993, the
Company reached settlement agreements with regulators and agreed to
forgo recovery of $41.1 million of deferred fuel cost related to
the Brunswick Plant outage. The net effect of these settlement
agreements resulted in a decrease of $33.1 million in deferred
fuel cost for the three, nine and twelve months ended September
30, 1994, as compared to the same periods ended September 30,
1993. Excluding the effect of these settlements, deferred fuel
cost increased for the three, nine and twelve month periods ended
September 30, 1994, as a result of lower fuel costs associated
with increased nuclear generation and as a result of the
recovery of prior fuel costs as allowed by the North Carolina
fuel adjustment statute.
Purchased power increased for the nine and twelve months
ended September 30, 1994, primarily due to increased purchases from
Duke Power Company (Duke) and North Carolina Eastern Municipal
Power Agency (Power Agency). The increased purchases from Duke of
$29.9 million and $46.2 million for the nine and twelve months
ended September 30, 1994, respectively, are primarily due to an
agreement under which the Company began purchasing 400 megawatts
of generating capacity in July 1993. The increased purchases
from Power Agency of $8.1 million and $12.1 million for the nine
and twelve months ended September 30, 1994, respectively, are
primarily due to the increased buyback provisions of the
Company's April 1993 agreement with Power Agency.
Other operation expense increased for the twelve months
ended September 30, 1994, in part due to adjustments made in the
fourth quarter of 1992 that decreased expenses for the prior twelve
month period. These adjustments were made to certain accrual and
asset balances as a result of more current information at that
time. The remainder of the increase for the twelve months and the
increase for the nine months ended September 30, 1994, is made up
of a number of items, none of which are individually significant.
Maintenance expense decreased for the nine and twelve
months ended September 30, 1994, primarily due to a decrease in
costs associated with the Brunswick Plant. In the prior periods,
significant costs were incurred at the Brunswick Plant as a
result of the Plant's extended outage.
The increase in Harris Plant deferred costs for the
twelve months ended September 30, 1994, includes adjustments
related to the 1993 settlement between the Company and North
Carolina Electric Membership Corporation (NCEMC).
Other Income (Expense): The Harris Plant disallowance -
Power Agency line item reflects a write-off recorded as a result of
the 1993 settlement with Power Agency. The write-off represents a
portion of the Company's Harris Plant costs that will not be
recoverable through sales of supplemental power to Power Agency.
As of January 1994, the Company is no longer recording
interest income related to the qualified employee stock ownership
plan (ESOP) loan (see New Accounting Standard below). This
reduction in interest income is reflected in the three, nine and
twelve months ended September 30, 1994. Interest income also
decreased in these current periods as compared to the prior periods
due to the Company's September 1993 settlement agreement with
Westinghouse Electric Corporation, which increased interest
income in the prior periods. Partially offsetting these decreases
in the nine and twelve month periods was an increase for interest
income recorded in June 1994 that related to certain IRS audit
issues.
Interest Charges: Interest charges on long-term debt
decreased for all periods primarily due to long-term debt
refinancings that allowed the Company to take advantage of lower
interest rates.
Material Changes in Capital Resources and
Liquidity From December 31, 1993, to
September 30, 1994 and From September 30, 1993,
to September 30, 1994
_______________________________________________
During the nine and twelve months ended September 30,
1994, the Company issued long-term debt totaling $272.6 million and
$364.9 million, respectively. These issuances of debt, debt issued
in the third quarter of 1993 and internally generated funds
financed the retirement or redemption of long-term debt totaling
$267.6 million and $532.7 million, respectively.
The Company uses short-term financing in the form of
commercial paper backed by revolving credit agreements to provide
flexibility in the timing and amounts of long-term financing. At
September 30, 1994, the Company had revolving credit facilities
amounting to $207.9 million and $15 million in commercial paper
outstanding.
The Company's First Mortgage Bonds are currently rated
"A2" by Moody's Investors Service, "A" by Standard & Poors and "A+"
by Duff & Phelps. Standard & Poors and Moody's Investors Service
have rated the Company's commercial paper "A-1" and "P-1",
respectively.
The Company's capital structure at September 30, 1994,
was 49.8% common stock equity, 47.5% long-term debt and 2.7%
preferred stock.
In July 1994, the Board of Directors of the Company
(Board) authorized the Executive Committee of the Board to
repurchase up to 10 million shares of the Company's common stock on
the open market. The Board indicated that at current stock price
levels it was in the best interests of the Company's stockholders
for management to have the flexibility to repurchase shares. In
accordance with the stock repurchase program, the Company had
purchased approximately 4.2 million shares through October 31,
1994.
With regard to compliance with Phase II of the 1990
amendments to the Clean Air Act (Act), in order to reduce sulfur
dioxide emissions, the Company will modify equipment to allow
certain of the Company's plants to burn lower-sulfur coal, and the
Company is planning for the installation of scrubbers. Installation
of additional equipment will also be necessary to reduce nitrogen
oxides emissions. The Company anticipates that it will be able to
delay the installation and operation of scrubbers until 2005 by
using sulfur dioxide emission allowances. The Company purchased
emission allowances under the Environmental Protection Agency's
emission allowance trading program in 1993 and 1994. The Company
estimates that the total capital cost to comply with Phase II of
the Act will approximate $278 million during the period 1994
through 1999 and an additional $370 million during the period
2000 through 2005. These estimates, for installation or
modification of equipment, are in nominal dollars (undiscounted
future amounts expected to be expended). The required
modifications and additions are expected to increase operating
and maintenance costs by a total of $20 million for the period
1994 through 1999, $53 million for the period 2000 through 2004
and by $40 million beginning in 2005. Additionally, fuel costs
are expected to increase by a total of approximately $160 million
for the period 2000 through 2004 and by approximately $55 million
beginning in 2005. The Company expects these increased fuel costs
to be recoverable through applicable fuel adjustment statutes.
Actual plans for compliance with the Act's requirements have not
been finalized and the amount required for capital expenditures
and for increased operating, maintenance and fuel expenditures
cannot be determined with certainty at this time. The financial
impact of additional expenditures will be dependent on future
ratemaking treatment. The North Carolina Utilities Commission and
the South Carolina Public Service Commission are currently
allowing the Company to accrue carrying charges on its investment
in emission allowances.
New Accounting Standard
_______________________
In January 1994, the Company implemented Statement of
Position (SOP) 93-6, "Employers' Accounting for Stock Ownership
Plans," on a prospective basis. This SOP requires the following
changes in accounting for the Company's leveraged employee stock
ownership plan: 1) ESOP shares that have not been committed to be
released to participants' accounts are no longer considered
outstanding for the determination of earnings per common share; 2)
dividends on unallocated ESOP shares are no longer recognized for
financial statement purposes; 3) all tax benefits of ESOP dividends
are now recorded directly to non-operating income tax expense,
whereas previously a portion of the tax benefits was recorded
directly to retained earnings; 4) interest income related to the
qualified ESOP loan is no longer recognized; and 5) the difference
between the acquisition and allocation prices of ESOP shares, which
was previously recorded as other income, net, is now recorded
directly to common stock. In addition, ESOP loan transactions
between the Company and the Stock Purchase-Savings Plan Trustee
are no longer reflected in the Statements of Cash Flows. The
implementation of SOP 93-6 resulted in an increase in earnings
per common share of approximately $.03 for the three and twelve
months ended September 30, 1994, and $.04 for the nine months
ended September 30, 1994.
Legal Matters
_____________
In September 1994, NCEMC withdrew the Complaint it had
filed with the Federal Energy Regulatory Commission, which had
alleged that the wholesale rates the Company charges NCEMC are
excessive.
Environmental Matters
_____________________
With regard to manufactured gas plant (MGP) sites in
North Carolina, the Company has recently been approached by another
North Carolina public utility concerning a possible cost-sharing
arrangement with respect to the investigation and, if necessary,
remediation of four MGP sites. The Company is currently engaged
in discussions with the other utility regarding this matter.
Based on current cost estimates provided by that utility, the
Company does not believe its portion of costs associated with the
investigation and remediation of these sites, if any, would be
material to the financial position or results of operations of
the Company.
In addition, a current owner of property that was the
site of one MGP owned by Tidewater Power Company (Tidewater Power),
which merged into the Company in 1952, has been party to a separate
administrative proceeding regarding that site. That owner and the
Company have entered into an agreement to share the cost of
investigation and remediation of this site. The Company has also
been approached by a North Carolina municipality that is the
current owner of another MGP site that was formerly owned by
Tidewater Power. The Company is engaged in discussions with that
municipality concerning a possible cost-sharing arrangement with
respect to the investigation and, if necessary, the remediation
of that site. Due to the uncertainty concerning potential
environmental harm and the full extent to which remedial action
will be required at the two sites formerly owned by Tidewater
Power, the total cost of investigating and remediating these
sites is not determinable at this time. The Company cannot
predict the outcome of these matters.
The Company is continuing its investigation regarding the
identities of parties connected to individual MGP sites, the
relative relationships of the Company and other parties to those
sites, and the degree, if any, to which the Company should
undertake shared voluntary efforts with others at individual
sites. Except as noted above, due to the lack of information with
respect to the operation of MGP sites and the uncertainty
concerning questions of liability and potential environmental
harm, the extent and cost of required remedial action, if any,
and the extent to which liability may be asserted against the
Company or against others are not currently determinable. The
Company cannot predict the outcome of these matters or the extent
to which other former MGP sites may become the subject of
inquiry.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
_______ _________________
Legal aspects of certain matters are set forth in Item 5 below.
Item 2. Changes in Securities )
_______ _____________________ )
)
Item 3. Defaults upon Senior Securities ) Not applicable
_______ _______________________________ ) for the quarter
) ended September
) 30, 1994.
Item 4. Submission of Matters to a Vote )
of Security Holders )
_______ _______________________________ )
)
Item 5. Other Information
_______ _________________
1. (Reference is made to the Company's 1993 Form 10-K,
Competition and Franchises, paragraph 1.b., page 7. Reference is
also made to the Company's Form 10-Q for the quarter ended June
30, 1994, Item 5, paragraph 3.) With regard to the application
the Company filed with the North Carolina Utilities Commission
(NCUC) on June 20, 1994 requesting permission to change the rate
it was charging AlliedSignal Inc. (Allied) for approximately 16
MW of electricity provided to Allied's Moncure, North Carolina
facility, on September 13, 1994, the Company amended its
application to revise the proposed rate and reduce the term of
its availability. The proposed rate provides value that is
consistent with the value Allied would realize if it opted to
obtain service by self-generating 11 MW of the electricity
required at this facility. By order issued October 3, 1994, the
NCUC approved the amended application. As a result, the Company
will serve all of Allied's electrical requirements at the new
rate for five years. Thereafter, the new rate will terminate;
however, the Company will continue to serve all of Allied's
electrical requirements unless one of the parties terminates the
existing electrical service agreement between them.
2. (Reference is made to the Company's 1993 Form 10-K,
Competition and Franchises, paragraph 1.b., page 7.) By order
issued September 30, 1994, the South Carolina Public Service
Commission (SCPSC) established a docket for a generic proceeding
to consider the effect of electric and natural gas demand side
management programs on competition between the two types of
utilities. The order states that the outcome of such a
proceeding will not apply to the 1995 integrated resource plans
that electric utilities file with the SCPSC. The Company cannot
predict the outcome of this matter.
3. (Reference is made to the Company's 1993 Form 10-K, Retail
Rate Matters, paragraph 5, page 12. Reference is also made to
the Company's Form 10-Q for the quarter ended June 30, 1994, Item
5, paragraph 5.) With regard to the North Carolina retail
jurisdiction, the stipulations agreed to by the parties to the
Company's 1994 North Carolina fuel case were approved by the NCUC
by order dated September 6, 1994. The stipulations resolved all
issues between the parties to the proceeding. Pursuant to the
stipulations, the parties agreed that a net fuel factor of 1.309
cents/kWh will be in effect for the Company for the period
September 15, 1994 through September 14, 1995. As part of the
stipulations, the Company agreed to forgo recovering $5.8 million
of the underrecovered fuel expense for the test year ended March
31, 1994. Of this amount, $3.5 million is associated with
certain outage time experienced by the Company's Robinson Nuclear
Plant, and the remaining $2.3 million relates to the recovery of
certain cogeneration fuel costs.
With regard to the South Carolina retail jurisdiction, the
Company's fall 1994 South Carolina fuel case hearing was
scheduled to commence on September 19, 1994; however, on
September 15, 1994, the SCPSC approved a settlement agreement
that resolved all issues between all parties to the proceeding.
Pursuant to the settlement, the Company agreed to a $2.2 million
reduction of its fuel cost underrecovery account in return for a
fuel factor of 1.400 cents/kWh for the six month period October
1, 1994 through March 31, 1995, and for Nucor Steel (Nucor)
agreeing to dismiss its September 8, 1993, appeal of the SCPSC's
decision to reaffirm its earlier orders to exclude certain
testimony offered by Nucor in the Company's fall 1990 South
Carolina fuel case.
4. (Reference is made to the Company's 1993 Form 10-K, Wholesale
Rate Matters, paragraph 2.a., page 14. Reference is also made to
the Company's Form 10-Q for the quarter ended June 30, 1994, Item
5, paragraph 7.) With regard to the proceeding initiated by
North Carolina Electric Membership Corporation (NCEMC) and one of
its members before the Federal Energy Regulatory Commission
(FERC) on April 12, 1991, Docket No. EL91-28-000, alleging that
the Company's wholesale rates and fuel clause billings were
excessive and requesting that the Company provide its real-time
load signal to NCEMC, on October 24, 1994, the FERC approved the
settlement agreement between the Company and the City of
Fayetteville's Public Works Commission (Fayetteville PWC), an
intervenor in the NCEMC case, which resolves, as between them,
all wholesale fuel clause billings issues through December 31,
1993. Amounts associated with the settlement do not have a
material impact on the results of operations of the Company.
Also on October 24, 1994, the FERC approved the settlement
agreement between the Company and the intervenor that remained a
party to the NCEMC-initiated proceeding. Amounts associated with
the settlement do not have a material impact on the results of
operations of the Company. The FERC's approval of these
settlement agreements concludes this proceeding.
With regard to the Complaint NCEMC filed with the FERC, Docket
No. EL94-84-000, under Section 206 of the Federal Power Act on
August 1, 1994, alleging that the wholesale rates the Company
charges NCEMC are excessive, and seeking a rate reduction of
approximately $38.6 million per year, on September 23, 1994,
NCEMC withdrew the Complaint.
5. (Reference is made to the Company's 1993 Form 10-K, Wholesale
Rate Matters, paragraph 3, page 15. Reference is also made to
the Company's Form 10-Q for the quarter ended June 30, 1994, Item
5, paragraph 12.) With regard to the new power supply agreement
the Company and the Town of Waynesville entered into on July 26,
1994, the FERC approved the agreement on September 13, 1994, with
an effective date of October 2, 1994.
6. (Reference is made to the Company's 1993 Form 10-K, Wholesale
Rate Matters, paragraph 3.c., page 16. Reference is also made to
the Company's Form 10-Q for the quarter ended June 30, 1994, Item
5, paragraph 11.) With regard to the change the FERC required to
the new power supply and coordination agreement the Company and
the Fayetteville PWC entered into on March 10, 1994, the
compliance filing the Company and the Fayetteville PWC made to
effectuate the change was accepted by the FERC on August 12,
1994. On October 24, 1994, the FERC approved the settlement
agreement between the Fayetteville PWC and the Company which
resolves all wholesale fuel clause billing issues between them
through December 31, 1993. See Item 5, paragraph 4 for a
discussion of the settlement agreement.
7. (Reference is made to the Company's 1993 Form 10-K,
Environmental Matters, paragraph 2, page 16.) With regard to the
Company's plans for compliance with the Clean Air Act's (Act)
Phase II requirements, in order to reduce sulfur dioxide
emissions, the Company will modify equipment to allow certain of
the Company's plants to burn lower-sulfur coal, and the Company
is planning for the installation of scrubbers. Installation of
additional equipment will also be necessary to reduce nitrogen
oxides emissions. The Company anticipates that it will be able
to delay the installation and operation of scrubbers until 2005
by using sulfur dioxide emission allowances. The Company
purchased emission allowances under the Environmental Protection
Agency's emission allowance trading program in 1993 and 1994.
The Company now estimates that the total capital cost to comply
with Phase II of the Act will approximate $278 million during the
period 1994 through 1999 and an additional $370 million during
the period 2000 through 2005. These estimates are in nominal
dollars (undiscounted future amounts expected to be expended.)
The required modifications and additions are expected to
increase operating and maintenance costs by a total
of $20 million for the period 1994 through 1999, $53 million
for the period 2000 through 2004 and by $40 million beginning
in 2005. Additionally, fuel costs are expected to increase by
a total of approximately $160 million for the period 2000 through
2004, and by approximately $55 million beginning in 2005. The
Company expects these increased fuel costs to be recoverable
through applicable fuel adjustment statutes. Actual plans for
compliance with the Act's requirements have not been finalized
and the amount required for capital expenditures and for
increased operating, maintenance and fuel expenditures cannot be
determined with certainty at this time. The financial impact of
additional expenditures will be dependent on future ratemaking
treatment. The NCUC and the SCPSC are currently allowing the
Company to accrue carrying charges on its investment in emission
allowances. The Company cannot predict the outcome of this
matter.
8. (Reference is made to the Company's 1993 Form 10-K,
Environmental Matters, paragraph 3.e., page 18.) With regard to
the Seaboard Chemical Corporation (Seaboard) hazardous waste
disposal site in Jamestown, North Carolina, the North Carolina
Department of Environment, Health and Natural Resources (DEHNR)
has indicated that it is seeking to have further remedial
activities performed at the Seaboard site. The Company recently
joined the Seaboard Group II (a group of potentially responsible
parties formed to conduct additional work at the Seaboard site).
Cost estimates for the additional work are not available. The
Company cannot predict the outcome of this matter.
9. (Reference is made to the Company's 1993 Form 10-K,
Environmental Matters, paragraph 4, page 19.) With regard to
manufactured gas plant (MGP) sites in North Carolina, the Company
has recently been approached by another North Carolina public
utility concerning a possible cost-sharing arrangement with
respect to the investigation and, if necessary, remediation of
four MGP sites. The Company is currently engaged in discussions
with the other utility regarding this matter. Based on current
cost estimates provided by that utility, the Company does not
believe its portion of costs associated with the investigation
and remediation of these sites, if any, would be material to the
financial position or results of operations of the Company.
In addition, a current owner of property that was the site of
one MGP owned by Tidewater Power Company (Tidewater Power), which
merged into the Company in 1952, has been party to a separate
administrative proceeding regarding that site. That owner and
the Company have entered into an agreement to share the cost of
investigation and remediation of this site. The Company has also
been approached by a North Carolina municipality that is the
current owner of another MGP site that was formerly owned by
Tidewater Power. The Company is engaged in discussions with that
municipality concerning a possible cost-sharing arrangement with
respect to the investigation and, if necessary, the remediation
of that site. Due to the uncertainty concerning potential
environmental harm and the full extent to which remedial action
will be required at the two sites formerly owned by Tidewater
Power, the total cost of investigating and remediating these
sites is not determinable at this time. The Company cannot
predict the outcome of these matters.
The Company is continuing its investigation regarding the
identities of parties connected to individual MGP sites, the
relative relationships of the Company and other parties to those
sites, and the degree, if any, to which the Company should
undertake shared voluntary efforts with others at individual
sites. Except as noted above, due to the lack of information
with respect to the operation of MGP sites and the uncertainty
concerning questions of liability and potential environmental
harm, the extent and cost of required remedial action, if any,
and the extent to which liability may be asserted against the
Company or against others are not currently determinable. The
Company cannot predict the outcome of these matters or the extent
to which other former MGP sites may become the subject of
inquiry.
10. (Reference is made to the Company's 1993 Form 10-K, Nuclear
Matters, paragraph 7.e., page 24. Reference is also made to the
Company's Form 10-Q for the quarter ended March 31, 1994, Item 5,
paragraph 8 and to the Company's Form 10-Q for the quarter ended
June 30, 1994, Item 5, paragraph 16.) By letter dated August 30,
1994, the Nuclear Regulatory Commission (NRC) issued a Notice of
Violation and Imposition of Civil Penalty in the amount of
$75,000 involving the Company's testing of certain ventilation
equipment at its H.B. Robinson Plant. The Notice also indicated
that activities related to the adequacy of corrective action on
issues identified by a contractor and the adequacy of corrective
actions on a design concern involving an isolation valve
constituted violations of NRC requirements; however, no civil
penalty was assessed in connection with those violations. By
letter dated September 29, 1994, the Company responded to the
Notice of Violation and paid the assessed penalty.
11. (Reference is made to the Company's 1993 Form 10-K,
Other Matters, page 27.) On November 4, 1994, the Company filed a
complaint against SMC Mining Company, Wolf Creek Collieries
Company and Kermit Coal Company (the Sellers) in the United
States District Court for the Eastern District of North Carolina
(Civil Action No. 5:94-CV-846-BO(2)). The Sellers are all companies
owned by Zeigler Coal Holding Company. Under the terms of a 1971
contract, as amended, the Sellers are to supply the Company with
coal having certain qualities and characteristics from the Wolf
Creek mine (Wolf Creek) in Kentucky. The contract provides that
the Company has the right to refuse to accept further deliveries
from the Sellers if the coal they ship fails to meet the specification
for sulfur content for two consecutive months. During the months of
August and September 1994, the Sellers shipped to the Company Wolf Creek
coal which did not meet the sulfur specifications provided in the
contract. As a result of the Sellers' shipment of non-complying coal,
on November 4, 1994, the Company exercised its right to suspend
future shipments of coal from Wolf Creek until the Sellers can give
the Company reasonable assurance that future shipments will meet
the contract's specifications. The Complaint asks the court to
determine whether the dispute is subject to arbitration and that
the Company's suspension of future shipments from the Sellers was
legal. On November 4, 1994, the Sellers filed a Complaint against the
Company in the Circuit Court of Martin County, Kentucky (Civil Action
No. 94-CZ-00212), asking the court to restrain the Company from
refusing to accept future shipments of coal under the 1971 contract.
On November 4, 1994, the court issued an ex parte temporary restraining
order (TRO) which prevents the Company, for the time being, from
refusing contract coal deliveries from Wolf Creek. The Company has
removed the Kentucky state court action to the United States District
Court for the Eastern District of Kentucky. On November 9, 1994,
the Company filed in the Kentucky federal court a response to the
state court's TRO. The response seeks to dissolve the TRO, which would
allow the Company to refuse coal shipments from Wolf Creek until the dispute
is settled. In its response, the Company also moved for transfer of the
case to the United States District Court for the Eastern District of
North Carolina. A hearing on these motions is scheduled for November 14,
1994 in Pikeville, Kentucky. Whatever the outcome of this dispute, the
Company anticipates no problems in ensuring sufficient coal supplies for
its plants. The Company cannot predict the outcome of this matter.
Item 6. Exhibits and Reports on Form 8-K
_______ ________________________________
(a) Exhibits
None.
(b) Reports on Form 8-K filed during or with respect to the
quarter
None.
SIGNATURES
Pursuant to 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.
CAROLINA POWER & LIGHT COMPANY
(Registrant)
By: Charles D. Barham, Jr.
Executive Vice President
By: Paul S. Bradshaw
Vice President and Controller
(and Principal Accounting
Officer)
Date: November 9, 1994
<TABLE>
APPENDIX
Carolina Power & Light Company
(ORGANIZED UNDER THE LAWS OF NORTH CAROLINA)
INTERIM FINANCIAL STATEMENTS
(NOT AUDITED BY INDEPENDENT AUDITORS)
SEPTEMBER 30, 1994
<CAPTION>
STATEMENTS OF INCOME
(In thousands Three Months Ended Nine Months Ended Twelve Months Ended
except per share amounts) ------------------ ----------------- -------------------
September 30 September 30 September 30
------------ ------------ ------------
1994 1993 1994 1993 1994 1993
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues....................................$ 805,552 $ 854,750 $ 2,237,323 $ 2,236,826 $ 2,895,880 $ 2,899,850
--------- --------- ----------- ----------- ----------- -----------
Operating Expenses
Operation - fuel for generation..................... 126,692 152,354 378,109 401,183 501,291 531,937
deferred fuel cost, net................. 28,626 36,984 20,411 33,810 13,965 24,707
purchased power......................... 102,483 112,241 319,838 272,315 415,615 352,196
other................................... 130,305 123,412 400,375 363,794 534,913 463,170
Maintenance......................................... 38,719 45,386 149,455 173,942 210,962 264,114
Depreciation and amortization....................... 97,025 99,849 311,227 306,981 417,892 404,086
Taxes other than on income.......................... 36,997 37,346 109,264 104,718 147,416 134,772
Income tax expense.................................. 82,433 81,332 163,743 168,716 184,345 199,767
Harris Plant deferred costs, net.................... 6,476 6,418 19,648 16,709 30,515 20,400
--------- --------- ----------- ----------- ----------- -----------
Total Operating Expenses...................... 649,756 695,322 1,872,070 1,842,168 2,456,914 2,395,149
--------- --------- ----------- ----------- ----------- -----------
Operating Income...................................... 155,796 159,428 365,253 394,658 438,966 504,701
--------- --------- ----------- ----------- ----------- -----------
Other Income (Expense)
Allowance for equity funds used during construction. 1,660 2,520 5,761 6,431 8,330 9,087
Income tax credit (expense) (Note 2)................ 2,886 (2,723) 5,375 (3,592) 8,575 (4,102)
Harris Plant carrying costs......................... 2,398 6,556 7,443 11,682 22,904 13,884
Harris Plant disallowance - Power Agency............ - (20,645) - (20,645) - (20,645)
Interest income (Note 2)............................ 2,329 18,278 13,731 30,937 18,990 37,410
Other income, net (Note 2).......................... 5,586 9,056 19,601 29,948 32,115 39,187
--------- --------- ----------- ----------- ----------- -----------
Total Other Income............................ 14,859 13,042 51,911 54,761 90,914 74,821
--------- --------- ----------- ----------- ----------- -----------
Income Before Interest Charges........................ 170,655 172,470 417,164 449,419 529,880 579,522
--------- --------- ----------- ----------- ----------- -----------
Interest Charges
Long-term debt...................................... 45,828 51,693 139,793 158,412 186,563 212,726
Other interest charges.............................. 5,655 3,867 13,392 12,647 17,163 18,477
Allowance for borrowed funds used
during construction............................... (1,081) (1,732) (3,313) (4,264) (5,010) (5,154)
--------- --------- ----------- ----------- ----------- -----------
Net Interest Charges......................... 50,402 53,828 149,872 166,795 198,716 226,049
--------- --------- ----------- ----------- ----------- -----------
Net Income............................................ 120,253 118,642 267,292 282,624 331,164 353,473
Preferred Stock Dividend Requirements................. (2,402) (2,402) (7,206) (7,206) (9,609) (7,548)
Tax Benefit of ESOP Dividends......................... - - - - - 3,552
--------- --------- ----------- ----------- ----------- -----------
Earnings for Common Stock.............................$ 117,851 $ 116,240 $ 260,086 $ 275,418 $ 321,555 $ 349,477
========= ========= =========== =========== =========== ===========
Average Common Shares
Outstanding (Notes 2 and 3)......................... 149,416 160,737 150,426 160,737 153,025 160,737
Earnings per Common Share (Notes 2 and 3).............$ 0.79 $ 0.72 $ 1.73 $ 1.71 $ 2.10 $ 2.17
Dividends Declared per Common Share...................$ 0.425 $ 0.410 $ 1.275 $ 1.230 $ 1.700 $ 1.640
- ------------------
See Supplemental Data and Notes to Financial Statements.
</TABLE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
BALANCE SHEETS September 30 December 31
(In thousands) ------------ -----------
1994 1993 1993
---- ---- ----
ASSETS
<S> <C> <C> <C>
Electric Utility Plant
Electric utility plant in service......................$ 9,076,667 $ 8,712,154 $ 8,789,518
Accumulated depreciation............................... (3,132,176) (2,833,044) (2,897,832)
------------ ------------ ------------
Electric utility plant in service, net.......... 5,944,491 5,879,110 5,891,686
Held for future use.................................... 13,222 13,284 13,300
Construction work in progress.......................... 193,286 282,252 309,713
Nuclear fuel, net of amortization...................... 181,399 209,291 217,488
------------ ------------ ------------
Total Electric Utility Plant, Net............... 6,332,398 6,383,937 6,432,187
------------ ------------ ------------
Current Assets
Cash and cash equivalents.............................. 48,419 160,876 23,607
Accounts receivable.................................... 314,790 367,595 321,309
Fuel................................................... 71,439 74,207 62,029
Materials and supplies................................. 121,934 113,493 111,052
Prepayments............................................ 41,233 44,474 46,869
Other current assets................................... 26,896 18,787 18,591
------------ ------------ ------------
Total Current Assets............................ 624,711 779,432 583,457
------------ ------------ ------------
Deferred Debits and Other Assets
Income taxes recoverable
through future rates.................................. 381,981 372,170 385,515
Abandonment costs...................................... 75,237 153,698 125,361
Harris Plant deferred costs............................ 132,194 138,666 144,399
Unamortized debt expense............................... 64,567 61,672 63,898
Miscellaneous other property and investments........... 313,766 235,554 264,165
Other assets and deferred debits....................... 190,651 176,935 185,209
------------ ------------ ------------
Total Deferred Debits and Other Assets.......... 1,158,396 1,138,695 1,168,547
------------ ------------ ------------
Total Assets.................................$ 8,115,505 $ 8,302,064 $ 8,184,191
============ ============ ============
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity....................................$ 2,627,338 $ 2,632,999 $ 2,632,116
Preferred stock - redemption not required.............. 143,801 143,801 143,801
Long-term debt, net.................................... 2,502,893 2,505,043 2,584,903
------------ ------------ ------------
Total Capitalization............................ 5,274,032 5,281,843 5,360,820
------------ ------------ ------------
Current Liabilities
Current portion of long-term debt...................... 252,050 427,630 162,630
Notes payable (principally commercial paper)........... 15,000 5,000 76,000
Accounts payable....................................... 133,691 190,077 293,093
Taxes accrued.......................................... 155,901 123,028 20,913
Interest accrued....................................... 50,969 58,380 54,770
Dividends declared (Note 2)............................ 70,207 70,706 74,111
Deferred fuel credit (cost)............................ 10,584 (3,381) (9,827)
Other current liabilities.............................. 65,696 49,880 67,510
------------ ------------ ------------
Total Current Liabilities....................... 754,098 921,320 739,200
------------ ------------ ------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes...................... 1,586,643 1,556,116 1,585,490
Accumulated deferred investment tax credits............ 254,935 266,546 263,588
Other liabilities and deferred credits................. 245,797 276,239 235,093
------------ ------------ ------------
Total Deferred Credits and Other Liabilities.... 2,087,375 2,098,901 2,084,171
------------ ------------ ------------
Commitments and Contingencies (Note 4)
Total Capitalization and Liabilities.........$ 8,115,505 $ 8,302,064 $ 8,184,191
============ ============ ============
SCHEDULES OF COMMON STOCK EQUITY
(In thousands)
Common stock...........................................$ 1,534,029 $ 1,622,277 $ 1,622,277
Unearned ESOP common stock............................. (206,654) (225,409) (220,725)
Capital stock issuance expense......................... (790) (334) (790)
Retained earnings...................................... 1,300,753 1,236,465 1,231,354
------------ ------------ ------------
Total Common Stock Equity.......................$ 2,627,338 $ 2,632,999 $ 2,632,116
============ ============ ============
---------------------
See Supplemental Data and Notes to Financial Statements.
</TABLE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
STATEMENTS OF CASH FLOWS
(In thousands)
Three Months Ended Nine Months Ended Twelve Months Ended
------------------ ----------------- -------------------
September 30 September 30 September 30
------------ ------------ ------------
1994 1993 1994 1993 1994 1993
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Operating Activities
Net income............................................... $ 120,253 $ 118,642 $ 267,292 $ 282,624 $ 331,164 $ 353,473
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and amortization.......................... 126,173 106,355 378,577 335,542 503,129 439,648
Harris Plant deferred costs............................ 4,078 (138) 12,205 5,027 7,611 6,516
Harris Plant disallowance - Power Agency .............. - 20,645 - 20,645 - 20,645
Deferred income taxes.................................. (5,578) 19,611 (4,771) 33,590 32,993 78,060
Investment tax credit adjustments...................... (2,884) (4,061) (8,653) (9,848) (11,612) (12,258)
Allowance for equity funds used during construction.... (1,660) (2,520) (5,761) (6,431) (8,330) (9,087)
Deferred fuel cost .................................... 28,626 36,984 20,411 33,810 13,965 24,707
Net decrease (increase) in receivables, inventories
and prepaid expenses................................. 19,246 (7,482) (50,068) (76,974) 19,103 (110,589)
Net increase (decrease) in payables and accrued
expenses............................................. 25,565 22,904 (1,234) (12,639) (50,608) (147)
Miscellaneous.......................................... 2,983 (10,707) 15,512 27,831 (1,438) 530
------- ------- ------- ------- ------- -------
Net Cash Provided by Operating Activities............. 316,802 300,233 623,510 633,177 835,977 791,498
------- ------- ------- ------- ------- -------
Investing Activities
Gross property additions................................. (63,935) (86,922) (191,876) (230,390) (302,609) (319,505)
Nuclear fuel additions................................... (9,520) (2,546) (30,726) (28,489) (50,238) (32,466)
Contributions to external decommissioning trust.......... (4,746) (3,780) (18,461) (11,086) (28,253) (15,285)
Contributions to retiree benefit trusts.................. - (1,250) (16,000) (2,500) (17,250) (9,167)
Loan transactions with SPSP Trustee, net (Note 2)........ - 6,884 - 12,009 9,125 21,160
Allowance for equity funds used during construction...... 1,660 2,520 5,761 6,431 8,330 9,087
------- ------- ------- ------- ------- -------
Net Cash Used in Investing Activities................. (76,541) (85,094) (251,302) (254,025) (380,895) (346,176)
------- ------- ------- ------- ------- -------
Financing Activities
Proceeds from issuance of long-term debt................. - 242,018 268,325 537,269 313,086 636,120
Net decrease in pollution control bond escrow............ - - - 2,127 - 2,693
Net increase (decrease) in short-term notes
payable (maturity less than 90 days)................... (57,600) (25,900) (61,000) (41,800) 10,000 3,000
Retirement of long-term debt............................. (138) (234,723) (268,377) (521,783) (536,970) (622,075)
Purchase of Company common stock (Note 3)................ (86,732) - (86,732) - (86,732) -
Retirement of preferred stock............................ - - - - - (95,950)
Dividends paid on common stock (Note 2).................. (64,226) (65,902) (192,398) (197,706) (257,441) (261,197)
Dividends paid on preferred stock........................ (2,400) (2,402) (7,214) (7,206) (9,482) (11,669)
------- ------- ------- ------- ------- -------
Net Cash Used in Financing Activities................. (211,096) (86,909) (347,396) (229,099) (567,539) (349,078)
------- ------- ------- ------- ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents....... 29,165 128,230 24,812 150,053 (112,457) 96,244
Cash and Cash Equivalents at Beginning of the Period....... 19,254 32,646 23,607 10,823 160,876 64,632
------- ------- ------- ------- ------- -------
Cash and Cash Equivalents at End of the Period............. $ 48,419 $ 160,876 $ 48,419 $ 160,876 $ 48,419 $ 160,876
======= ======= ======= ======= ======= =======
Supplemental Disclosures of Cash Flow Information
Cash paid during the period - interest................... $ 52,719 $ 56,518 $ 148,349 $ 167,160 $ 199,990 $ 227,588
income taxes............... 22,736 40,393 75,461 70,645 118,339 105,402
- --------------------
See Supplemental Data and Notes to Financial Statements.
</TABLE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
SUPPLEMENTAL DATA Three Months Ended Nine Months Ended Twelve Months Ended
------------------ ----------------- -------------------
September 30 September 30 September 30
------------ ------------ ------------
1994 1993 1994 1993 1994 1993
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues (in thousands)
Residential............................. $ 263,677 $ 292,377 $ 716,067 $ 732,404 $ 927,361 $ 938,218
Commercial.............................. 165,008 170,233 458,325 453,053 598,245 585,423
Industrial.............................. 197,282 197,708 556,828 556,678 744,165 735,232
Government and municipal................ 20,815 21,355 59,913 59,716 78,813 77,668
Wholesale - standard rate schedules..... 99,660 113,970 282,323 282,161 354,083 366,158
Power Agency contract requirements...... 33,565 43,903 101,330 114,168 121,421 148,062
Other utilities......................... 14,121 4,285 29,762 8,807 32,186 9,513
Miscellaneous revenue................... 11,424 10,919 32,775 29,839 39,606 39,576
--------- ---------- ---------- ---------- ---------- -----------
Total Operating Revenues.......... $ 805,552 $ 854,750 $2,237,323 $2,236,826 $2,895,880 $2,899,850
========= ========== ========== ========== ========== ===========
Energy Sales (millions of kWh)
Residential............................. 3,029 3,327 8,675 8,822 11,251 11,349
Commercial.............................. 2,453 2,485 6,671 6,548 8,672 8,466
Industrial.............................. 3,585 3,633 10,378 10,063 13,872 13,413
Government and municipal................ 359 356 969 954 1,263 1,230
Wholesale - standard rate schedules..... 1,972 2,118 5,299 5,291 6,930 6,800
Power Agency contract requirements...... 664 986 2,115 2,843 2,777 3,796
Other utilities......................... 465 91 799 246 879 270
--------- ---------- ---------- ---------- ---------- -----------
Total Energy Sales................ 12,527 12,996 34,906 34,767 45,644 45,324
========= ========== ========== ========== ========== ===========
Energy Supply (millions of kWh)
Generated - coal........................ 5,492 7,212 17,341 19,537 23,611 26,551
nuclear..................... 5,730 4,027 12,782 10,775 15,698 12,778
hydro....................... 192 80 728 666 846 933
combustion turbines......... 2 54 68 85 66 93
Purchased............................... 1,764 2,184 5,580 5,232 7,459 6,895
--------- ---------- ---------- ---------- ---------- -----------
Total Energy Supply
(Company Share)................. 13,180 13,557 36,499 36,295 47,680 47,250
========= ========== ========== ========== ========== ===========
Detail of Income Taxes (in thousands)
Included in Operating Expenses
Income tax expense - current............ $ 96,224 $ 71,271 $ 185,305 $ 154,355 $ 169,572 $ 146,649
Income tax expense - deferred........... (10,907) 14,122 (12,909) 24,209 25,191 65,376
Income tax expense - investment
tax credit adjustments................ (2,884) (4,061) (8,653) (9,848) (10,418) (12,258)
--------- ---------- ---------- ---------- ---------- -----------
Subtotal.......................... 82,433 81,332 163,743 168,716 184,345 199,767
--------- ---------- ---------- ---------- ---------- -----------
Harris Plant deferred costs - deferred... - - - - - (414)
Harris Plant deferred costs -
investment tax credit adjustments...... (74) 63 (223) (26) 21 (92)
--------- ---------- ---------- ---------- ---------- -----------
Subtotal.......................... (74) 63 (223) (26) 21 (506)
--------- ---------- ---------- ---------- ---------- -----------
Total Included in Operating Expenses.... 82,359 81,395 163,520 168,690 184,366 199,261
--------- ---------- ---------- ---------- ---------- -----------
Included in Other Income
Income tax expense (credit) - current... (8,215) (2,766) (13,513) (5,789) (15,183) (8,582)
Income tax expense - deferred........... 5,329 5,489 8,138 9,381 7,802 12,684
Income tax expense - investment
tax credit adjustments................ - - - - (1,194) -
--------- ---------- ---------- ---------- ---------- -----------
Subtotal.......................... (2,886) 2,723 (5,375) 3,592 (8,575) 4,102
Harris Plant carrying costs - deferred.. - - - - - 403
Other income, net - deferred............ - - - - - 10
--------- ----------------------- ---------- ---------- -----------
Total Included in Other Income.... (2,886) 2,723 (5,375) 3,592 (8,575) 4,515
--------- ----------------------- ---------- ---------- -----------
Included in Interest Charges
Allowance for borrowed funds used
during construction - deferred....... - - - - - 565
--------- ---------- ---------- ---------- ---------- -----------
Total Income Tax Expense...... $ 79,473 $ 84,118 $ 158,145 $ 172,282 $ 175,791 $ 204,341
========= ========== ========== ========== ========== ===========
<CAPTION>
FINANCIAL STATISTICS September 30, 1994 September 30, 1993
------------------ ------------------
Actual Pro Forma Actual Pro Forma
------ --------- ------ ---------
(Note 2) (Note 2)
<S> <C> <C> <C> <C>
Ratio of earnings to fixed charges........ 3.29 3.46 3.23 3.40
Return on average common stock equity..... 12.07% 11.13% 13.54% 12.42%
Book value per common share (Note 2)...... $ 17.77 N/A $ 17.78 N/A
Capitalization ratios
Common stock equity................... 49.82% 53.75% 49.85% 54.12%
Preferred stock - redemption 2.72 2.73 2.72 2.72
not required......................... 47.46 43.52 47.43 43.16
Long-term debt, net................... ------------ ---------- ---------- ---------
100.00% 100.00% 100.00% 100.00%
Total......................... ============ ========== ========== =========
- ----------------------------
See Notes to Financial Statements.
</TABLE>
Carolina Power & Light Company
NOTES TO FINANCIAL STATEMENTS
1. Except as described in Note 2 below, these interim financial statements
are prepared in conformity with the accounting principles reflected in
the financial statements included in the Company's 1993 Annual Report to
Shareholders and the 1993 Annual Report on Form 10-K. These are interim
financial statements, and because of temperature variations between
seasons of the year and the timing of outages of electric generating
units, especially nuclear-fueled units, the amounts reported in the
Statements of Income for periods of less than twelve months are not
necessarily indicative of amounts expected for the year.
Certain amounts for 1993 have been reclassified to conform to the 1994
presentation.
2. In January 1994, the Company implemented Statement of Position (SOP)
93-6, "Employers' Accounting for Employee Stock Ownership Plans," on a
prospective basis. This SOP requires the following changes in accounting
for the Company's leveraged employee stock ownership plan (ESOP): 1)
ESOP shares that have not been committed to be released to participants'
accounts are no longer considered outstanding for the determination of
earnings per common share; 2) dividends on unallocated ESOP shares are
no longer recognized for financial statement purposes; 3) all tax
benefits of ESOP dividends are now recorded to non-operating income tax
expense, whereas previously a portion of the tax benefits was recorded
directly to retained earnings; 4) interest income related to the
qualified ESOP loan is no longer recognized; and 5) the difference
between the acquisition and allocation prices of ESOP shares, which was
previously recorded as other income, net, is now recorded directly to
common stock. In addition, ESOP loan transactions between the Company
and the Stock Purchase-Savings Plan (SPSP) Trustee are no longer
reflected in the Statements of Cash Flows.
The implementation of SOP 93-6 resulted in an increase in earnings per
common share of approximately $.03 and $.04 for the three and nine
months ended September 30, 1994, respectively.
Selected pro forma statistics, which eliminate the significant capital
structure-related impacts of the ESOP feature of the SPSP, are included
in Financial Statistics.
3. In July 1994, the Board of Directors of the Company authorized the
Executive Committee of the Board to repurchase up to 10 million shares
of the Company's common stock on the open market. In accordance with the
stock repurchase program, the Company has purchased approximately 3.5
million shares through September 30, 1994. The decrease in average
common shares outstanding resulted in an increase in earnings per common
share of approximately $.01 in each of the three, nine and twelve month
periods ended September 30, 1994.
4. Contingencies existing as of the date of these statements are described
below. No significant changes have occurred since December 31, 1993,
with respect to the commitments discussed in Note 9 of the financial
statements included in the Company's 1993 Annual Report to Shareholders.
a) In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs are approved by the North Carolina Utilities
Commission and the South Carolina Public Service Commission and are
based on site-specific estimates that included the costs for removal of
all radioactive and other structures at the site. In the wholesale
jurisdiction, the provisions for nuclear decommissioning costs are based
on amounts agreed upon in applicable rate settlements. Accumulated
decommissioning cost provisions, which are included in accumulated
depreciation, were $249.5 million at September 30, 1994, and $209.5
million at September 30, 1993, and include amounts funded internally and
amounts funded in an external decommissioning trust. Based on the
site-specific estimates discussed below, and using an assumed after-tax
earnings rate of 8.5% and an assumed cost escalation rate of 4%, current
levels of rate recovery for nuclear decommissioning costs are currently
adequate to provide for decommissioning of the Company's nuclear
facilities.
The Company's most recent site-specific estimates of decommissioning
costs were developed in 1993, using 1993 cost factors, and are based on
prompt dismantlement decommissioning, which reflects the cost of removal
of all radioactive and other structures currently at the site. These
estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2,
$284.3 million for the Harris Plant, $235.4 million for Brunswick Unit
No. 1 and $221.4 million for Brunswick Unit No. 2. These estimates are
subject to change based on a variety of factors including, but not
limited to, cost escalation, changes in technology applicable to nuclear
decommissioning, and changes in federal, state or local regulations. The
cost estimates exclude the portion attributable to North Carolina
Eastern Municipal Power Agency, which holds an undivided ownership
interest in certain of the Company's generating facilities.
b) Various organic materials associated with the production of
manufactured gas, generally referred to as coal tar, are regulated under
various federal and state laws, and a contingent liability may exist for
their remediation. There are several manufactured gas plant (MGP) sites
to which the Company and certain entities that were later merged into
the Company may have had some connection. In this regard, the Company is
participating in the North Carolina MGP Group (Group), which is a group
of entities alleged to be former owners or operators of MGP sites in
North Carolina. The Group was formed in response to an initiative
launched by the North Carolina Department of Environment, Health and
Natural Resources, Division of Solid Waste Management (DSWM), to
encourage the voluntary assessment and, where necessary, the remediation
of MGP sites. The Group and DSWM have entered into a Memorandum of
Understanding relative to the establishment of a uniform program and
framework for addressing MGP sites for which DSWM has contended that
members of the Group have potential responsibility. It is anticipated
that the investigation and remediation of specific MGP sites will be
addressed pursuant to one or more Administrative Orders on Consent
between DSWM and individual potentially responsible parties. To date,
the Company has not entered into any such orders.
The Company has recently been approached by another North Carolina
public utility concerning a possible cost-sharing arrangement with
respect to the investigation and, if necessary, remediation of four MGP
sites. The Company is currently engaged in discussions with the other
utility regarding this matter. Based on current cost estimates provided
by that utility, the Company does not believe its portion of costs
associated with the investigation and remediation of these sites, if any,
would be material to the financial position or results of operations
of the Company.
In addition, a current owner of property that was the site of one MGP
owned by Tidewater Power Company (Tidewater Power), which merged into
the Company in 1952, has been party to a separate administrative
proceeding regarding that site. That owner and the Company have entered
into an agreement to share the cost of investigation and remediation of
this site. The Company has also been approached by a North Carolina
municipality that is the current owner of another MGP site that was
formerly owned by Tidewater Power. The Company is engaged in discussions
with that municipality concerning a possible cost-sharing arrangement
with respect to the investigation, and if necessary, the remediation of
that site. Due to the uncertainty concerning potential environmental
harm and the full extent to which remedial action will be required at
the two sites formerly owned by Tidewater Power, the total cost of
investigating and remediating these sites is not determinable at this
time. The Company cannot predict the outcome of these matters.
The Company is continuing its investigation regarding the identities of
parties connected to individual MGP sites, the relative relationships of
the Company and other parties to those sites, and the degree, if any, to
which the Company should undertake shared voluntary efforts with others
at individual sites. Except as noted above, due to the lack of
information with respect to the operation of MGP sites and the
uncertainty concerning questions of liability and potential
environmental harm, the extent and cost of required remedial action, if
any, and the extent to which liability may be asserted against the
Company or against others are not currently determinable. The Company
cannot predict the outcome of these matters or the extent to which other
former MGP sites may become the subject of inquiry.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND> THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM INTERIM FINANCIAL STATEMENTS AS OF
SEPTEMBER 30, 1994 AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS
</LEGEND>
<CIK> 0000017797
<NAME> CAROLINA POWER & LIGHT COMPANY
<S> <C>
<PERIOD-TYPE> QTR-3
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> SEP-30-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $6,332,398
<OTHER-PROPERTY-AND-INVEST> $313,766
<TOTAL-CURRENT-ASSETS> $624,711
<TOTAL-DEFERRED-CHARGES> $653,979
<OTHER-ASSETS> $190,651
<TOTAL-ASSETS> $8,115,505
<COMMON> $1,327,375
<CAPITAL-SURPLUS-PAID-IN> ($790)
<RETAINED-EARNINGS> $1,300,753
<TOTAL-COMMON-STOCKHOLDERS-EQ> $2,627,338
$0
$143,801
<LONG-TERM-DEBT-NET> $2,502,893
<SHORT-TERM-NOTES> $0
<LONG-TERM-NOTES-PAYABLE> $0
<COMMERCIAL-PAPER-OBLIGATIONS> $15,000
<LONG-TERM-DEBT-CURRENT-PORT> $252,050
$0
<CAPITAL-LEASE-OBLIGATIONS> $0
<LEASES-CURRENT> $0
<OTHER-ITEMS-CAPITAL-AND-LIAB> $2,574,423
<TOT-CAPITALIZATION-AND-LIAB> $8,115,505
<GROSS-OPERATING-REVENUE> $2,237,323
<INCOME-TAX-EXPENSE> $163,743
<OTHER-OPERATING-EXPENSES> $1,708,327
<TOTAL-OPERATING-EXPENSES> $1,872,070
<OPERATING-INCOME-LOSS> $365,253
<OTHER-INCOME-NET> $51,911
<INCOME-BEFORE-INTEREST-EXPEN> $417,164
<TOTAL-INTEREST-EXPENSE> $149,872
<NET-INCOME> $267,292
$7,206
<EARNINGS-AVAILABLE-FOR-COMM> $260,086
<COMMON-STOCK-DIVIDENDS> $192,765
<TOTAL-INTEREST-ON-BONDS> $0
<CASH-FLOW-OPERATIONS> $623,510
<EPS-PRIMARY> $1.73
<EPS-DILUTED> $1.73
</TABLE>
