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 June 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 (I.R.S. Employer
incorporation 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
July 31,1994: 160,675,322
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
_______ ____________________
Reference is made to the attached Appendix containing the
Interim Financial Statements for the periods ended June 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, Six and Twelve Months Ended June 30, 1994,
As Compared With the Corresponding Periods One Year Earlier
___________________________________________________________
Operating Revenues and Expense: Revenues increased for all
periods reflecting higher energy sales due to slight increases in
usage and number of customers.
A portion of the decrease in the deferred fuel credit for
the twelve months ended June 30, 1994, reflects settlement
agreements reached with the Company's regulators in the North
Carolina and South Carolina jurisdictions in July and September
1993, respectively. As part of these settlements, the Company
agreed to forgo recovery of a total of $41.1 million of deferred
fuel expense related to the Brunswick Plant outage. Excluding
the effect of these settlements, the remaining $26.1 million
decrease in the deferred fuel credit was primarily due
to lower fuel costs associated with an increase in nuclear
generation and due to the recovery of prior fuel costs
as allowed in the Company's most recent annual fuel adjustment
proceeding.
Purchased power increased for the three months ended June 30,
1994, primarily due to increased purchases from Duke Power Company
(Duke). Purchased power increased for the six and twelve months
ended June 30, 1994, primarily due to increased purchases from Duke
and North Carolina Eastern Municipal Power Agency (Power Agency).
The increased purchases from Duke of $16.6 million, $33.0 million
and $56.9 million for the three, six and twelve months ended June
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 $9.0 million and $18.3 million for the six and twelve months
ended June 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 $4.8 million and
$7.4 million for the three and six months ended June 30, 1994,
respectively, due to outage-related work at the Harris Plant in the
current year. The balance of the increase in each period is made
up of a number of items, none of which are individually
significant. Other operation expense increased for the twelve
months ended June 30, 1994, primarily due to adjustments made in
1992 that decreased expenses for the twelve months ended June 30,
1993. In addition, other operation expense increased for the
twelve months ended June 30, 1994, due to outage-related work at
the Harris Plant and the recognition of greater employee benefits
expense due to new accounting requirements effective in 1993.
Maintenance expense decreased in the six and twelve months
ended June 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 decrease in income tax expense for all periods
includes a reduction in expense as the result of certain Internal
Revenue Service (IRS) audit issues.
The increase in Harris Plant deferred costs for the twelve
months ended June 30, 1994, includes adjustments related to a
September 1993 settlement between the Company and North Carolina
Electric Membership Corporation (NCEMC).
Other Income: The increase in Harris Plant carrying costs for
the twelve months ended June 30, 1994, is primarily related to the
1993 settlement between the Company and NCEMC.
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.
Interest income increased for all periods as a result of the
Company recording interest income in June 1994 related to certain
IRS audit issues. In addition, for the twelve months ended June
30, 1994, interest income increased due to the Company's settlement
agreement with Westinghouse Electric Corporation. 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). This reduction in interest income partially
offsets the increases discussed above for the three and twelve
months ended June 30, 1994, and more than offsets the increase for
the six months ended June 30, 1994.
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 June 30, 1994 and From
June 30, 1993, to June 30, 1994
___________________________________________________
During the six and twelve months ended June 30, 1994, the
Company issued long-term debt totaling $272.6 million and $609.9
million, respectively. These issuances of debt together with
internally generated funds financed the retirement or redemption of
long-term debt totaling $267.7 million and $762.7 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
June 30, 1994, these revolving credit agreements amounted to $185
million. Recently, the Company obtained additional credit
facilities of $22.9 million which became effective in July 1994.
These credit facilities replaced certain credit facilities that
expired in April 1994. At June 30, 1994, the Company had $72.6
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 June 30, 1994, was 49.9%
common stock equity, 47.4% 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. The
Board's action provides flexibility for management to undertake
such a program at its discretion, but does not establish a target
stock price or timetable for repurchases. On July 21, 1994, the
Company began repurchasing shares of its common stock on
the open market in accordance with the stock repurchase program.
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 $.01 for the six months ended June 30, 1994.
Legal Matters
_____________
With regard to the April 1993 agreement entered into by the
Company and Power Agency to restructure portions of their contracts
covering power supplies and jointly-owned interests in several of
the Company's generating units, on July 29, 1994, the Federal
Energy Regulatory Commission (FERC) accepted the provisions of the
agreement that are subject to the FERC's jurisdiction.
On August 1, 1994, NCEMC filed a complaint with the FERC,
alleging that the wholesale rates the Company charges NCEMC are
excessive, and seeking a rate reduction of approximately $38.6
million per year. Although the Company cannot predict the outcome
of this matter, it believes NCEMC's allegations are without merit.
With regard to the remaining disputed issues relating to Power
Agency's use of capacity and energy from the South Carolina Public
Service Authority (Santee Cooper) and Power Agency's use of a
combustion turbine electric generating project, the Company and
Power Agency negotiated final Power Coordination Agreements
relating to the Santee Cooper and turbine generator transactions,
and filed them with the FERC on April 29, 1994. The parties are
awaiting FERC action on these filings. The Company cannot
predict the outcome of these matters.
With regard to the North Carolina retail jurisdiction, the
Company's 1994 North Carolina fuel case hearing was held on August
2, 1994. The parties to the fuel proceeding agreed to stipulations
that resolved all issues between them in 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 forego 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. The Company cannot predict whether
the stipulations will be approved by the North Carolina Utilities Commission.
Competition
In June 1994, the FERC approved a 30-year agreement between
the Company and NCEMC, which represents seventeen wholesale
electric membership corporations in the Company's service area.
The agreement assures that the Company will continue to be NCEMC's
primary source of electricity for the next several years.
According to the agreement, NCEMC can assume responsibility for a
portion of its load, subject to advance notice and agreed-upon
limits, beginning in January 1996. Recently, NCEMC gave notice
that it will award a power-supply contract to another supplier
beginning on January 1, 1996. If approved by the FERC, the
contract with the other supplier will displace 200 megawatts of
baseload capacity that NCEMC currently purchases from the Company.
On and after January 1, 1996, the Company will continue to supply
not less than 1000 MW of electricity to NCEMC until at least
December 31, 2000. Load reductions beyond the year 2000 are
subject to specific limits and require five years advance notice.
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 )
_______ _____________________ )
) Not applicable for
) the quarter ended
Item 3. Defaults upon Senior Securities ) June 30, 1994.
______ _______________________________ )
)
)
)
Item 4. Submission of Matters to a Vote
of Security Holders
______ _______________________________
(a) The Annual Meeting of the Shareholders was held on
May 11, 1994.
(b) The meeting involved the election of directors.
Proxies for the meeting were solicited pursuant
to Regulation 14, there was no solicitation in
opposition to the management's nominees as listed
below, and all such nominees were elected.
(c) The total votes were as follows:
Votes For Votes Withheld
_________ ______________
Charles D. Barham, Jr. 136,206,920 2,314,918
Edwin B. Borden 136,195,139 2,326,699
Felton J. Capel 135,900,944 2,620,894
William Cavanaugh III 136,042,073 2,479,765
George H. V. Cecil 136,045,170 2,476,668
Charles W. Coker 136,881,936 1,639,902
Richard L. Daugherty 136,688,017 1,833,821
William E. Graham, Jr. 136,891,636 1,630,202
Gordon C. Hurlbert 136,814,572 1,707,266
J. R. Bryan Jackson 136,902,685 1,619,153
Robert L. Jones 136,837,106 1,684,732
Estell C. Lee 136,896,162 1,625,676
Sherwood H. Smith, Jr. 136,819,879 1,701,959
J. Tylee Wilson 136,772,255 1,749,583
Item 5. Other Information
_______ _________________
1. (Reference is made to the Company's 1993 Form 10-K,
Generating Capability, paragraph 4, page 5 and Competition and
Franchises, paragraph 1.b., page 7. Reference is also made to the
Company's Form 10-Q for the quarter ended March 31, 1994, Item 5,
paragraph 1.) With regard to the Walters Hydroelectric Plant
relicensing proceeding (Project Nos. 432-004 and 2748-000), by
letter dated June 29, 1994, the Federal Energy Regulatory
Commission (FERC) advised the Company and North Carolina Electric
Membership Corporation (NCEMC) that the First Amendment to the
Power Coordination Agreement (PCA), filed with the FERC on
May 11, 1994, complied with the FERC's April 19,1994 order. That
order conditionally approved the PCA, the Interchange Agreement,
and the settlement agreements previously filed in this proceeding.
The FERC's June 29, 1994 letter also stated that the revised PCA
was accepted for filing. The PCA allows NCEMC to assume
responsibility for up to 200 MW of its load from the Company's
system between January 1, 1996 and December 31, 2000. On and after
January 1, 1996, the Company expects to continue to supply not
less than 1000 MW of electricity to NCEMC until at least December
31, 2000. NCEMC's board of directors has voted to award a
power-supply contract for 200 MW to another supplier beginning on
January 1, 1996. If approved by the FERC, the contract will
displace 200 MW of baseload capacity that NCEMC currently purchases
from the Company. Load reductions beyond the year 2000 are subject
to specific limits and require five years advance notice. Issuance
of the license for the Walters Plant by the FERC will conclude this
matter.
2. (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 March
31, 1994, Item 5, paragraph 2.) With regard to the petition filed
with the North Carolina Utilities Commission (NCUC) by the North
Carolina Public Staff (Public Staff), which represents the using
and consuming public in matters before the NCUC, proposing interim
guidelines to apply to requests for self-generation deferral rates,
by order issued May 13, 1994, the NCUC established a docket (Docket
No. E-100, Sub 73) to consider the proposed self-generation
deferral rates guidelines, and dispersed energy facilities and
economic development rates. Initial comments were filed by the
Company and other interested parties on June 13, 1994, and reply
comments were filed on June 27, 1994. In response to the parties'
comments, on July 1, 1994, the Public Staff filed modifications to
the proposed self-generation deferral rate guidelines. By order
issued July 21, 1994, the NCUC, with limited exceptions, approved
and adopted the modified self-generation deferral rate guidelines
proposed by the Public Staff. In this order, the NCUC also
requested that additional comments regarding economic
development rates be filed by October 21, 1994, and stated that the
issue of dispersed energy facilities would be addressed on a case
by case basis. The guidelines allow the Company to adjust rates
to retain certain loads for which self-generation is feasible.
3. (Reference is made to the Company's 1993 Form 10-K,
Competition and Franchises, Paragraph 1.b., page 7.) On June 20,
1994, the Company filed with the NCUC an application for
permission to change the rates it currently charges AlliedSignal
Inc. (Allied) for approximately 16 MW of electricity provided to
Allied's Moncure, North Carolina facility. The proposed rates
provide 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. If the proposed rates
are approved by the NCUC, the Company will continue to serve all of
Allied's electrical requirements. The Company cannot predict the
outcome of this matter.
4. (Reference is made to the Company's 1993 Form 10-K,
Financing Program, paragraph 4, page 10. Reference is also made
to the Company's Form 10-Q for the quarter ended March 31, 1994,
Item 5, paragraph 4.) On June 15, 1994, the Company redeemed
$122.6 million principal amount of First Mortgage Bonds, Pollution
Control Series G due June 15, 2014, at 100% of the principal amount
of such bonds plus accrued interest to the date of redemption.
5. (Reference is made to the Company's 1993 Form 10-K,
Retail Rate Matters, paragraph 5, page 12.) With regard to the
North Carolina retail jurisdiction, the Company's 1994 North
Carolina fuel case hearing was held on August 2, 1994. The
parties to the fuel proceeding agreed to stipulations that
resolved all issues between them in 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 forego 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. The Company cannot
predict whether the stipulations will be approved by the NCUC.
6. (Reference is made to the Company's 1993 Form 10-K,
Retail Rate Matters, paragraph 6, page 13. Reference is also made
to the Company's Form 10-Q for the quarter ended March 31, 1994,
Item 5, paragraph 5.) With regard to the docket the South Carolina
Public Service Commission (SCPSC) opened to consider whether the
adoption of certain standards set forth in Section 111 of the
Energy Policy Act of 1992 (Energy Act) would further the purposes
of the Public Utility Regulatory Policies Act (PURPA), by order
dated June 22, 1994, the SCPSC approved a stipulation entered into
by the Company and the other parties to the proceeding. In that
stipulation, the parties agreed that standards similar to those of
Section 111 of the Energy Act have already been implemented to the
degree necessary, and therefore, the specific standards of Section
111 do not need to be adopted by the SCPSC in order to implement
the purposes of PURPA.
7. (Reference is made to the Company's 1993 Form 10-K,
Wholesale Rate Matters, paragraph 2.a., page 14.) On August 1,
1994, NCEMC filed a Complaint with the FERC, Docket No. EL94-84,
under Section 206 of the Federal Power Act. The Complaint alleges
that the wholesale rates the Company charges NCEMC are excessive,
and seeks a rate reduction of approximately $38.6 million per year.
Although the Company cannot predict the outcome of this matter,
it believes NCEMC's allegations are without merit.
8. (Reference is made to the Company's 1993 Form 10-K,
Wholesale Rate Matters, paragraph 2.b., page 14.) With regard to
the remaining disputed issues relating to North Carolina Eastern
Municipal Power Agency's (Power Agency) use of capacity and energy
from the South Carolina Public Service Authority (Santee Cooper)
and Power Agency's use of a combustion turbine electric generating
project, the Company and Power Agency negotiated final Power
Coordination Agreements relating to the Santee Cooper and turbine
generator transactions, and filed them with the FERC on April 29,
1994. The parties are awaiting FERC action on these filings.
The Company cannot predict the outcome of these matters.
9. (Reference is made to the Company's 1993 Form 10-K,
Wholesale Rate Matters, paragraph 2.c., page 15.) With regard
to the agreement the Company and Power Agency entered into on
April 7, 1993 to restructure portions of their contracts covering
power supplies and jointly-owned interests in several of the
Company's generating units, on July 29, 1994, the FERC accepted
the provisions of the agreement that are subject to its
jurisdiction.
10. (Reference is made to the Company's 1993 Form 10-K,
Wholesale Rate Matters, paragraph 3.b., page 15.) With regard to
the wholesale purchase power contract between the Company and
the City of Camden, South Carolina, as a result of the contract
amendment that was approved by the FERC, effective March 11, 1994,
the parties sought a dismissal of the pending state court
litigation relating to the proper termination date of the contract.
On May 17, 1994, the South Carolina Supreme Court dismissed the
litigation.
11. (Reference is made to the Company's 1993 Form 10-K,
Wholesale Rate Matters, paragraph 3.c., page 16.) With regard to
the new power supply and coordination agreement the Company and
the City of Fayetteville's Public Works Commission (Fayetteville
PWC) entered into on March 10, 1994, the FERC approved the
agreement, subject to one change, on May 12, 1994. On June 13,
1994, the Company and the Fayetteville PWC made a compliance filing
with the FERC to effectuate the change. That filing is subject
to the FERC's review and acceptance; however, the rates provided
for in the power supply and coordination agreement are currently in
effect. The Company cannot predict the outcome of this matter.
12. (Reference is made to the Company's 1993 Form 10-K,
Wholesale Rate Matters, paragraph 3, page 16.) On July 26, 1994,
the Town of Waynesville and the Company entered into a new power
supply agreement. The agreement provides that the Company will
remain the Town's sole electricity provider for the next ten
years. The Town, which serves about 2,800 customers, has a peak
load of 15MW. The power supply agreement was filed with the FERC
on August 2, 1994 for approval. The Company cannot predict the
outcome of this matter.
13. (Reference is made to the Company's 1993 Form 10-K,
Environmental Matters, paragraph 3.f., page 18. Reference is
also made to the Company's Form 10-Q for the quarter ended March
31, 1994, Item 5, paragraph 7.) With regard to the Macon-Dockery
superfund site located near Cordova, North Carolina, on July 6,
1994, the United States District Court for the Middle District of
North Carolina granted the motion Crown Cork & Seal Company and
Clark Equipment filed seeking to name the Company as a defendant
in an ongoing lawsuit (Civil Action No. 3: 92CV00744). The
lawsuit seeks to recover costs incurred in undertaking the
Remedial Investigation Feasibility Study and the Remedial Design
for the site. Although the Company cannot predict the outcome of
this matter, it does not anticipate that costs associated
with this site will be material to the results of operations of the
Company.
14. (Reference is made to the Company's 1993 Form 10-K,
Nuclear Matters, paragraph 4.a., page 21.) With regard to the
Company's recovery through rates of nuclear decommissioning
costs, in the Company's retail jurisdictions, provisions for
nuclear decommissioning costs are approved by the NCUC and the
SCPSC, and are based on site-specific estimates that include the
costs for removal of all radioactive and other structures at the
site. In the wholesale jurisdiction, the provisions for nuclear
decommissioning cost are based on amounts agreed upon in applicable
rate settlements. Accumulated decommissioning cost provisions,
which are included in accumulated depreciation, were $240.5 million
at June 30, 1994, and $201.1 million at June 30, 1993, and include
amounts funded internally and amounts funded in an external
decommissioning trust. Based on an assumed after-tax earnings rate
of 8.5% and an assumed cost escalation rate of 4%, provisions for
nuclear decommissioning costs are currently adequate to provide
for decommissioning of the Company's nuclear facilities.
15. (Reference is made to the Company's 1993 Form 10-K,
Nuclear Matters, paragraph 7.d., page 23.) With regard to the
Company's Brunswick Nuclear Plant, in a letter dated June 21, 1994,
the Nuclear Regulatory Commission (NRC) notified the Company that
it was removing the Brunswick Plant from the list of plants
receiving increased regulatory scrutiny. In the letter, the NRC
cited the "sustained improvement" at the Brunswick Plant and noted
the trouble-free performance of Brunswick Unit No. 2 over a
sustained period in parallel with the Brunswick Unit No. 1 recovery
and restart. The NRC also stated that the "operation of both units
have demonstrated the competency of management and the teamwork
among staff."
The scheduled spring 1994 refueling outage at Brunswick Unit
No. 2 was recently completed. During that outage, shroud
modifications similar to those performed on Unit No. 1 in 1993
were successfully completed, and Unit No. 2 resumed generating
electricity on June 30, 1994. The costs associated with the shroud
modifications are not material to the results of operations
of the Company.
With regard to the allegations concerning the Brunswick Plant
shrouds made last fall by two private organizations and an
individual, in early June 1994, the NRC issued a statement to the
press reporting that the NRC had conducted a preliminary inquiry
into the allegations. The NRC determined that there was not enough
information available to conduct an investigation. Last fall, the
Company conducted an internal technical review of those same
allegations shortly after they were first raised and found no
evidence to substantiate them. The Company cannot predict the
outcome of this matter.
16. (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.) With regard to the fuel assembly and power
instrumentation issues the Company identified on November 17, 1993
at its H. B. Robinson Plant Unit No. 2, on May 9, 1994, the NRC
issued a Severity Level IV Notice of Violation (the next to the
lowest severity level) concluding that this situation involved
noncompliance with certain NRC requirements. The NRC did not
propose a civil penalty in connection with this matter. In a
letter to the NRC dated June 8, 1994, the Company acknowledged
that the violations had occurred, clarified the events surrounding
the occurrences, and described the corrective actions that had been
taken to address the situation. Although the Company cannot
predict the outcome of these matters, it does not anticipate
further enforcement action by the NRC in connection with these
violations.
On April 13, 1994, the Company submitted a written response to
the Notice of Violation and Proposed Imposition of Civil Penalty
that the NRC issued in connection with the degradation of the
Robinson Unit No. 2 diesel generators, and paid the assessed
$37,500 civil penalty.
With regard to the apparent violation of NRC requirements
related to inattention to licensed duties at the Robinson Plant,
on May 16, 1994, an enforcement conference was held between
the Company and the NRC to discuss this matter. On May 30, 1994,
the NRC issued a Severity Level IV Notice of Violation to the
Company in connection with this matter, but did not propose a civil
penalty. In a letter to the NRC dated June 29, 1994, the Company
acknowledged that the violation had occurred and described the
corrective actions that had been taken to address the occurrence.
Although the Company cannot predict the outcome of this matter, it
does not anticipate further enforcement action by the NRC in
connection with this violation.
During the inspections conducted at the Robinson Plant during
the period May 22 through June 24, 1994, the NRC identified certain
activities that might have violated certain NRC requirements. The
activities related to the failure to take adequate corrective
action on issues identified by a contractor, inadequate testing
of ventilation equipment, and inadequate corrective actions on a
design concern involving an isolation valve. An enforcement
conference between the Company and the NRC was held on
July 26 to determine whether a violation had occurred and if so, to
assess the significance of the violation. The NRC may issue a
notice of violation and could impose a civil penalty upon
the Company in connection with these activities. The Company
cannot predict the outcome of this matter.
17. (Reference is made to the Company's 1993 Form 10-K,
Part II, Item 5, Market for the Registrant's Common Equity and
Related Shareholder Matters, page 32.) On July 13, 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. The Board's action provides flexibility for
management to undertake such a program at its discretion, but does
not establish a target stock price or timetable for repurchases.
On July 21, 1994, the Company began repurchasing shares of its
Common Stock on the open market in accordance with the stock
repurchase program.
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: August 10, 1994
<TABLE>
<CAPTION>
Carolina Power & Light Company
(ORGANIZED UNDER THE LAWS OF NORTH CAROLINA)
INTERIM FINANCIAL STATEMENTS
(NOT AUDITED BY INDEPENDENT AUDITORS)
JUNE 30, 1994
STATEMENTS OF INCOME
(In thousands Three Months Ended Six Months Ended Twelve Months Ended
except per share amounts) June 30 June 30 June 30
1994 1993 1994 1993 1994 1993
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues..........................................$687,310 $674,591 $1,431,771 $1,382,076 $2,945,077 $2,869,418
-------- -------- ---------- ---------- ---------- ----------
Operating Expenses
Operation - fuel for generation........................... 121,505 122,210 251,417 248,829 526,954 541,531
deferred fuel cost (credit), net.............. (5,964) (1,917) (8,215) (3,174) 22,324 (44,849)
purchased power............................... 105,814 82,372 217,355 160,074 425,372 345,054
other......................................... 139,266 124,794 270,070 240,382 528,021 454,416
Maintenance............................................... 63,777 65,022 110,736 128,556 217,628 279,925
Depreciation and amortization............................. 109,145 103,851 214,202 207,132 420,716 405,081
Taxes other than on income................................ 36,831 33,470 72,267 67,372 147,765 134,151
Income tax expense........................................ 23,812 35,598 81,310 87,384 183,243 206,936
Harris Plant deferred costs, net.......................... 6,694 4,084 13,172 10,291 30,457 17,930
-------- -------- ---------- ---------- ---------- ----------
Total Operating Expenses............................ 600,880 569,484 1,222,314 1,146,846 2,502,480 2,340,175
-------- -------- ---------- ---------- ---------- ----------
Operating Income............................................ 86,430 105,107 209,457 235,230 442,597 529,243
-------- -------- ---------- ---------- ---------- ----------
Other Income (Expense)
Allowance for equity funds used during construction....... 1,838 2,246 4,101 3,911 9,190 8,511
Income tax credit (expense) (Note 2)...................... (1,094) 33 2,489 (869) 2,965 (2,785)
Harris Plant carrying costs............................... 2,482 2,530 5,045 5,126 27,063 9,486
Harris Plant disallowance - Power Agency.................. - - - - (20,645) -
Interest income (Note 2).................................. 10,108 4,923 11,402 12,659 34,939 25,604
Other income, net (Note 2)................................ 7,525 9,335 14,015 20,892 35,587 39,667
-------- -------- ---------- ---------- ---------- ----------
Total Other Income.................................. 20,859 19,067 37,052 41,719 89,099 80,483
-------- -------- ---------- ---------- ---------- ----------
Income Before Interest Charges.............................. 107,289 124,174 246,509 276,949 531,696 609,726
-------- -------- ---------- ---------- ---------- ----------
Interest Charges
Long-term debt............................................ 46,589 52,497 93,965 106,719 192,428 216,140
Other interest charges.................................... 3,486 3,131 7,737 8,780 15,376 17,788
Allowance for borrowed funds used
during construction..................................... (1,001) (1,438) (2,232) (2,532) (5,661) (4,437)
-------- -------- ---------- ---------- ---------- ----------
Net Interest Charges............................... 49,074 54,190 99,470 112,967 202,143 229,491
-------- -------- ---------- ---------- ---------- ----------
Net Income.................................................. 58,215 69,984 147,039 163,982 329,553 380,235
Preferred Stock Dividend Requirements....................... (2,402) (2,402) (4,804) (4,804) (9,609) (9,609)
Tax Benefit of ESOP Dividends............................... - - - - - 7,104
-------- -------- ---------- ---------- ---------- ----------
Earnings for Common Stock...................................$ 55,813 $ 67,582 $ 142,235 $ 159,178 $ 319,944 $ 377,730
======== ======== ========== ========== ========== ==========
Average Common Shares Outstanding (Note 2).................. 151,057 160,737 150,939 160,737 155,878 160,737
Earnings per Common Share (Note 2)..........................$ 0.37 $ 0.42 $ 0.94 $ 0.99 $ 2.05 $ 2.35
Dividends Declared per Common Share.........................$ 0.425 $ 0.410 $ 0.850 $ 0.820 $ 1.685 $ 1.625
_____________________
See Supplemental Data and Notes to Financial Statements.
</TABLE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
BALANCE SHEETS June 30 December 31
(In thousands) 1994 1993 1993
---- ---- ----
ASSETS
<S> <C> <C> <C>
Electric Utility Plant
Electric utility plant in service......................$ 8,960,319 $ 8,707,382 $ 8,789,518
Accumulated depreciation............................... (3,054,933) (2,766,827) (2,897,832)
------------ ------------ ------------
Electric utility plant in service, net.......... 5,905,386 5,940,555 5,891,686
Held for future use.................................... 13,222 13,284 13,300
Construction work in progress.......................... 244,124 225,767 309,713
Nuclear fuel, net of amortization...................... 199,281 222,019 217,488
------------ ------------ ------------
Total Electric Utility Plant, Net............... 6,362,013 6,401,625 6,432,187
------------ ------------ ------------
Current Assets
Cash and cash equivalents.............................. 19,254 32,646 23,607
Accounts receivable.................................... 332,829 336,708 321,309
Fuel................................................... 81,735 100,463 62,029
Materials and supplies................................. 118,891 114,334 111,052
Deferred fuel cost..................................... 18,042 40,365 9,827
Prepayments............................................ 44,589 44,223 46,869
Other current assets................................... 15,160 19,098 18,591
------------ ------------ ------------
Total Current Assets............................ 630,500 687,837 593,284
------------ ------------ ------------
Deferred Debits and Other Assets
Income taxes recoverable
through future rates.................................. 381,856 377,312 385,515
Abandonment costs...................................... 85,278 175,308 125,361
Harris Plant deferred costs............................ 136,272 138,528 144,399
Unamortized debt expense............................... 65,726 55,721 63,898
Miscellaneous other property and investments........... 314,163 191,418 264,165
Other assets and deferred debits....................... 190,801 159,258 185,209
------------ ------------ ------------
Total Deferred Debits and Other Assets.......... 1,174,096 1,097,545 1,168,547
------------ ------------ ------------
Total Assets.................................$ 8,166,609 $ 8,187,007 $ 8,194,018
============ ============ ============
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity....................................$ 2,659,859 $ 2,577,637 $ 2,632,116
Preferred stock - redemption not required.............. 143,801 143,801 143,801
Long-term debt, net.................................... 2,527,025 2,567,596 2,584,903
------------ ------------ ------------
Total Capitalization............................ 5,330,685 5,289,034 5,360,820
------------ ------------ ------------
Current Liabilities
Current portion of long-term debt...................... 227,050 350,000 162,630
Notes payable (principally commercial paper)........... 72,600 30,900 76,000
Accounts payable....................................... 181,116 201,387 293,093
Taxes accrued.......................................... 77,681 82,598 20,913
Interest accrued....................................... 55,070 61,649 54,770
Dividends declared (Note 2)............................ 70,095 70,706 74,111
Other current liabilities.............................. 75,888 70,412 67,510
------------ ------------ ------------
Total Current Liabilities....................... 759,500 867,652 749,027
------------ ------------ ------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes...................... 1,580,845 1,518,272 1,585,490
Accumulated deferred investment tax credits............ 257,819 270,607 263,588
Other liabilities and deferred credits................. 237,760 241,442 235,093
------------ ------------ ------------
Total Deferred Credits and Other Liabilities.... 2,076,424 2,030,321 2,084,171
------------ ------------ ------------
Commitments and Contingencies (Note 3)
Total Capitalization and Liabilities.........$ 8,166,609 $ 8,187,007 $ 8,194,018
============ ============ ============
SCHEDULES OF COMMON STOCK EQUITY
(In thousands)
Common stock...........................................$ 1,624,696 $ 1,622,277 $ 1,622,277
Unearned ESOP common stock............................. (211,285) (228,747) (220,725)
Capital stock issuance expense......................... (790) (334) (790)
Retained earnings...................................... 1,247,238 1,184,441 1,231,354
------------ ------------ ------------
Total Common Stock Equity.......................$ 2,659,859 $ 2,577,637 $ 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 Six Months Ended Twelve Months Ended
June 30 June 30 June 30
1994 1993 1994 1993 1994 1993
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Operating Activities
Net income............................................... $ 58,215 $ 69,984 $ 147,039 $ 163,982 $ 329,553 $ 380,235
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and amortization.......................... 128,763 116,258 252,404 229,187 483,311 439,635
Harris Plant deferred costs............................ 4,212 1,554 8,127 5,165 3,394 8,444
Harris Plant disallowance - Power Agency .............. - - - - 20,645 -
Deferred income taxes.................................. 9,628 4,154 807 13,979 58,181 83,544
Investment tax credit adjustments...................... (2,884) (2,893) (5,768) (5,787) (12,788) (11,088)
Allowance for equity funds used during construction.... (1,838) (2,246) (4,101) (3,911) (9,190) (8,511)
Deferred fuel cost (credit)............................ (5,964) (1,917) (8,215) (3,174) 22,324 (44,849)
Net increase in receivables, inventories
and prepaid expenses................................. (46,231) (35,654) (69,314) (69,492) (7,625) (127,892)
Net increase (decrease) in payables and accrued
expenses............................................. (33,956) 15,300 (26,799) (35,543) (53,269) 36,857
Miscellaneous.......................................... (4,177) 19,070 12,528 38,538 (15,128) (3,288)
------- ------- ------- ------- ------- -------
Net Cash Provided by Operating Activities............. 105,768 183,610 306,708 332,944 819,408 753,087
------- ------- ------- ------- ------- -------
Investing Activities
Gross property additions................................. (55,628) (61,857) (127,941) (143,468) (325,596) (295,845)
Nuclear fuel additions................................... (5,815) (20,013) (21,206) (25,943) (43,264) (73,852)
Contributions to external decommissioning trust.......... (7,387) (3,639) (13,715) (7,306) (27,287) (14,950)
Contributions to retiree benefit trusts.................. - (1,250) (16,000) (1,250) (18,500) (7,917)
Loan transactions with SPSP Trustee, net (Note 2)........ - 3,760 - 5,125 16,009 23,836
Allowance for equity funds used during construction...... 1,838 2,246 4,101 3,911 9,190 8,511
------- ------- ------- ------- ------- -------
Net Cash Used in Investing Activities................. (66,992) (80,753) (174,761) (168,931) (389,448) (360,217)
------- ------- ------- ------- ------- -------
Financing Activities
Proceeds from issuance of long-term debt................. 120,339 - 268,325 295,251 555,104 591,308
Net decrease in pollution control bond escrow............ - 1,800 - 2,127 - 3,062
Net increase (decrease) in short-term notes
payable (maturity less than 90 days)................... 65,900 30,900 (3,400) (15,900) 41,700 9,500
Retirement of long-term debt............................. (172,616) (204,209) (268,239) (287,060) (771,555) (619,700)
Retirement of preferred stock............................ - - - - - (95,950)
Dividends paid on common stock (Note 2).................. (64,186) (65,902) (128,172) (131,804) (259,117) (258,786)
Dividends paid on preferred stock........................ (2,403) (2,402) (4,814) (4,804) (9,484) (13,730)
------- ------- ------- ------- ------- -------
Net Cash Used in Financing Activities................. (52,966) (239,813) (136,300) (142,190) (443,352) (384,296)
------- ------- ------- ------- ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents....... (14,190) (136,956) (4,353) 21,823 (13,392) 8,574
Cash and Cash Equivalents at Beginning of the Period....... 33,444 169,602 23,607 10,823 32,646 24,072
------- ------- ------- ------- ------- -------
Cash and Cash Equivalents at End of the Period............. $ 19,254 $ 32,646 $ 19,254 $ 32,646 $ 19,254 $ 32,646
======= ======= ======= ======= ======= =======
Supplemental Disclosures of Cash Flow Information
Cash paid during the period - interest................... $ 43,383 $ 54,745 $ 95,630 $ 110,642 $ 203,789 $ 221,817
income taxes.... 50,675 30,540 52,725 30,252 135,996 85,622
- --------------------
See Supplemental Data and Notes to Financial Statements.
</TABLE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
SUPPLEMENTAL DATA Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
1994 1993 1994 1993 1994 1993
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues (in thousands)
Residential............................. $ 190,017 $ 191,659 $ 452,390 $ 440,027 $ 956,060 $ 910,274
Commercial.............................. 149,520 146,178 293,317 282,820 603,469 581,949
Industrial.............................. 192,686 197,514 359,546 358,970 744,591 736,724
Government and municipal................ 19,582 19,692 39,098 38,361 79,354 78,511
Wholesale - standard rate schedules..... 81,465 76,841 182,663 168,191 368,393 363,397
Power Agency contract requirements...... 31,818 31,282 67,765 70,265 131,759 154,521
Other utilities......................... 11,571 1,788 15,641 4,522 22,350 5,450
Miscellaneous revenue................... 10,651 9,637 21,351 18,920 39,101 38,592
--------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues.......... $ 687,310 $ 674,591 $1,431,771 $1,382,076 $2,945,077 $2,869,418
========= ========== ========== ========== ========== ==========
Energy Sales (millions of kWh)
Residential............................. 2,303 2,332 5,646 5,495 11,549 11,014
Commercial.............................. 2,167 2,155 4,218 4,063 8,703 8,371
Industrial.............................. 3,676 3,420 6,793 6,430 13,919 13,179
Government and municipal................ 304 301 610 598 1,260 1,239
Wholesale - standard rate schedules..... 1,627 1,449 3,327 3,173 7,076 6,627
Power Agency contract requirements...... 804 897 1,451 1,857 3,099 3,972
Other utilities......................... 216 50 334 155 507 184
--------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales................ 11,097 10,604 22,379 21,771 46,113 44,586
========= ========== ========== ========== ========== ==========
Energy Supply (millions of kWh)
Generated - coal........................ 5,753 5,852 11,849 12,325 25,330 27,521
nuclear..................... 3,668 3,610 7,051 6,748 13,995 10,687
hydro....................... 232 240 537 586 734 995
combustion turbines......... 28 26 66 31 119 81
Purchased............................... 1,859 1,409 3,816 3,048 7,879 7,237
--------- ---------- ---------- ---------- ---------- ----------
Total Energy Supply
(Company Share)................. 11,540 11,137 23,319 22,738 48,057 46,521
========= ========== ========== ========== ========== ==========
Detail of Income Taxes (in thousands)
Included in Operating Expenses
Income tax expense - current............ $ 18,837 $ 36,099 $ 89,080 $ 83,084 $ 144,618 $ 144,799
Income tax expense - deferred........... 7,859 2,392 (2,002) 10,087 50,219 73,225
Income tax expense - investment
tax credit adjustments................ (2,884) (2,893) (5,768) (5,787) (11,594) (11,088)
--------- ---------- ---------- ---------- ---------- ----------
Subtotal.......................... 23,812 35,598 81,310 87,384 183,243 206,936
--------- ---------- ---------- ---------- ---------- ----------
Harris Plant deferred costs - deferred... - - - - - (930)
Harris Plant deferred costs -
investment tax credit adjustments...... (74) (44) (149) (89) 158 (125)
--------- ---------- ---------- ---------- ---------- ----------
Subtotal.......................... (74) (44) (149) (89) 158 (1,055)
--------- ---------- ---------- ---------- ---------- ----------
Total Included in Operating Expenses.... 23,738 35,554 81,161 87,295 183,401 205,881
--------- ---------- ---------- ---------- ---------- ----------
Included in Other Income
Income tax expense (credit) - current... (675) (1,795) (5,298) (3,023) (9,733) (7,534)
Income tax expense - deferred........... 1,769 1,762 2,809 3,892 7,962 10,319
Income tax expense - investment
tax credit adjustments................. - - - - (1,194) -
--------- ---------- ---------- ---------- ---------- ----------
Subtotal.......................... 1,094 (33) (2,489) 869 (2,965) 2,785
Harris Plant carrying costs - deferred.. - - - - - 797
Other income, net - deferred............ - - - - - 18
--------- ---------- ---------- ---------- ---------- ----------
Total Included in Other Income.... 1,094 (33) (2,489) 869 (2,965) 3,600
--------- ---------- ---------- ---------- ---------- ----------
Included in Interest Charges
Allowance for borrowed funds used
during construction - deferred....... - - - - - 1,205
--------- ---------- ---------- ---------- ---------- ----------
Total Income Tax Expense...... $ 24,832 $ 35,521 $ 78,672 $ 88,164 $ 180,436 $ 210,686
========= ========== ========== ========== ========== ==========
FINANCIAL STATISTICS JUNE 30, 1994 JUNE 30, 1993
ACTUAL PRO FORMA ACTUAL PRO FORMA
(Note 2) (Note 2)
Ratio of earnings to fixed charges........ 3.26 3.42 3.34 3.53
Return on average common stock equity..... 12.22% 11.28% 15.07% 13.76%
Book value per common share (Note 2)...... $ 17.60 N/A $ 17.46 N/A
Capitalization ratios
Common stock equity................... 49.90% 53.87% 48.74% 53.10%
Preferred stock - redemption 2.70 2.70 2.72 2.72
not required......................... 47.40 43.43 48.54 44.18
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 $.01 for the six
months ended June 30, 1994.
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. 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 cost are based on
amounts agreed upon in applicable rate settlements.
Accumulated decommissioning cost provisions, which are
included in accumulated depreciation, were $240.5 million at
June 30, 1994, and $201.1 million at June 30, 1993, and
include amounts funded internally and amounts funded in an
external decommissioning trust. Based on an assumed after-tax
earnings rate of 8.5% and an assumed cost escalation rate of
4%, provisions 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 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, inflation, 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) 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), a group of entities alleged to be former owners or
operators of MGP sites. 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. In addition,
a current owner of property that was the site of one MGP site
owned by Tidewater Power Company, which merged into the
Company in 1952, and the Company have entered into an
agreement to share the cost of investigation and remediation
of this site. 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.
