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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________
Form 10
GENERAL FORM FOR REGISTRATION OF SECURITIES
Pursuant to Section 12(b) or (g)
NORTH CAROLINA NATURAL GAS CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 56-0646235
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
411 Fayetteville Street
Raleigh, North Carolina 27601
(Address of principal executive offices)
(919) 546-6111
(Registrant's telephone number, including area code)
Securities to be registered pursuant to Section 12(b) of the Act: None.
Securities to be registered pursuant to Section 12(g) of the Act:
Common Stock, $0.10 par value
(Title of class)
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ITEM 1. BUSINESS.
General
North Carolina Natural Gas Corporation was incorporated under the laws of
Delaware in 1955. Our principal offices are located at 411 Fayetteville Street,
Raleigh, North Carolina. On July 15, 1999, we were acquired by Carolina Power &
Light Company, or CP&L, and became a wholly-owned subsidiary of CP&L. The
merger with CP&L was accounted for using the purchase method of accounting and
the effects of the merger are reflected in our financial data as of the merger
date. Periods ending at December 31 reflect a change in our fiscal year end from
September 30 to conform to the fiscal year end of CP&L. CP&L recently converted
to a holding company structure in which we became a wholly-owned subsidiary of a
new holding company called CP&L Energy, Inc.
We have two business segments:
. a regulated natural gas transmission and local distribution
segment, and
. an unregulated segment which participates in related profit-making
ventures.
We are engaged in the transmission and distribution of natural gas through
approximately 1,128 miles of transmission pipeline and approximately 2,865 miles
of distribution mains. Our natural gas operations are regulated by the North
Carolina Utilities Commission. We also have four unregulated subsidiaries.
We sell and transport natural gas to over 103,000 residential customers,
over 13,900 commercial and agricultural customers and 473 industrial and
electric utility customers located in 110 towns and cities, primarily in eastern
and south central North Carolina. We also sell and transport natural gas to
four municipal gas distribution systems which serve over 50,000 end users. The
North Carolina Office of State Planning estimates that the population of our
franchised territory is approximately 2.4 million. We serve principally the
following cities and towns: Albermarle, Dunn, Fayetteville, Goldsboro,
Greenville, Jacksonville, Indian Trail, Kinston, Lumberton, New Bern, Monroe,
Roanoke Rapids, Rockingham, Rocky Mount, Smithfield/Selma, Southern Pines,
Wilmington and Wilson.
We believe that our service area is attractive to industry and commerce due
to favorable labor relations, responsive local and state government agencies,
good climate and proximity to major markets in the Mid-Atlantic and Southeast
United States. Industrial activities in our region are diverse. Our customers
include pharmaceutical, chemical, brick, fiber optic cable, glass, textile,
rubber and aluminum manufacturers, and dairy, food and tobacco processors. We
also provide natural gas service to four large military bases located in North
Carolina (Pope Air Force Base, Seymour Johnson Air Force Base, Fort Bragg and
Camp Lejuene).
We purchase and transport natural gas under long-term contracts with
Transcontinental Gas Pipeline Corporation (Transco), Columbia Gas Transmission
Corporation (Columbia) and several other major gas producers and marketers. In
1999, approximately 74% of our total available gas supply was purchased under
long-term contracts, in the spot market or from non-pipeline suppliers for
system supply, and approximately 26% was received for transportation to various
customers. We also provide propane gas to approximately 12,000 customers and,
until mid-1999, provided gas appliance sales and service to retail customers and
new homebuilders.
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The following is a summary of regulated operating revenues and other
operating data by major customer classification and non-regulated operating
revenues for the periods listed below:
<TABLE>
<CAPTION>
Three Months ended July 15, 1999- | October 1, 1998- Twelve Months ended
March 31, December 31, | July 14, September 30,
2000 1999 | 1999 1998 1997
---- ---- | ---- ---- ----
<S> <C> <C> | <C> <C> <C>
REVENUES (in 000's) |
Gas Revenues |
Residential $ 26,066 $ 14,259 | $ 40,267 $ 49,045 $ 49,046
Commercial 13,855 12,433 | 23,924 31,178 31,224
Industrial 22,770 59,712 | 56,482 72,732 76,604
Wholesale 9,429 12,464 | 18,429 21,492 24,829
---------- ---------- | --------- -------- --------
Total Regulated Revenues $ 72,120 $ 98,868 | $ 139,102 $174,447 $181,703
|
Non-Regulated Revenues $ 9,836 $ 2,636 | $ 30,685 $ 57,468 $ 53,831
---------- ---------- | --------- -------- --------
|
TOTAL REVENUES $ 81,956 $ 101,504 | $ 169,787 $231,915 $235,534
|
OTHER DATA |
Natural Gas Sales (in 000's dt) |
Residential 3,710 1,601 | 5,632 6,374 6,186
Commercial 2,261 2,165 | 4,179 5,248 5,099
Industrial 7,976 19,690 | 25,024 34,503 35,120
Wholesale 3,397 4,082 | 7,442 8,852 9,053
---------- ---------- | --------- -------- --------
Total Natural Gas Sales 17,344 27,538 | 42,277 54,977 55,458
Gas Sold 11,791 20,685 | 26,615 28,167 28,519
Gas Transported 5,553 6,853 | 15,662 26,810 26,939
|
Customers Billed (peak month) |
Residential 105,041 102,579 | 102,623 101,005 98,092
Commercial 13,969 13,856 | 13,798 13,707 13,065
Industrial and Electric Utilities 472 473 | 462 457 444
Wholesale 50,858 49,718 | 49,802 46,918 45,417
Propane 11,645 11,644 | 11,686 11,234 10,218
</TABLE>
Natural Gas Supply
During 1999, we purchased 10,218,285 dekatherms (dt) of natural gas under
our firm sales contracts with Transco. We also purchased 32,363,629 dt in the
spot market or under long-term contracts with producers or natural gas
marketers. We also transported 15,221,897 dt of customer-owned gas in 1999. The
outlook for natural gas supplies in our service area remains favorable, and many
sources of gas are available on a firm basis.
Our firm transportation contracts enable us to acquire gas directly from
producers or other natural gas marketers and have the gas transported on a firm
basis at delivered costs that reflect the market price of natural gas in any
month. Many of our industrial and large commercial customers have the
capability to burn a fuel other than natural gas, and these customers will
generally switch from gas when it costs more than the alternative fuel
(primarily residual oil, distillate oil or propane). Some of these same
customers prefer to acquire their own gas supplies, and we work with each
pipeline and the customers to arrange transportation service for them when
possible. Our primary objectives are to secure adequate and reliable gas
supplies on reasonable terms and conditions consistent with our obligation to
provide service to our firm service customers at the lowest reasonable cost.
Spot market purchases will continue to be utilized primarily in the off-peak
months (generally March through November) to supplement purchases under firm
supply agreements. The Transco firm sales contract provides gas supplies of up
to 55,935 dt/day, which we use to accommodate our supply needs resulting from
day-to-day changes in the level of demand on our system.
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We also own and operate a liquefied natural gas (LNG) storage plant that
provides 97,200 dt per day to our peak-day delivery capability and have capacity
under our contract with Pine Needle LNG Company, LLC, which owns and operates a
liquefied natural gas plant located in Guilford County, North Carolina near the
interconnection of Transco's pipeline with Cardinal Pipeline.
The following table summarizes the supply sources that are under contract
or otherwise available to us as of June 30, 2000:
<TABLE>
<CAPTION>
Maximum Contract
Daily Annual Expiration
Supply Source Contract/Supply Type Deliverability (a) Quantity (a) Date
------------- -------------------- ------------------ ------------ ----
(dt) (dt)
<S> <C> <C> <C> <C>
Transco........................ Firm Transportation 145,935 (b) 53,266,275 2013
Firm Sales 55,935 20,416,275 2001
General Storage 2,070 98,790 2013
Washington Storage 32,154 (c) 2,734,180 (c)
Liquefied Gas Storage 5,320 26,600 2016
Southern Expansion 16,871 (b) (d) 2,444,553 2005
Eminence Storage 39,373 (g) 316,914 2013
Columbia Gas Transmission...... Firm Transportation 9,801 (b) 3,577,365 2004
Firm Transportation 10,000 (b) 3,650,000 2004
Storage Transportation 5,199 (e) 1,421,835 2004
Firm Storage Services 5,199 (i) 223,238 2004
Columbia Gulf Transmission..... Firm Transportation 20,193 (e) (j) 5,231,515 2004
(b)
Cardinal Pipeline.............. Firm Transportation 41,400 (b) (k) 15,111,000 2019
Pine Needle LNG................ Liquified Natural Gas
Storage 41,400 414,000 2019
Hess Energy Services........... Firm Sales 15,000 (e) (f) 3,732,750 2004
Firm Sales 25,000 (f) 9,125,000 2001
Conoco, Inc.................... Firm Sales 10,000 (e) (f) 2,580,000 2001
Coral Energy Resources......... Firm Sales 25,000 (e) (f) 6,450,000 2001
Amoco Energy Trading Corp...... Firm Sales 25,000 (f) 9,125,000 2001
Columbia Energy................ Firm Sales 25,000 (f) 9,125,000 2001
PanCanadian Energy............. Firm Sales 25,000 (f) 9,125,000 2001
Exxon Company, U.S.A........... Firm Sales 15,000 (f) 5,475,000 2003
Southern Company Energy........ Firm Sales 25,000 (f) 9,125,000 2001
Marketing
MEG Marketing.................. Firm Sales 5,000 (d) (f) 755,000 2001
LNG Plant...................... Company Owned 97,200 (h) 1,000,000 N/A
</TABLE>
_______________________
(a) Quantities are shown in dekatherms. One dekatherm equals approximately
1,000,000 British thermal units (Btu) or one Mcf at 1,000 Btu/cu. ft.
(b) Firm transportation contracts are for pipeline capacity only. We are
responsible for acquiring our own gas supplies to be transported on a firm
basis under the firm transportation contracts with Transco and Columbia
Gulf. Gas supplies are available under the Transco firm sales agreement,
other long-term agreements (see footnote (f) below),
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multi-month term agreements or agreements of one month or less for supplies
purchased in the spot market.
(c) Washington storage volumes may be withdrawn to the extent that the gas
supplied by Transco or other contract suppliers is unavailable on any day or
if we elect to take such gas instead of other gas supplies. Service has
continued subsequent to contract expiration under provisions of Transco's
Federal Energy Regulatory Commission, or FERC, tariff. FERC approval of
abandonment would be required to terminate service.
(d) Winter months only (November through March).
(e) Provides for a lower daily deliverability volume in the summer period (April
through October).
(f) Contracts are for gas supply only; no pipeline capacity is included. Gas
purchased from these suppliers flows on our firm transportation contracts
with Transco or Columbia (see footnote (b) above).
(g) Transco salt dome storage capacity allocated to customers of Transco firm
sales service under FERC Order 636. Transco schedules injections and
withdrawals of gas from eminence storage capacity under agency agreements
with us and the other firm sales service customers.
(h) Transmission pipeline capacity to distribute supplies withdrawn from storage
at our LNG plant under normal operating conditions.
(i) Delivered via storage transportation.
(j) Delivered via Columbia Gas Transmission.
(k) Link between Transco and our system near Clayton, North Carolina.
Franchises
We hold a certificate of public convenience and necessity granted by the
North Carolina Utilities Commission to provide service to our current service
area. Under North Carolina law, no company may construct or operate properties
for the sale or distribution of natural gas without such a certificate, except
that no certificate is required for construction in the ordinary course of
business or for construction into territory contiguous to that already occupied
by a company and not receiving similar service from another utility.
We have nonexclusive franchises from 71 municipalities in which we
distribute natural gas and four municipalities to which we sell or transport gas
for resale. The expiration dates of those franchises that have specific
expiration provisions range from 2000 to 2020. The franchises are substantially
uniform in nature. They contain no restrictions of a materially burdensome
nature and are adequate for our business. In addition, we serve 39 communities
from which no franchises are required.
On July 28, 1998, the North Carolina Utilities Commission initiated a
review to determine whether we were providing adequate service to at least some
portion of the 47 counties in our franchise territory. Hearings were held
December 7 and 8, 1998. On March 17, 1999, the North Carolina Utilities
Commission issued an order requiring us to forfeit our exclusive franchise
rights to 14 of 17 unserved counties in eastern North Carolina for failing to
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adequately serve these counties. Furthermore, the order required us to complete
our expansion project to provide service in the remaining three counties
(Bertie, Martin and Onslow) by July 1, 2000. These projects are substantially
complete as of the date of this document. We do not expect the loss of exclusive
franchise rights to serve these 14 counties to have a material adverse impact on
our future prospects.
Seasonal Nature of Our Business
Our business is seasonal in nature. Cold weather affects customer demand
in high priority markets and generally results in greater earnings during the
winter months. In our October 1995 General Rate Order, residential and
commercial rates were increased while industrial rates were decreased. This
action further increased the seasonal variation in our revenues, margins and
earnings because residential and commercial consumption increases in the winter
months and industrial consumption increases in the summer months. However, our
deliveries to high load factor industrial customers, together with summer season
deliveries for agricultural crop drying and electricity generation, help to
minimize quarterly variations in throughput volumes and earnings.
We normally inject gas into storage during periods of warm weather and
withdraw it during periods of cold weather. The storage and various other
contracts shown in the table under the Natural Gas Supply section provide
adequate daily supply to meet our peak-day requirements.
Unregulated Businesses
We have four subsidiaries that are not regulated by the North Carolina
Utilities Commission:
. NCNG Energy Corporation, which is involved in energy related
investments and sales to natural gas resellers;
. NCNG Pine Needle Investment Corporation, which participates in gas
supply and pipeline projects in North Carolina;
. NCNG Cardinal Pipeline Investment Corporation, which holds a 5%
ownership interest in a limited liability company formed to acquire
an existing pipeline and extend that pipeline's gas delivery
capacity;
. Cape Fear Energy Corporation, which was involved in natural gas
marketing for industrial and municipal customers on our system.
These activities were phased out in mid-1999.
We also operate a propane division, which engages in the sale of propane to
customers who do not have access to natural gas. Sales of propane increased 13%
from 1998 to 7.2 million gallons in 1999 due to the addition of 600 new
customers and colder weather. Pretax income from our propane division increased
to $1.6 million in 1999, compared to $1.25 million in fiscal 1998, due to a 17%
increase in gross margin on propane sales resulting from the addition of higher
margin residential customers.
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Until mid-1999, we also operated an appliance sales and service division,
which sold, installed and maintained gas appliances. For the period from January
1, 1999 through August 31, 1999, sales of the appliance division were
approximately $1.0 million.
In response to the growth of the natural gas business in North Carolina, we
established a new subsidiary, NCNG Energy Corporation, in August 1995 to
participate in two partnerships with subsidiaries of Transco, Piedmont Natural
Gas Company and Public Service Company of North Carolina, Inc. involving gas
supply and pipeline projects affecting the entire state of North Carolina. NCNG
Energy transferred its ownership in these two projects to two new subsidiaries,
NCNG Pine Needle Investment Corporation and NCNG Cardinal Pipeline Investment
Corporation. NCNG Pine Needle is a 5% equity owner in Pine Needle LNG Company,
LLC. The other Pine Needle LNG partners are the Municipal Gas Authority of
Georgia and subsidiaries of Transco, Piedmont, Public Service Company of North
Carolina and Amerada Hess Corporation. Pine Needle LNG Company owns and
operates a 4 Bcf liquefied natural gas plant at a site near Transco's main
interstate pipeline north of Greensboro, North Carolina. This facility became
operational in May 1999. We have contracted for 10%, or 400,000 Mcf annually, of
the liquified natural gas capacity to support continuing growth in our customer
base expected over the next five years.
Additionally, NCNG Cardinal Pipeline and its partners organized Cardinal
Expansion Company, LLC, which took over an existing intrastate pipeline formerly
owned by Piedmont Natural Gas and Public Service Company of North Carolina and
extended it from Burlington, North Carolina to an interconnection with our
system and that of Public Service Company of North Carolina southeast of Raleigh
at Clayton, North Carolina. The expanded pipeline enables us to add substantial
volumes of natural gas year round to the middle of our system. NCNG Cardinal
Pipeline has a 5% equity interest in Cardinal Expansion Company. This facility
became operational in November 1999.
Regulations and Rates
The North Carolina Utilities Commission regulates our rates, service area,
adequacy of service, safety standards, acquisition, extension and abandonment of
facilities, accounting and sales of securities. We operate only in North
Carolina and are not subject to federal regulation as a "natural gas company"
under the Natural Gas Act.
On October 27, 1995, the North Carolina Utilities Commission issued an
order granting a general rate increase of $4.2 million in annual revenues
effective November 1, 1995. The Commission's order approved, in all material
respects, a stipulation of settlement reached among us, the Public Staff of the
North Carolina Utilities Commission, the Carolina Utility Customers Association,
Inc. and other intervenors in the rate case. The order provides for a rate of
return on net investment of 10.09%, but, pursuant to the stipulation of
settlement, did not state separately the rate of return on common equity or the
capital structure used to calculate revenue requirements. The order provides for
significant rate design changes by increasing residential and commercial rates
while reducing industrial sales and transportation rates to recognize, among
other things, the differences in costs of serving various customer classes. The
order establishes several new rate schedules, including an economic development
rate to assist in attracting new industry to our service area and a rate to
provide standby, on-peak gas supply service to industrial and other customers
whose gas service would otherwise be interrupted.
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As part of the October 27, 1995 order, the North Carolina Utilities
Commission also approved:
. Continuation of the weather normalization adjustment mechanism originally
approved in 1991. The weather normalization adjustment mechanism is discussed
in greater detail below.
. Establishment of a price sensitive volume adjustment mechanism that became
effective November 1, 1995. The price sensitive volume adjustment excludes
from our revenue requirement the margin from eight large, fuel-switchable
customers, and requires that all actual margins earned on deliveries of gas
to such customers be passed through to all other customers.
. An increase in depreciation rates for certain distribution plant. The
increased depreciation rates account for approximately $750,000 of the $4.2
million annual revenue increase.
. The accounting for and recovery in rates of costs associated with
environmental assessment and remediation of a former manufactured gas plant
site. The North Carolina Utilities Commission approved our proposal to
recover an annualized amount of manufactured gas plant costs based on amounts
expended, net of recoveries from third parties.
The weather normalization adjustment benefits both us and our space-heating
customers by reducing large swings in our customers' bills and our revenues due
to fluctuations in winter weather. This weather normalization adjustment rider
increases the margins on our temperature-sensitive load during warmer-than-
normal winter weather and decreases the margin during colder-than-normal winter
weather. In the 15 months ended December 31, 1999, winter weather was
approximately 15.5% warmer than normal and, accordingly, the weather
normalization adjustment increased net billings to customers by approximately
$5.4 million.
The North Carolina Utilities Commission, in a general rule making
proceeding, revised its purchased gas adjustment procedures in April 1992. The
revised procedures continue to allow us to recover all of our prudently incurred
gas costs, but such procedures provide for several significant changes that
include:
. the establishment of a benchmark commodity cost of gas, which
represents our estimate of the actual commodity cost of gas from all
suppliers that we will incur in a future period;
. the recovery of 100% of prudently incurred fixed costs of pipeline
capacity and storage costs, including costs of any new capacity added
since the last general rate case;
. the reduction of the notice period for requesting purchased gas
adjustment rate changes from 30 days to 14 days;
. the establishment of a tariff provision that allows us to recover
margin losses from negotiated rates to large non-price sensitive
volume adjustment commercial and industrial customers;
. a true-up of fixed gas costs recovered from our customers;
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. a true-up of our lost, unaccounted for and company use volumes
compared to such volumes included in the last general rate case; and
. an annual review of our gas costs, including the prudence thereof, by
the North Carolina Utilities Commission and a hearing before the North
Carolina Utilities Commission. The annual review of our gas costs for
the 12 months ended October 31, 1998 was held in April 1999. The North
Carolina Utilities Commission found our gas costs and gas purchasing
practices to be prudent, as it had in all previous reviews. The North
Carolina Utilities Commission is expected to report its conclusion
with respect to our annual prudency review for the 12 months ended
October 31, 1999 during the third quarter 2000.
In August 1995, the North Carolina Utilities Commission issued an order
approving our first expansion project to utilize the expansion fund established
for our system under legislation passed by the North Carolina General Assembly
in 1991. The project extended our transmission pipeline 72 miles from Mount
Olive to the Camp Lejeune Marine Base in Jacksonville, North Carolina. In 1998,
we constructed the first 20-mile segment of 10-inch pipeline to Warsaw in Duplin
County and continued acquiring rights-of-way and performing necessary
environmental studies for the remainder of the route. This project was
substantially completed in September 1999. We also utilized the expansion fund
for an approximate 44-mile expansion project in Bertie and Martin Counties. This
project was completed during the fourth quarter of 1999.
In August 1999, we filed with the North Carolina Utilities Commission our
annual true-up of lost, unaccounted for and company use volumes for the 12
months ended June 30, 1999. Because such volumes were less than the base period
amounts included in the 1995 general rate case, we refunded $76,669 in 1999 from
the true-up by crediting that amount to our deferred gas cost account for future
reduction in rates to customers.
The North Carolina Utilities Commission issued an order effective November
1, 1995, revising the sharing mechanism for buy/sell and interstate pipeline
capacity release transactions. This order broadened the scope of covered
transactions to include all "secondary market transactions" that involve use of
the local distribution company's firm transportation or storage capacity rights
on pipelines, the capacity costs of which are recovered from utility customers.
This order changed our customers' and our portion of the sharing of net
compensation from 90%/10% to 75%/25%. Total secondary market revenues decreased
to $335,000 in 1999 compared to $3.0 million in 1998 due primarily to lower
transportation volumes.
Both of our interstate pipeline suppliers, Transco and Columbia, have
ongoing rate and certificate matters under jurisdiction of FERC. We do not
expect any regulatory decisions or court orders to have a material impact on our
financial condition, results of operations, or cash flows because all prudently
incurred gas costs, including interstate pipeline capacity and storage service
costs, are eligible for immediate recovery from our customers, and refunds from
interstate pipelines must be transferred to the expansion fund or directly
refunded to our customers.
In conjunction with CP&L's acquisition of us, we signed a joint stipulation
agreement with the North Carolina Utilities Commission in which we agreed to cap
margin rates for gas sales and transportation services, with limited exceptions,
through November 1, 2003. We believe that this agreement will not have a
material adverse effect on our results of operations, financial condition, or
cash flows.
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Competition
The natural gas industry continues to evolve into a more competitive
environment. We have competed successfully with other forms of energy such as
electricity, residual fuel, distillate fuel oil, propane and, to a lesser
extent, coal. The principal competitive considerations have been price and
accessibility. We have the lowest residential natural gas rates in North
Carolina and are in a favorable competitive position. With the exception of
four municipalities that operate municipal gas distribution systems within our
service territory, we are the sole distributor of natural gas in our franchised
service territory.
Further unbundling of services to commercial and residential customers
could increase competition for commodity sales services, but not for the
distribution of natural gas. We do not expect the North Carolina Utilities
Commission to require further unbundling in the near future. We have a balanced
gas supply portfolio that provides security of supply at the lowest reasonable
cost, as determined by the North Carolina Utilities Commission in all of our
prior annual prudency reviews.
During 1999, approximately 54% of total throughput on our system was sold
to customers having alternative fuel usage capabilities under interruptible
rates. However, our purchased gas adjustment rider allows us to negotiate rates
lower than the filed tariff rates and to recover the lost margin from our
other core market customers to encourage industrial customers to remain on the
system when the price of their alternative fuel is lower than the gas tariff
rate. The price sensitive volume adjustment requires that all margins earned
from the eight customers subject to the adjustment be passed through to all
other customers. Although we have historically benefited from the favorable
spread between the prices of both No. 2 fuel oil and propane, as compared to
natural gas, and have remained competitive in most instances with No. 6 fuel
oil, the market could be affected by volatility in the price of fuel oil as well
as increases in the price of natural gas.
Environmental Matters
The provisions of the Comprehensive Environmental Response, Compensation
and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the
clean up of certain contaminated sites. This statute imposes retroactive joint
and several liability upon various classes of "responsible parties." Some
states, including North Carolina, have similar types of legislation. There are
presently several sites with respect to which we have been notified by the EPA
or the State of North Carolina of our potential liability, as described below in
greater detail.
Various materials associated with the historical production of manufactured
gas are regulated under various federal and state laws. There are several
manufactured gas plant sites (MGPs) to which we have some connection. Along with
others, we are participating in a cooperative effort with the North Carolina
regulatory authorities to address the MGPs. The investigation and remediation of
the MGPs will be addressed pursuant to a consent order between the state and
responsible parties. We continue efforts to identify other parties who may be
responsible for cleanup costs at MGPs, and whose
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participation in cleanups would reduce our cost of participation. We do not
expect the costs associated with these sites to be material to our consolidated
results of operations, financial condition, or cash flows.
We are occasionally notified by environmental regulators of our involvement
or potential involvement at sites, other than MGPs, that may require
investigation and remediation. Although we may incur costs at these sites of
which we have been notified, based upon the current status of these sites, we do
not expect those costs to be material to our consolidated results of operations,
financial condition, or cash flows.
We have filed claims with our general liability insurance carriers to
recover costs arising out of actual or potential liabilities. Some claims have
settled, and others are pending. While we cannot predict the outcome of these
matters, we do not expect the outcome to have a material impact on our
consolidated results of operations, financial condition, or cash flows.
Employees
At March 31, 2000, we had 378 full-time employees. Employee relations are
good and we have not had any material work stoppage due to labor disagreements.
Through CP&L, and after August 1, 2000, CP&L Energy, we have a noncontributory
employee retirement plan for substantially all regular employees, an employee
stock purchase-savings plan, a group life and medical insurance program, and
other customary employee benefits.
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A Caution About Forward-Looking Statements
Statements made in our Management's Discussion and Analysis of Financial
Condition and Results of Operations and throughout this registration statement
that are not historical in fact are forward-looking statements and, accordingly,
involve estimates, projections, goals, forecasts, assumptions, risks and
uncertainties that could cause actual results or outcomes to differ materially
from those expressed in the forward-looking statements. In connection with the
safe harbor provisions of the Private Securities Reform Act of 1995, we caution
that, while we believe such statements to be reasonable and make them in good
faith, the actual results almost always vary, depending on the circumstances.
You should be aware of important factors that could have a material impact on
future results. These factors include, but are not limited to:
. weather;
. legislative and regulatory initiatives with respect to, among others,
allowed rates of return, industry and rate structure, competition, and
our ability to access and utilize the expansion fund;
. financial market conditions, including the availability of public debt
financing at reasonable rates;
. economic trends and interest rates;
. unanticipated population growth or decline in our current and
prospective markets;
. consumer preferences and market demand;
. competition;
. general industry trends;
. unanticipated changes in operating expenses and capital expenditures;
. the successfulness of CP&L's reorganization into a holding company and
the impact of the transfer by CP&L of its ownership in us to CP&L
Energy; and
. legal and administrative proceedings.
These factors are difficult to predict and may contain uncertainties that
may materially affect the actual results that are beyond our control. New
factors may emerge in the future and we cannot predict what these factors may be
nor can we assess the impact of the new factors.
Any forward looking statement speaks only as of the date on which it was
made, and we do not undertake any obligation to update any forward looking
statement to reflect events or circumstances after the date on which the
statement was made.
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ITEM 2. FINANCIAL INFORMATION.
We present below selected historical and pro forma financial and operating
data. The selected historical and pro forma financial data presented below
should be read in conjunction with our consolidated and pro forma financial
statements and their respective accompanying notes included elsewhere in this
registration statement. We derived the selected historical financial data as of
and for the fiscal years ended September 30, 1995 through September 30, 1998, as
of July 14, 1999 (pre-merger) and December 31, 1999 (post-merger), and for the
periods October 1, 1998 to July 14, 1999 (pre-merger) and July 15, 1999 to
December 31, 1999 (post-merger) from our audited consolidated financial
statements. We have derived the pro forma financial data for the twelve months
ended December 31, 1999 from our unaudited pro forma consolidated condensed
statement of operations for the twelve-month period ended December 31, 1999.
Periods ending at December 31 reflect a change in our fiscal year end to conform
to the fiscal year end of CP&L.
Our merger with CP&L was accounted for using the purchase method of
accounting, and the applicable effects were reflected in our financial
statements as of the merger date, July 15, 1999. Accordingly, the post-merger
financial statements reflect a new basis of accounting. We derived the selected
historical financial data as of and for the three months ended March 31, 1999
and March 31, 2000 from our unaudited consolidated financial statements. Because
of the seasonal nature of our business, the results of operations for the
three-month periods ended March 31 are not necessarily indicative of the results
for the full year.
The unaudited pro forma consolidated condensed statement of operations for
the twelve-month period ended December 31, 1999 gives effect to the following
transactions: (i) the acquisition of us by CP&L as if the transaction had
occurred on January 1, 1999 and (ii) the advance refunding of our outstanding
debt using proceeds of a CP&L revolving credit facility as if the merger had
occurred on January 1, 1999 and the subsequent advance refunding had occurred an
equivalent length of time following the pro forma merger effective date.
13
<PAGE>
<TABLE>
<CAPTION>
Fiscal Years Ended September 30,
-----------------------------------------------------------------
1995 1996 1997 1998
---- ---- ---- ----
(in thousands, except ratio data)
<S> <C> <C> <C> <C>
Income Statement Data:
Operating Revenues.............................. $170,189 $235,201 $235,534 $231,915
Gross Margin.................................... 62,819 74,769 79,262 81,314
Net Income...................................... 11,809 15,173 17,594 17,148
Balance Sheet Data (end of period)
Total Assets.................................... $214,880 $232,779 $253,251 $271,438
Total Long-Term Debt............................ 62,000 63,000 61,000 59,000
Stockholders' Equity............................ 92,778 101,958 113,223 123,201
Other Data:
Capital Expenditures............................ $ 22,581 $ 15,831 $ 30,500 $ 36,652
Net Utility Plant (end of period)............... 178,796 184,434 203,560 225,139
Ratio of Earnings to Fixed Charges (1).......... 4.33x 5.32x 5.72x 5.14x
</TABLE>
<TABLE>
<CAPTION>
Pro Forma
Twelve
Months Three Months
October 1, October 1, Ended Ended
1997 to 1998 to July 15-December 31, December March 31,
July 14, July 14, -------------------- 31, ---------------------
1998 1999 1998 | 1999 1999 1999 | 2000
---- ---- ---- | ---- ---- ---- | ----
(unaudited) (audited) (unaudited)|(audited) (unaudited) (unaudited)
(in thousands, except ratio data)
<S> <C> <C> <C> |<C> <C> <C> | <C>
Income Statement Data: | |
Operating Revenues......... $191,099 $169,787 $ 90,858 |$101,504 $221,249 $ 69,953 | $ 81,956
Gross Margin............... 69,250 67,119 32,596 | 32,606 79,193 30,529 | 30,097
Net Income................. 17,040 10,683 4,959 | 1,379 4,054 10,295 | 10,228
| |
Balance Sheet Data: | |
(end of period) | |
Total Assets............... $267,985 $300,338 $286,878 |$567,436 n.a. $297,118 | $558,661
Total Long-Term Debt....... 59,000 52,500 59,000 | -- n.a. 59,000 | --
Stockholders' Equity....... 124,942 126,556 126,190 | 365,102 n.a. 134,827 | 375,330
| |
Other Data: | |
Capital Expenditures....... $ 28,717 $ 38,114 $ 20,785 |$ 27,198 n.a. $ 11,776 | $ 9,531
Net Utility Plant (end of | |
period)................... 219,602 248,490 233,270 | 259,184 n.a. 240,948 | 261,637
Ratio of Earnings to | |
Fixed Charges (1)......... 6.54x 4.62x 3.19x | 1.80x 2.55x 9.54x | 8.74x
</TABLE>
_____________________
(1) We define "earnings" as net income before income taxes plus fixed charges
less allowances for funds used during construction. We define "fixed charges"
as the sum of interest on long-term debt, other interest, and amortization of
debt discount and expense.
14
<PAGE>
Management's Discussion and Analysis of Financial Condition and Results of
Operations
The Company
We are a wholly owned subsidiary of CP&L Energy. We are engaged primarily
in the business of transporting and distributing natural gas at regulated retail
rates to customers in 110 cities, towns and communities, as well as at regulated
wholesale rates to four municipal gas distribution systems, in south-central and
eastern North Carolina. Our natural gas operations are regulated by the North
Carolina Utilities Commission. We also have unregulated operations which
historically have included a propane division and an appliance sales and
service division, as well as subsidiaries which market gas to on-system and off-
system customers. For the fiscal year ended September 30, 1998, and during
calendar year 1999, we served approximately 173,000 and 178,000 customers,
respectively.
We were acquired by CP&L on July 15, 1999. The merger with CP&L was
accounted for using the purchase method of accounting and the effects of the
merger are reflected in our financial data as of the merger date. Following our
merger with CP&L, our subsidiaries elected to phase out all unregulated
marketing activities in response to restrictions imposed under the terms of a
Code of Conduct and Regulatory Conditions ordered by the North Carolina
Utilities Commission. In mid-1999, we exited the appliance sales and service
business. We continue to expand our transmission and distribution systems to
keep pace with the economic development and residential, commercial and
industrial customer growth in our service area. Our financial position and
results of operations are substantially dependent upon our receiving adequate
and timely increases in rates, which are regulated by the North Carolina
Utilities Commission. In connection with our merger with CP&L, we signed a
stipulation agreement with the Public Staff of the North Carolina Utilities
Commission in which we agreed to cap margin rates for gas sales and
transportation service, with limited exceptions, through November 1, 2003. We
do not expect this agreement to have a material adverse impact on our
consolidated financial condition, results of operations or cash flows.
Our business is seasonal in nature as fluctuations in weather dictate
injecting and withdrawing from storage and billings to residential and
commercial customers. Injections of natural gas into storage and a reduction in
customer billings occur during periods of warm weather (April through October).
Withdrawals from storage and increased customer billings occur during periods of
cold weather (November through March). Our weather normalization adjustment
ratemaking mechanism largely mitigates the change in margin resulting from
fluctuations in weather patterns, and applies to residential and commercial
customers, including municipal sales, from November 16 to April 15 of each year.
Our regulated revenues include revenues from both gas sold to customers and
for transportation of customer-owned gas. Our revenues from transportation are
lower than from sales because we do not incur or bill the commodity cost of gas
for transported volumes. However, as a result of regulatory pricing mechanisms,
we generally earn the same margin on a dekatherm (dt) of gas whether transported
or sold because transportation rates exclude only the commodity cost of gas,
which the customer pays directly to its supplier, and any related taxes. These
regulatory pricing mechanisms may be amended or discontinued at the discretion
of the North Carolina Utility Commission.
15
<PAGE>
Recoverable purchased gas costs and refunds payable primarily represent the
difference between our benchmark gas cost rate charged to customers and the
actual cost of gas, including demand charges. If our benchmark rate charged to
customers exceeds the actual cost of gas, recoverable purchased gas costs will
decrease and refunds payable will increase. Should the benchmark rate charged
to customers be less than the actual cost of gas, refunds payable will decrease
and recoverable purchased gas costs will increase. It is our policy to manage
the benchmark cost of gas to minimize, when possible, large over- or under-
recoveries.
In the natural gas distribution industry, gross margin, rather than
revenues, has become the standard indicator of our results of operations. Two
factors account for this change: (1) the steadily increasing number of customers
acquiring their own gas supplies and utilizing the gas utility for
transportation only, and (2) the increased volatility in the commodity price of
natural gas. We earn the same profit margin on transportation of customer-owned
gas as we earn from bundled sales service to those customers. However, changes
in the mix of transportation and sales volumes can have a significant impact on
operating revenues and cost of gas, because the commodity cost of gas associated
with transportation volumes is paid by the customer directly to the customer's
supplier and, therefore, we do not incur or bill the cost of the commodity.
Our non-regulated revenues include revenues from our propane division and,
for the periods prior to 2000, gas marketing revenues from our marketing
subsidiaries, as well as revenues from our appliance sales and service
division. Our appliance sales and service division was discontinued in August
1999.
Our capital requirements reflect the capital-intensive nature of our
business and are attributable principally to our construction program, debt
service and working capital requirements such as receivables and gas in storage.
We have historically relied on short term loans from banks and cash flows from
operations to finance construction expenditures. We currently utilize a $150
million revolving credit facility from CP&L for our borrowing needs.
Results of Operations
The Three-Months Ended March 31, 2000 Compared to the Three Months Ended
March 31, 1999
Revenues and Cost of Gas. Operating revenues increased $12.0 million for
the period ended March 31, 2000 as compared to the period ended March 31, 1999,
which was caused by increased total throughput due to weather that was 2% colder
than the weather for the same period in the previous year and due to an increase
in customer base in the residential and commercial classes. The increase was
also caused by mix changes between sales and transportation volumes to
industrial and municipal customers. Customers that used the transportation
rate in the prior period purchased bundled services during the current period
due to the market price for gas being higher than our benchmark price for gas.
Cost of gas increased $12.4 million, which was caused by increased total
throughput due to weather that was 2% colder than the weather for the same
period in the previous year and due to an increase in customer base in the
residential and commercial classes. The increase was also
16
<PAGE>
caused by increased sales of gas and decreased transportation of customer-owned
gas for the three-month period ended March 31, 2000.
Throughput and Margin. The chart below compares margins for the three-
months ended March 31, 2000 and 1999 by customer class (in thousands):
<TABLE>
<S> <C> <C>
Customer Class 2000 1999
-------------- ---- ----
Residential...................... $11,430 $11,413
Commercial....................... 5,394 6,221
Industrial....................... 8,137 7,249
Municipal........................ 3,261 3,251
Non-utility...................... 1,875 2,395
------- -------
Total............................ $30,097 $30,529
======= =======
</TABLE>
Gross margin decreased $432,000 for the three-month period ended March 31,
2000. Residential margins increased slightly due to colder weather in the three-
month period ended March 31, 2000 than the same period in the previous year and
increased facilities charges due to an increase in customer base. Our weather
normalization adjustment largely mitigates the change in margin from residential
and commercial customers due to fluctuations in weather patterns, and is in
effect from November 16 to April 15 of each year. The decrease in commercial
margin and increase in industrial margin is primarily due to our classifying
several small industrial customers differently in the three months ended March
31, 2000 than in the three months ended March 31, 1999. We reclassified the
small industrials into the industrial customer class in the 2000 period for
consistency purposes in regulatory reporting. The reclassified customers
accounted for approximately 13% of the commercial margin for the three months
ended March 31, 1999. We exited the appliance business during 1999, which
resulted in the decrease in margin in the nonutility customer class.
Our total throughput volumes for the period increased by 688,000 dt to 17.3
million dt. Commercial, residential and municipal volumes increased 519,000 dt,
207,000 dt and 73,000 dt, respectively. Industrial volumes decreased 178,000
dt. The overall increase in volumes was due to weather that was 2% colder than
the same period last year and due to an increase in the commercial and
residential customer bases. Transportation volumes decreased for the three-
month period ended March 31, 2000 due to the benchmark commodity cost of gas in
our rates being lower than the spot market price of natural gas. This caused
customers who normally transport on our system to purchase their natural gas
supplies on a bundled sales rate from us.
Operating Expenses. Operating and maintenance expenses decreased $343,000
for the three months ended March 31, 2000 as compared to the same period last
year. The decrease was primarily due to downsizing resulting from our
purchase by CP&L. The downsizing reduced the overhead related to the labor
force in many operational areas and reduced general and administrative expenses.
Depreciation and amortization expense increased approximately $1.8 million
primarily due to the amortization of goodwill recorded in the purchase
transaction by CP&L, which was pushed down to us.
17
<PAGE>
General taxes decreased approximately $2.0 million due to the gross
receipts tax being eliminated by state law in July 1999. The gross receipts tax
was replaced by an excise tax, which is a component of operating revenues and
cost of sales, as it is passed through to the customer.
Net Income. We earned $10.2 million for the three months ended March 31,
2000, compared to $10.3 million for the three months ended March 31,1999.
The Period From July 15, 1999 to December 31, 1999 Compared to the Period
From July 15, 1998 to December 31, 1998
Revenues and Cost of Gas. Operating revenues increased $10.6 million for
the period ended December 31, 1999, as compared to the same period in the
previous year. The increase for the period was caused by mix changes between
transportation and sales volumes to industrial and municipal customers. In
addition, weather that was 9% cooler than the weather for the same period in the
previous year resulted in increased total throughput.
Cost of gas increased $10.6 million for the period ended December 31, 1999,
as compared to the same period in the previous year. The increase for the
period was caused by mix changes between transportation and sales volumes to
industrial and municipal customers. In addition, the increase in throughput was
due to weather that was 9% cooler than the weather for the same period in the
previous year.
Throughput and Margin. Weather for the period ended December 31, 1999 was
16% warmer than normal but 9% cooler than the weather for the period ended
December 31, 1998. Our total throughput volumes for the December 31, 1999 period
increased by 2.4 million dt to 25.2 million dt. Commercial, residential,
wholesale and industrial volumes increased 151,000 dt, 181,000 dt, 250,000 dt
and 1.8 million dt, respectively. Throughput for all customers increased
relative to the prior period due to comparatively cooler weather.
The chart below compares margins for the period July 15, 1999 - December
31, 1999 and the same period ended December 31, 1998 by customer class (in
thousands):
Customer Class 1999 1998
-------------- ---- ----
Residential............. $ 9,292 $ 9,130
Commercial.............. 5,269 5,096
Industrial ............. 13,609 12,647
Municipal............... 3,232 3,097
Non-utility............. 1,204 2,626
------- -------
Total................... $32,606 $32,596
======= =======
Gross margin for the period ended December 31, 1999, was relatively flat
compared to the same period in the previous year. Positively affecting the
period ended December 31, 1999 was (1) customer growth in the higher margin
residential and commercial markets and (2) an increase in throughput for all
customer classes. This was offset by a decrease in non-utility margins due to
lower sales volumes of propane and our exit from the merchandising business.
18
<PAGE>
Operating Expenses. Total operating expenses, excluding the cost of gas
sold, increased to $25.8 million for the period ended December 31, 1999,
compared to $22.8 million for the same period in 1998. The increase in 1999 was
due primarily to $2.8 million of goodwill amortization which was pushed-down to
us in connection with CP&L's acquisition of us.
Net Income. We earned $1.4 million for the period ended December 31, 1999,
compared to $5.0 million for the period ended December 31, 1998. The 72.2%
decrease in net income for the period ended December 31, 1999 compared to the
same period ended December 31, 1998 was primarily due to a decline in
nonregulated margins, resulting from our discontinued gas marketing activities
and costs associated with exiting the merchandising business as well as an
increase in operating expenses as discussed above.
The Period From October 1, 1998 to July 14, 1999 Compared to the Period
From October 1, 1997 to July 14, 1998
Revenues and Cost of Gas. Operating revenues decreased $21.3 million for
the period ended July 14, 1999, as compared to the same period in the previous
year. The decrease for the period was caused by mix changes between
transportation and sales volumes to industrial and municipal customers and a
lower average commodity cost of gas. In addition, warmer-than-normal weather
negatively affected total natural gas throughput as well as propane sales.
Cost of gas decreased $19.2 million for the period ended July 14, 1999, as
compared to the same period in the previous year. The decrease for the period
was caused by mix changes between transportation and sales volumes to industrial
and municipal customers and a lower average commodity cost of gas. In addition,
this decrease in throughput was due to warmer-than-normal weather and a decrease
in the average commodity cost of gas as compared to the previous year.
Throughput and Margin. The weather for the period ended July 14, 1999 was
15% warmer than normal but 4% cooler than the period ended July 14, 1998. Our
total throughput volumes for the period ended July 14, 1999 decreased by 375,000
dt to 42.2 million dt as compared to the same period in the previous year.
Commercial, residential and wholesale volumes decreased 424,000 dt, 153,000 dt,
and 72,000 dt, respectively, while industrial volumes increased 274,000 dt. The
overall decrease in throughput volumes was due to decreased volumes to
commercial, residential, and wholesale customer classes resulting from warmer-
than-normal weather and slowed customer growth. The decrease was partially
offset by higher volumes to industrial customers due to an increased customer
base.
19
<PAGE>
The chart below compares margins for the period October 1, 1998 - July 14,
1999 to the same period ended July 14, 1998 by customer class (in thousands):
Customer Class 1999 1998
-------------- ---- ----
Residential.......... $23,026 $23,106
Commercial........... 12,466 13,855
Industrial........... 20,211 19,953
Municipal............ 6,578 6,766
Non-utility.......... 4,838 5,570
------- -------
Total................ $67,119 $69,250
======= =======
Gross margin decreased $2.1 million for the period ended July 14, 1999,
compared to the same period in the previous year. Negatively affecting the
period was (1) slowed customer growth in the higher margin residential and
commercial markets; (2) a decrease in throughput in the higher margin
residential and commercial markets; and (3) a decrease in non-utility margins
due to lower sales volumes due to warmer-than-normal weather. The weather
normalization adjustment helped to offset the lower margins as the weather was
15% warmer than normal for the period ended July 14, 1999.
Operating Expenses. Operating and maintenance expenses increased $5.1
million for the period ended July 14, 1999, as compared to the same period in
the previous year. The increase was primarily due to approximately $4.0 million
of merger related costs incurred in connection with our merger with CP&L.
Net Income. Our net income was $10.7 million, for the period ended July
14, 1999, compared to $17.0 million for the same period in the previous year.
Fiscal Year Ended September 30, 1998 Compared to the Fiscal Year Ended
September 30, 1997
Revenues and Cost of Gas. In fiscal year 1998, our transportation service
volumes were down slightly to 26.8 million dt compared to 26.9 million dt in
fiscal year 1997. Sales volumes for 1998 were also down slightly to 28.1 million
dt compared to 28.5 million dt in 1997. In general, the margin earned on gas
transported is equal to the margin earned on gas sold; however, transportation,
which replaces sales, results in lower revenues because transportation rates
exclude the commodity cost of gas which is paid by the customer directly to its
gas supplier. We still delivered the gas and earned transportation revenue
equivalent to the margin contained in a companion sales rate. In addition, we
indirectly earned additional margin from transportation customers who chose to
purchase gas from our marketing subsidiary. Our operating revenues and cost of
sales include both our regulated and unregulated business and our subsidiaries.
In 1998, our operating revenues and cost of sales decreased $3.6 million
and $5.7 million, respectively, primarily due to lower throughput volumes and a
7% decrease in the average cost of gas.
Throughput and Margin. The weather for fiscal year 1998 was 19% warmer
than normal and 2% cooler than 1997. Our total throughput volumes in 1998
decreased by 480,000 dt to 55.0
20
<PAGE>
million dt. Commercial and residential volumes increased by 149,000 dt and
188,000 dt, respectively, while wholesale and industrial volumes decreased
223,000 dt and 594,000 dt, respectively. The overall decrease in throughput
volumes was due to decreased volumes to wholesale municipal customers as a
result of warmer-than-normal weather and lower throughput to interruptible
industrial customers resulting from some plant closings and low alternative fuel
prices, primarily No. 6 oil. This was offset by higher volumes to the
residential and commercial customer classes due to a customer growth rate of
approximately 3% as well as increased volumes to firm service industrial
customers.
We continued adding natural gas customers at an above-average growth rate
in 1998. The addition of about 6,000 customers in 1998 represented a growth rate
of 3.5%, compared to the national average of less than 2% for all natural gas
distribution utilities. Even though warmer-than-normal weather in the winter
decreased per customer sales of gas to residential and commercial customers, we
did not realize a proportional decrease in margins from such customers because
of the operation of the weather normalization adjustment which stabilizes our
margin from space-heating customers based on normal weather. The weather
normalization adjustment provided $4.2 million of margin in 1998 compared to
$2.9 million in 1997.
The chart below compares margins for the fiscal years 1998 and 1997 by
customer class (in thousands):
Customer Class 1998 1997
-------------- ---- ----
Residential........... $26,184 $24,723
Commercial............ 16,102 15,000
Industrial............ 25,289 26,029
Municipal............. 7,533 7,454
Non-utility........... 6,206 6,056
------- -------
Total................. $81,314 $79,262
======= =======
The residential, commercial and municipal margins increased in fiscal year
1998 as compared to fiscal year 1997. The increase in customers, as well as the
effect of the weather normalization adjustment for these customer classes as
explained above, contributed to the margin growth. Industrial margins decreased
as a result of lower sales volumes to alternative fuel customers due to low oil
prices and the loss of three industrial customers as a result of plant closings.
However, the loss in volumes to these customers was somewhat offset by a 130%
increase in volumes to electric generation customers due to warmer-than-normal
weather during the summer months. Nonutility margin increased due to the
addition of 1,000 new propane customers and weather which was 2% cooler than
1997 as well as higher margins from our marketing subsidiary. These items were
offset by lower appliance sales and other subsidiary income.
Operating Expenses. Our total operating expenses, excluding the cost of
gas sold, increased to $48.9 million in 1998, compared to $48.2 million in 1997.
As a percentage of margin, the 1998 amount was 60.2%, down slightly from 60.8%
in 1997. Operations and maintenance expenses decreased to $28.8 million in
1998, compared to $29.5 million in 1997. The decrease in 1998 was due in part
to lower power costs for liquefaction at our liquified natural gas, or LNG,
plant due to warmer-than-normal weather. This resulted in higher liquefied
natural gas inventory levels at the end of the 1998 winter season.
Additionally, distribution expenses
21
<PAGE>
were lower due primarily to a 3% reduction in employees in 1998 compared to
1997. Three small customer service offices were closed in the fourth quarter of
fiscal year 1998. These savings were somewhat offset due to higher customer
collection and meter reading expenses.
Net Income. For the fiscal year ended September 30, 1998, we earned $17.1
million compared to $17.6 million in fiscal year 1997.
Included in 1997 earnings is a non-recurring after-tax credit of $1.1
million ($1.9 million pre-tax) related to the recovery of past exploration and
development costs. Excluding this nonrecurring credit, the 2.4% increase in
earnings in 1998 compared to 1997 was primarily due to (1) an increase in the
residential and commercial customer base of approximately 3%, which resulted in
increased facilities charges as well as increased sales; (2) higher volumes to
firm service industrial and electric power generation customers; (3) increased
earnings from our propane division; and, (4) lower operations and maintenance
expenses as a result of increased cost control measures and 3% fewer employees.
Liquidity and Capital Resources
Net cash provided by operating activities of $32.2 million for the three
months ended March 31, 2000 was used primarily to expand our plant facilities
and to repay notes payable to CP&L. Construction spending was $5.8 million,
after giving effect to funds received from the expansion fund, for the three-
month period ended March 31, 2000.
Current cash requirements are financed primarily through our $150 million
revolving credit facility with CP&L. As of March 31, 2000, available borrowings
under the CP&L revolving credit facility amounted to $40 million. The revolving
credit facility has a 364-day term, subject to automatic 364-day extensions, and
expires on July 15, 2001. The stated interest rate on the facility is the
London Interbank Offered Rate, or LIBOR, plus 0.10% (6.13% at March 31, 2000).
The average interest rate on the CP&L revolving credit facility was 5.9% for the
three months ended March 31, 2000.
Our ratio of long-term debt to total capitalization was 0% at March 31,
2000 as compared to 30.4% at March 31, 1999. The decrease is the result of the
advance refunding of our long-term debt in August 1999 using proceeds from the
CP&L revolving credit facility. Our ratio of long term debt to total
capitalization was 33.1% at September 30, 1998 and 29.3% at July 14, 1999. We
had no long term debt as of December 31, 1999 and March 31, 2000.
In December 1999, we (through CP&L) announced plans to build a 30-inch
natural gas pipeline in North Carolina that will extend approximately 82 miles
from Iredell County to Richmond County. This pipeline, to be called the
Sandhills Pipeline, will provide gas to a new CP&L power plant that is under
construction in Richmond County. The new Richmond County plant is scheduled to
be completed in 2001. The estimated cost of this project is $100 million and
can accommodate new load growth and future expansions of CP&L's power plants.
Cash requirements for the period from July 15, 1999 to December 31, 1999
were financed primarily through internally generated cash and our $150 million
revolving credit facility with CP&L. Following the July 15, 1999 acquisition,
we began utilizing the CP&L revolving credit facility to finance operations. In
August 1999, we utilized borrowings available under the CP&L
22
<PAGE>
revolving credit facility to advance refund all of our outstanding debt plus
accrued interest. Funds were also borrowed during the period to provide for our
ongoing construction program and to finance normal operations. The CP&L
revolving credit facility accrues interest at LIBOR plus 0.10% (5.82% at
December 31, 1999). Our available borrowings under the CP&L revolving credit
facility at December 31, 1999 amounted to $15.1 million.
For the period from July 15, 1999 to December 31, 1999, net cash used in
operating activities, used in investing activities and provided by financing
activities was $11.6 million, $20.1 million and $28.0 million, respectively.
Net cash used in investing activities was used primarily to expand our plant
facilities. The net cash provided from financing activities primarily results
from $135 million of borrowings from CP&L offset by the repayment of $102
million of outstanding notes payable and long-term debt.
Construction spending was $17.5 million, after giving effect to funds
received ($9.7 million) from the expansion fund for the period from July 15,
1999 to December 31, 1999. The expansion fund was established for us in 1993 by
order of the North Carolina Utilities Commission. It was funded initially by
refunds we received from our pipeline suppliers. The investment and use of
these funds is restricted under a North Carolina Utilities Commission order.
For the period from October 1, 1998 to July 14, 1999, net cash provided by
operating activities, used in investing activities and provided by financing
activities was $25.6 million, $35.9 million and $13.1 million, respectively.
Net cash used in investing activities was used primarily to expand our plant
facilities. Construction spending was $33.2 million, after giving effect to
funds received ($4.9 million) from the expansion fund. The net cash provided
from financing activities primarily results from $27 million short-term
borrowings offset by the repayment of $6 million of long-term debt and the
payment of $10.6 million in cash dividends.
We expect to utilize public debt financing in 2000 to meet our capital
needs. On March 8, 2000 our board of directors approved one or more public debt
offerings in an amount not to exceed $300 million and authorized our management
to borrow funds through loans from financial institutions, commercial paper and
long-term debt. The proceeds of the offerings, expected to occur, from time to
time, over the next two years, will be used to repay the outstanding balance on
the CP&L revolving credit facility and provide working capital to fund our
ongoing construction program as well as day-to-day operations. We believe the
generation of net cash from operating activities, together with financing
available from the CP&L revolving credit facility, outside borrowings, and
public debt financing will be sufficient to provide for daily operations,
including summer injections, as well as our construction program through 2000.
Regulatory Accounting
We are subject to the provisions of Financial Accounting Standards Board
(FASB) Statement No. 71, "Accounting for the Effects of Certain Types of
Regulation." Regulatory assets represent probable future revenues to us
representing certain costs that are expected to be recovered from customers
through the ratemaking process. Regulatory liabilities represent probable future
reductions in revenues associated with amounts that are to be credited to
customers through the ratemaking process.
23
<PAGE>
As noted above, in August 1999 we advance refunded all of our then
outstanding long-term debt with proceeds from the CP&L revolving credit
facility. In connection with the advance refunding, we incurred prepayment
penalties of approximately $4.9 million. These penalties are being treated as a
regulatory asset in accordance with FASB No. 71 and are being amortized over the
remaining terms of the reacquired debt instruments.
In the event that all or a portion of our operations are no longer subject
to the provisions of Statement No. 71, we would be required to write off related
regulatory assets and liabilities. In addition, we would be required to
determine any impairment to the other assets, including plant, and write down
the assets, if impaired, to their fair value. To date, no such write-downs or
write-offs have been made, nor are any expected to be made in the future.
Recent Accounting Pronouncements
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for the reporting and
display of comprehensive income and its components in a full set of general
purpose financial statements. We adopted SFAS No. 130 on October 1, 1998. SFAS
No. 131 introduces a new model for segment reporting based on the way we
organize segments for making operating decisions and assessing performance. We
adopted SFAS No. 131 in fiscal year 1998.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits." SFAS No. 132 is an amendment
of SFAS No. 87, "Employers' Accounting for Pensions," SFAS No. 88, "Employers'
Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and
for Termination Benefits," and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." SFAS No. 132 requires additional
disclosures of the changes in the benefit obligation and plan assets during the
period, including economic events during the period. Economic events include
amendments, combinations, divestitures, curtailments and settlements. This
statement is effective for fiscal years beginning after December 15, 1997. We
adopted this standard October 1, 1998.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 standardizes the accounting
for derivative instruments, including certain derivative instruments embedded in
other contracts, by requiring that an entity recognize those items as assets or
liabilities in the consolidated statement of financial position and measure them
at fair value. This statement is effective for fiscal years beginning after
June 15, 2000, as amended by SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133" issued in June 1999. We expect to determine any effects of
SFAS No. 133 during the third quarter of 2000.
Recent Expansion Projects
In September 1999, we completed a $23 million, 72 mile gas pipeline from
Mount Olive to Jacksonville, bringing natural gas service to Duplin and Onslow
counties for the first time. The pipeline serves Camp Lejuene and will provide
service to over 50 commercial customers in Onslow County. In the fourth quarter
of 1999, we completed a 44 mile transmission pressure
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pipeline that extended natural gas service into Bertie and Martin counties. We
utilized funds from the expansion fund for both of these projects.
We are currently evaluating opportunities to utilize state bond funding to
expand natural gas services in both Montgomery and Columbus Counties, North
Carolina.
ITEM 3. PROPERTIES.
We own and operate a liquefied natural gas storage plant that can provide a
maximum daily capacity of 120,000 dekatherms (dt) per day to our peak-day
delivery capability. The average daily movement is 97,200 dt.
We own approximately 1,128 miles of transmission pipelines of two to 30
inches in diameter that connect our distribution systems with the Texas-to-New
York transmission system of Transco and the southern end of Columbia's
transmission system. Transco delivers gas to us at various points conveniently
located with respect to our distribution area. Columbia delivers gas to one
delivery point near the North Carolina-Virginia border. We distribute gas
through 2,865 miles of distribution mains. These transmission pipelines and
distribution mains are located primarily on rights-of-way held under easement,
license or permit on lands owned by third-parties.
We believe that all of our facilities are suitable, adequate for our
business, well-maintained and in good operating condition.
ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
North Carolina Natural Gas Corporation
All of our outstanding common stock is owned by our parent, CP&L Energy.
No other class of our securities is authorized or outstanding.
CP&L Energy
The following table sets forth certain information regarding the beneficial
ownership of CP&L Energy's common stock shares and common stock units as of
March 31, 2000 after giving effect to the conversion of CP&L to a holding
company structure, by:
. each of CP&L Energy's directors and named executive officers,
. all of CP&L Energy's directors and named executive officers as a group,
. each person (or group of affiliated persons) known by us to beneficially
own more than 5% of our outstanding common stock, and
. each of our directors and named executive officers who is not also a
named executive officer or director of CP&L Energy.
A unit of common stock does not represent an equity interest in CP&L Energy
and possesses no voting rights, but is equal in value at all times to a share of
common stock.
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As of March 31, 2000, other than Capital Research and Management Company,
which owned 5.9% of CP&L Energy's shares of common stock, none of the
individuals or groups in the above categories owned one percent (1%) or more of
any class of CP&L Energy voting securities. Unless otherwise indicated, each
person listed has sole voting power and investment power with respect to the
shares shown as beneficially owned by that person.
<TABLE>
<CAPTION>
Number of Shares of Common Number of Common
Stock Stock Units Beneficially
Name of Beneficial Owner Beneficially Owned Owned(1)(2)(3)(4)
----------------------- ------------------ -----------------
<S> <C> <C> <C> <C>
CP&L Energy Directors and
Executive Officers:
Leslie M. Baker, Jr. 1,000 7,250 (1)
Edwin B. Borden 4,838 19,858 (1)
David L. Burner 0 1,458 (2)
William Cavanaugh, III 118,712 (5) 137,846 (3,4,6,7)
Charles W. Coker 3,448 (8) 24,102 (1)
Richard L. Daugherty 909 13,018 (1)
Robert L. Jones 2,000 16,611 (1)
Tom D. Kilgore 16,612 (9) 14,444 (4,6)
Estell C. Lee 4,484 (10) 19,807 (1)
William O. McCoy 1,000 5,613 (1)
Robert B. McGehee 27,428 (11) 15,403 (4,6,7)
E. Marie McKee 600 1,573 (2)
John H. Mullin, III 1,000 2,062 (2)
William S. Orser 46,988 (12) 31,646 (3,4,6)
Sherwood H. Smith, Jr. 31,981 (13) 26,407 (2,3)
Calvin B. Wells 39,022 (14) 4,852 (4,6)
J. Tylee Wilson 5,000 5,684 (2)
Don K. Davis (15) 27,000 4,145 (4)
Peter M. Scott, III (15) 32,700 5,102 (4)
CP&L Energy directors and officers as a 391,750 ___
group (22 persons)(16)
5% Holders:
Capital Research and Management Company 9,450,000 (17) 0
NCNG Directors and Executive Officers:
Terrence D. Davis 12,761 1,076 (4)
Marsha M. Lederer 12 0
Mary Lee Edmonds 3,338 0
William D. Johnson 14,510 (18) 9,730 (4,6,7)
</TABLE>
__________________
(1) Consists of units representing common stock of CP&L under their Directors'
Deferred Compensation Plan and their Non-Employee Director Stock Unit Plan.
(2) Consists of units representing common stock of CP&L under their Directors'
Deferred Compensation Plan.
(3) Consists of performance units under CP&L's Long-Term Compensation Program.
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(4) Consists of performance shares awarded under CP&L's Performance Share Sub-
Plan of its 1997 Equity Incentive Plan.
(5) Includes 100,000 shares of restricted stock and 7,506 shares with shared
voting and investment power owned by members of Mr. Cavanaugh's immediate
family as to which beneficial ownership has not been disclaimed.
(6) Consists of replacement units to replace the value of CP&L contributions to
its Stock Purchase-Savings Plan that would have been made but for deferral
of salary under the Management's Deferred Compensation Plan (formerly the
Deferred Compensation Plan for Key Management Employees) and contribution
limitations under Section 415 of the Internal Revenue Code of 1986, as
amended.
(7) Consists of performance units recorded to reflect awards deferred under
CP&L's Management Incentive Compensation Plan.
(8) Includes 3,248 with shared voting and investment power owned by members of
Mr. Coker's immediate family to which beneficial ownership has not been
disclaimed.
(9) Includes 14,600 shares of restricted stock.
(10) Includes 160 shares with shared voting and investment power owned by
members of Ms. Lee's immediate family as to which beneficial ownership has
not been disclaimed.
(11) Includes 24,800 shares of restricted stock.
(12) Includes 40,000 shares of restricted stock.
(13) Does not include 900 shares owned by members of Mr. Smith's immediate
family as to which beneficial ownership has been disclaimed.
(14) Includes 10,400 shares of restricted stock. Mr. Wells retired effective
June 30, 2000.
(15) Mr. Davis became a director of NCNG on July 2, 2000. Mr. Scott became a
director of CP&L Energy on June 2, 2000. Mr. Davis owns 27,000 shares of
restricted stock. Mr. Scott owns 32,700 shares of restricted stock.
(16) William D. Johnson, our Secretary, is included in this group. Includes
shares owned by Mr. Wells as of March 31, 2000. Excludes shares owned by
Messrs. Don K. Davis and Scott.
(17) Address is 333 South Hope Street, Los Angeles, California, 90071. Consists
of shares of common stock held by Capital Research and Management Company
as investment advisor and manager of The American Funds Group of mutual
funds. Capital Research and Management Company has sole dispositive power
with respect to 9,450,000 shares.
(18) Includes 12,200 shares of restricted stock.
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<PAGE>
ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS.
Our amended and restated bylaws provide that the number of directors shall
not be less than one nor more than ten and may be fixed or changed from time to
time by our shareholders or our board of directors. All members of our board of
directors are elected annually by our parent, CP&L Energy.
The following table sets forth certain information with respect to our
directors, executive officers and other key employees:
NAME AGE POSITION(S)
---- --- -----------
Don K. Davis 55 President, Chief Executive Officer and
Director
Terrence D. Davis 54 Senior Vice President of Operations
George M. Baldwin 39 Vice President, Marketing
Marsha M. Lederer 30 Controller
Mary Lee Edmonds 41 Business Operations Manager
William D. Johnson 46 Director and Secretary
Mark F. Mulhern 40 Treasurer
William Cavanaugh, III 61 Director
Robert B. McGehee 57 Director
Tom D. Kilgore 52 Director
Peter M. Scott, III 50 Director
Don K. Davis became our Director on June 2, 2000 and our President and
Chief Executive Officer July 1, 2000. Mr. Davis is also the Executive Vice
President of CP&L's newly created Gas & Energy Services business unit and the
Chief Executive Officer of Strategic Resource Solutions. Prior to joining us,
Mr. Davis had served as the Chairman, President and Chief Executive Officer of
Yankee Atomic Power Company and Connecticut Yankee Atomic Power Company since
1997. From 1992 to 1997, Mr. Davis was a principal of PRISM Consulting Inc.
Terrence D. Davis has been our Senior Vice President of Operations since
July 1999. From January 1993 to July 1999, Mr. Davis served in varying
capacities as Senior Vice President and Vice President of Operations, Marketing,
and Industrial Sales. From 1980 to 1990, Mr. Davis was the Vice President of
Operations and Engineering for Chesapeake Utilities in Dover, Delaware. Mr.
Davis started his career and spent eleven years with Wisconsin Electric and
Wisconsin Natural Gas in Milwaukee, Wisconsin. Mr. Davis is the President of
the Southeastern Gas Association.
George M. Baldwin has been our Vice President of Marketing since January
1998. From January 1996 to January 1998, Mr. Baldwin was our Assistant Vice
President of Industrial Sales. Prior to that, he was the Director of Industrial
Sales. Mr. Baldwin is a Chartered Industrial Gas Consultant and a Certified Co-
Generation Professional.
Marsha M. Lederer has been our Controller since April 2000. Prior to that,
Ms. Lederer was a Supervisor in CP&L's accounting department. Prior to joining
CP&L, she held various
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positions with the accounting firms PricewaterhouseCoopers LLC and KPMG Peat
Marwick, LLC.
Mary Lee Edmonds has been our Business Operations Manager, the functional
equivalent of our chief financial officer, since July 1999. Ms. Edmonds was the
Manager of Financial Projects in CP&L's strategic planning department from
March 1999 to June 1999. Previous to that she held various positions within
both CP&L's accounting and treasury departments.
William D. Johnson is one of our Directors and is our Secretary. Mr.
Johnson is the Executive Vice President and Corporate Secretary of CP&L Energy
and has also been the Senior Vice President and Corporate Secretary, Legal and
Risk Management since March 1999. He was Vice President-Legal Department and
Corporate Secretary from 1997 to 1999, Vice President, Senior Counsel and
Manager-Legal Department from 1995 to 1997, Interim Manager-Legal Department
from 1994 to 1995, and Associate General Counsel and Practice Group Leader from
1992 to 1994 of CP&L. Before joining the company, Mr. Johnson was a practicing
attorney and partner with Hunton & Williams, a law firm in Raleigh, North
Carolina.
Mark F. Mulhern is our Treasurer. He has served as the Vice President and
Treasurer of CP&L since February 1997 and the Vice President and Controller from
March 1996 to February 1997. He has also served as the Vice President of Finance
and Treasurer of HYDRA-CO Enterprises, Inc., a subsidiary of Niagara Mohawk
Power Corporation from 1994 to 1996. From 1991 to 1994, Mr. Mulhern held various
finance and accounting positions at HYDRA-CO Enterprises, Inc. Prior to 1991,
Mr. Mulhern held various positions with the accounting firm of Price Waterhouse
& Co.
William Cavanaugh, III is one of our Directors and is the Chairman,
President and Chief Executive Officer of CP&L Energy and has served on similar
capacities with CP&L since May 1999. He was the President and Chief Executive
Officer of CP&L from October 1996 to May 1999, and President and Chief Operating
Officer from September 1992 to October 1996. Before joining CP&L, Mr. Cavanaugh
held various senior management and executive positions during a 23-year career
with Entergy Corporation, an electric utility holding company with operations in
Arkansas, Louisiana and Mississippi. Mr. Cavanaugh has been a member of the
Board of Directors of CP&L since 1993.
Robert B. McGehee is one of our Directors and has been the current
Executive Vice President of CP&L Energy and has served in similar capacities
with CP&L and as the General Counsel, Chief Administrative Officer and
Administrative Services, Corporate Relations and Financial Services Officer of
CP&L. He was the Executive Vice President, General Counsel and Chief
Administrative Officer, Administrative Services and Corporate Relations Officer
from March 1999 to June 2000. He was the Senior Vice President and General
Counsel, Public and Corporate Relations from May 1997 to March 1999. From 1974
to May 1997, Mr. McGehee was a practicing attorney with Wise Carter Child &
Caraway, a law firm in Jackson, Mississippi. He primarily handled corporate,
contract, nuclear regulatory and employment matters. From 1987 to 1997 he
managed the firm, serving as chairman of its Board from 1992 to May 1997.
Tom D. Kilgore is one of our Directors and is the Senior Vice President,
Power Operations from August 1998 to present of CP&L. He was the President and
Chief Executive Officer, Oglethorpe Power Corporation, Georgia Transmission
Corporation and Georgia Operations Corporation, from July 1991 to August 1998.
These three companies provide power
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<PAGE>
generation, transmission and system operations services, respectively, to 39 of
Georgia's 42 customer-owned Electric Membership Corporations. From 1984 to July
1991, Mr. Kilgore held numerous management positions at Oglethorpe.
Peter M. Scott, III became one of our Directors on June 2, 2000. Mr. Scott
joined CP&L in May 2000 as its Executive Vice President and Chief Financial
Officer. Mr. Scott has been President of Scott, Madden & Associates, Inc. since
1983, a 75-person management consulting firm founded by Mr. Scott. Prior to
1983, he was a principal and partner in Theodore Barry & Associates, a Los
Angeles-based consulting firm. As a consultant, Scott has specialized in the
energy and telecommunications industry.
ITEM 6. EXECUTIVE COMPENSATION.
The following table sets forth all compensation paid or accrued to our
chief executive officer and our most highly compensated executive officers whose
total annual salary and bonuses exceeded $100,000 for the fiscal years 1999,
1998 and 1997.
Summary Compensation Table
<TABLE>
<CAPTION>
Other Annual All Other
Name and Principal Position Year (1) Salary ($) Bonus ($) Compensation Compensation ($)
--------------------------- -------- ---------- --------- ------------ ----------------
<S> <C> <C> <C> <C> <C>
Calvin B. Wells, President and 1999 267,300 705,802 0 33,278
Chief Executive Officer, 1998 257,000 69,559 0 7,929
(retired June 30, 2000) 1997 257,000 144,693 0 7,891
Don K. Davis, President and
Chief Executive Officer, __ __ __ __ __
(effective July 1, 2000) (2)
Terrence D. Davis, 1999 156,000 179,773 0 2,012
Senior Vice President 1998 150,000 25,995 70,788 3,933
1997 124,000 42,081 62,880 3,202
</TABLE>
_____________
(1) Information for 1998 and 1997 reflects our compensation as an independent
public company. Information for 1999 reflects our compensation prior and
subsequent to our merger with CP&L on July 15, 1999.
(2) Mr. Don K. Davis became our President and CEO on July 1, 2000. Pursuant to
an employment agreement, as described in further detail below, Mr. Davis will be
paid an annual base salary of $285,000 and is eligible for additional
compensation through bonuses and other perquisites.
Director Compensation
Each of our directors is an employee of either CP&L or CP&L Energy and is
not separately compensated by us, CP&L or CP&L Energy for his services on our
board of directors or any committee of our board of directors.
Board Committees
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<PAGE>
We have a standing executive committee comprised of Messrs. Cavanaugh and
McGehee. Mr. Don K. Davis is expected to join the executive committee in place
of Mr. Wells, who retired on June 30, 2000. The executive committee was
established to facilitate the conduct of our business. The authority and
responsibility of the executive committee, as provided in our charter and by-
laws, permit the executive committee to exercise all the powers and authority of
the board of directors in its management of our business and affairs.
Employment Agreements
On July 15, 1999, we entered into employment agreements with Messrs.
Terrence D Davis and Baldwin. On May 15, 2000, CP&L entered into an employment
agreement with Mr. Don K. Davis. These agreements provide for base salaries,
bonuses, perquisites and participation in various executive compensation plans
offered to CP&L executives. Under the employment agreements, Messrs. Don K.
Davis, Terrence D. Davis and Baldwin are paid base salaries of $285,000,
$156,000 and $103,000, respectively. Base salary increases and bonus amounts
are determined by the CP&L Energy Board of Directors' Committee on Organization
and Compensation, or the CP&L Compensation Committee.
The employment agreements for Mr. Terrence Davis and Mr. Baldwin provide
that upon termination or constructive termination of employment by us for any
reason other than cause, each executive will retain benefits under our
established benefit programs, and will be entitled to the continuation of their
then current base salary and health benefits for two years and 11 months. The
benefit is reduced upon re-employment. Constructive termination is defined in
these agreements as a reassignment to a position that has significantly and
materially reduced responsibilities or a salary reduction. These employment
agreements also provide that if employment is voluntarily terminated for any
reason other than death or disability, each executive will retain all vested
benefits, but will not be entitled to any form of salary continuance or any form
of severance benefit.
The employment agreement with Mr. Don Davis provides that upon termination
or constructive termination of employment by us for any reason other than cause,
he will retain benefits under our established benefit programs, and will be
entitled to the continuation of his then current base salary for the remainder
of the term of his agreement and health benefits for up to eighteen months.
Salary continuation, which could be a minimum of two years or a maximum of three
years, is reduced upon re-employment. Constructive termination for this
agreement is defined as a change in the form of ownership of CP&L and Mr. Don
Davis is asked to leave.
Benefit Plans
Prior to our merger with CP&L, we had various benefit plans, including an
executive pension retirement plan, an employees' pension plan, a 401(k) plan,
and customary health and welfare plans. Under their employment agreements,
Messrs. Davis and Baldwin continued to participate in these benefit plans
through December 31, 1999. Upon the completion of our merger with CP&L, the
following benefit plans were immediately terminated: the long-term incentive
plan, the annual incentive plan, the employee stock purchase plan and the key
employee stock option plan.
We do not have separate benefit plans for our executive officers and
directors. All of our executive officers and directors participate in the
benefit plans of CP&L. The following discussion describes the benefit plans of
CP&L in which our executive officers and directors participate. By resolution
of the board of directors, the benefit plans described herein will be
transferred to CP&L Energy on August 1, 2000.
Management Incentive Compensation Plan
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CP&L sponsors the Management Incentive Compensation Plan for senior
executives, department heads and selected key employees. In order for awards to
be made under the plan, two conditions must be satisfied. First, a contribution
must be earned by one or more groups of employees under the corporate incentive
feature of CP&L's Stock Purchase-Savings Plan, a tax qualified 401(k) plan.
Incentive matching contributions are earned by participating employees if at
least five out of ten annual corporate and business unit goals are met. Second,
CP&L's return on common equity and earnings before interest, taxes, depreciation
and amortization, or EBITDA, growth for the most recent three-year period must
be above the median of those companies in a comparison group that is comprised
of the 29 electric utility companies comprising Standard & Poor's Electric
Index.
If participants at or above the department head level are eligible for
awards, then CP&L's Compensation Committee in its discretion determines whether
awards are to be made and, if so, in what amounts. If participants below the
department head level are eligible for awards, then CP&L's Chief Executive
Officer has sole and complete authority to approve such awards.
Awards consist of both a corporate component and a noncorporate component.
Award opportunities, expressed as a percentage of annual base salary earnings,
are applicable to both components of an award. The corporate component of an
award is based upon the overall performance of CP&L. The noncorporate component
of an award is based upon the level of attainment of business unit/group,
departmental and individual performance measures. Those measures are evaluated
in terms of three levels of performance (1) outstanding, (2) target and (3)
threshold, each of which is related to a particular payout percentage. If
earned, awards are either paid in cash in the succeeding year or deferred to a
later date, as elected by each individual participant. Deferred awards are
recorded in the form of performance units. Each performance unit is generally
equivalent to a share of the CP&L's common stock.
1997 Equity Incentive Plan
Under CP&L's 1997 Equity Incentive Plan, CP&L's Compensation Committee is
permitted to make various types of awards to directors, officers and other key
employees, affiliates and subsidiaries of CP&L, including us. Selection of
participants is within the sole discretion of the CP&L Compensation Committee.
Thus, the number of persons eligible to participate in the 1997 plan and the
number of grantees may vary from year to year. The 1997 plan was effective as
of January 1, 1997, and will expire on January 1, 2007, provided, however, that
all awards made prior to and outstanding on that date shall remain valid in
accordance with their terms and conditions.
The 1997 plan is a broad umbrella plan that allows CP&L to enter into
award agreements with participants and adopt various individual sub-plans that
will permit the grant of the following types of awards:
. nonqualified stock options,
. incentive stock options,
. stock appreciation rights,
. restricted stock,
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<PAGE>
. performance units,
. performance shares, and
. other stock unit awards or stock-based forms of awards.
The 1997 plan sets forth certain minimum requirements for each type of
award, with detailed provisions regarding awards to be set out either in award
agreements or in the sub-plans adopted under the 1997 plan. Subject to
adjustment as provided in the 1997 plan, the maximum aggregate number of shares
that may be issued under the 1997 plan cannot exceed 5,000,000 shares of CP&L
common stock, which may be in any combination of options, restricted stock,
performance shares, or any other right or option.
Under the terms of the 1997 plan, CP&L's Compensation Committee may grant
awards in a manner that qualifies them for the performance-based exception to
Section 162(m) of the Internal Revenue Code of 1986, as amended, or it may grant
awards that do not qualify for the exemption.
Performance Share Sub-Plan of the 1997 Plan
Under the provisions of the 1997 plan, CP&L's Compensation Committee
adopted the Performance Share Sub-Plan, which governs the issuance of
performance share awards to officers and key employees, as selected by CP&L's
Compensation Committee in its sole discretion. A "performance share" is a unit
granted to a participant, the value of which is equal to the value of a share of
CP&L common stock. Grants of performance share awards may range from 20% to 75%
of a participant's base salary, depending upon the participant's position and
job value. For purposes of the Sub-Plan, base salary is not reduced to reflect
salary deferrals and does not include incentive compensation. The number of
performance shares awarded are recorded in a separate account for each
participant, and are adjusted to reflect dividends, stock splits or other
adjustments in CP&L's common stock.
The performance period for an award under the Sub-Plan is the three
consecutive year period beginning in the year in which the award is granted.
There are two equally weighted performance measures under the Sub-Plan. One
performance measure is total shareholder return, which is defined in the Sub-
Plan as the appreciation or depreciation in the value of stock (which is equal
to the closing value of the stock on the last trading day of the relevant period
minus the closing value of the stock on the last trading day of the preceding
year) plus dividends declared during the relevant period, divided by the closing
value of the stock on the last trading day of the preceding year. The other
performance measure is EBITDA growth.
Awards under the Sub-Plan vest on January 1 following the end of a three-
year performance period. The aggregate value of the award is determined using
multipliers that are based on the difference between CP&L's total shareholder
return and EBITDA growth and the peer group total shareholder return and EBITDA
growth, respectively. The aggregate value of vested performance shares is equal
to the number of vested performance shares in the participant's account
multiplied by the closing price of CP&L's common stock, as published in The Wall
Street Journal on the last trading day before payment of the award. Awards are
paid in
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<PAGE>
cash after expiration of the performance period. Payment can be made in either
(i) lump sum on or about April 1 of the year immediately following the
performance period or (ii) in accordance with an election to defer in 25%
increments, made during the first year of the performance period. In the event
of death, disability, normal retirement or a change-in-control of CP&L, any
award granted under the Sub-Plan immediately becomes vested.
Restricted Stock Awards
Section 9 of the 1997 plan provides for the granting of shares of
restricted stock by CP&L's Compensation Committee to key employees in such
amounts and for such duration and/or consideration as it shall determine. The
1997 plan defines "key employee" as an officer or other employee, who, in the
opinion of CP&L's Compensation Committee, can contribute significantly to the
growth and profitability of, or perform services of major importance. Each
restricted stock grant must be evidenced by an agreement specifying the period
of restriction, the conditions that must be satisfied prior to removal of the
restriction, the number of shares granted, and such other provisions as CP&L's
Compensation Committee shall determine. During the period of restriction,
recipients of shares of restricted stock granted under the 1997 plan may
exercise full voting rights with respect to those shares, and shall be entitled
to receive all dividends and other distributions paid with respect to those
shares.
Restricted stock covered by each award made under the 1997 plan will be
provided to and become freely transferable by the recipient after the last day
of the period of restriction and/or upon the satisfaction of other conditions as
determined by the CP&L Compensation Committee. If the grant of restricted stock
is performance based, the total period of restriction for any or all shares or
units of restricted stock granted shall be no less than one (1) year. Any other
shares of restricted stock issued pursuant to the 1997 plan must provide that
the minimum period of restrictions shall be three (3) years, which period of
restriction may permit the removal of restrictions on no more than one-third
(1/3) of the shares of restricted stock at the end of the first year following
the grant date, and the removal of the restrictions on an additional one-third
(1/3) of the shares at the end of each subsequent year. The 1997 plan provides
that in no event shall any restrictions be removed from shares of restricted
stock during the first year following the grant date, except in the event of a
change in control.
Management's Deferred Compensation Plan
Effective January 1, 2000, CP&L established the Management Deferred
Compensation Plan, an unfunded, deferred compensation arrangement established
for the benefit of a select group of management and highly compensated employees
of CP&L and its subsidiaries. Under the Management Deferred Compensation Plan,
an eligible employee may elect to defer a portion of his or her salary until the
April 1 following the date that is five or more years from the last day of the
plan year for which the deferral is made, the April 1 following his or her date
of retirement, or the April 1 following the first anniversary of his or her date
of retirement. Deferrals will be made to deferral accounts administered
pursuant to the Management Deferred Compensation Plan in the form of deemed
investments in certain deemed investment funds individually chosen by each
participating employee from a list of investment options provided pursuant to
the Management Deferred Compensation Plan. Additionally, qualifying
participants will receive matching allocations from CP&L generally reflecting
foregone allocations to participants' 401(k) accounts due to such salary
deferrals, and/or foregone CP&L allocations to
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<PAGE>
the participants' 401(k) accounts due to certain Internal Revenue Code limits,
which will be allocated to a CP&L account that will be deemed initially to be
invested in hypothetical shares of CP&L's common stock. When a participant's
CP&L account has matured, pursuant to the terms of the Management Deferred
Compensation Plan, the participant may reallocate any part of such account among
the deemed investment funds chosen by the participant.
Other Benefits
CP&L has implemented an executive split dollar life insurance program which
consists of two separate plans. The first plan provides life insurance coverage
approximately equal to three times salary for senior executives. The second
plan provides additional life insurance coverage approximately equal to five
times salary for those officers of CP&L who are also members of the board of
directors.
CP&L also provides broad-based employee benefit plans in which senior
executives participate. Under the Stock Purchase-Savings Plan, a salary
reduction plan under Section 401(k) of the Internal Revenue Code of 1986, as
amended, the Code, full-time, highly compensated employees may invest up to 12%
of earnings up to a maximum of $10,500 in 2000 on a before-tax basis in CP&L's
common stock and other investment options. CP&L makes a matching contribution
of 50% of such investment, up to 3% of earnings, which is invested in CP&L
common stock. Under an incentive feature, CP&L's contribution may be increased
by up to an additional 50% if certain corporate and business unit financial,
operating, safety, customer satisfaction, and other performance goals are met.
CP&L also sponsors the Supplemental Retirement Plan, a defined benefit plan
which covers full-time employees who have been employed by CP&L for at least one
year. The right to receive pension benefits under this plan is vested after
five years. The Supplemental Retirement Plan, as applicable to employees joining
the plan after January 1, 1999, including our personnel, utilizes a cash balance
formula to determine pension benefits. Prior to the merger, benefits of
participants in our comparable retirement plan were calculated based upon a
"five years average compensation" formula which was frozen on December 31, 1999.
After December 31, 1999, the benefits of our eligible personnel were calculated
based upon the cash balance formula.
The Restoration Retirement Plan is an unfunded retirement plan for a select
group of management or highly compensated employees. The plan restores the full
benefit that would be provided under the Supplemental Retirement Plan but for
certain Code limits imposed on the benefit levels of highly compensated
employees. Generally, the benefit for participants is a monthly benefit payment
equal to the difference between (1) a participant's accrued benefit under the
Supplemental Retirement Plan without regard to the Internal Revenue Service
compensation and benefit limits, and (2) a participant's accrued benefit as
calculated under the Supplemental Retirement Plan. Effective January 1, 2000,
this Plan also applies to any employee who defers more than 10% of his salary
under the new Management Deferred Compensation Plan. The eligibility and
vesting requirement for this Plan are the same as those for the Supplemental
Retirement Plan. Participants under the Supplemental Executive Retirement Plan
forego participation in and rights under this plan.
The Supplemental Executive Retirement Plan provides a retirement benefit
for eligible senior executives equal to 4% of the average of their highest three
years of base salary earnings
35
<PAGE>
and annual bonus for each year of credited service with CP&L up to a maximum of
62%. Benefits under this plan are fully offset by Social Security benefits and
by benefits paid under CP&L's Supplemental Retirement Plan.
CP&L's executives, which include Messrs. Don K Davis and Terrence
Davis also receive certain perquisites and other personal benefits. In addition,
executives are eligible to received gross-up payments for federal and state
income tax obligations related to such perquisites and benefits.
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
We pay service fees to CP&L for various services provided to us. During
the post-merger period ended December 31, 1999, we paid fees in the amount of
$1.4 million.
We also have a $150.0 million revolving credit facility with CP&L, with
$135.0 million outstanding at December 31, 1999. For the post-merger period
ended December 31, 1999, we recognized interest expense of $3.0 million related
to this revolving credit facility.
ITEM 8. LEGAL PROCEEDINGS.
Other than the legal and environmental proceedings discussed in Item 1 of
this registration statement, there are no legal proceedings that are expected to
have a material adverse impact on our results of operations, financial
condition, or cash flows.
ITEM 9. MARKET PRICE OF AND DIVIDENDS ON OUR COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
There is no market for our common stock. All of our outstanding common
stock is owned by our parent, CP&L Energy.
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES.
During the last three years, we have not sold any securities that were
not registered under the Securities Act.
ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED.
Under our amended and restated certificate of incorporation, we are
authorized to issue 100 shares of common stock with a par value of $0.10 per
share. Each share of common stock is entitled to one vote. All of our common
stock is owned by our parent, CP&L Energy.
ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Our amended and restated certificate of incorporation provides that our
directors shall not be liable to us or our stockholders for monetary damages for
breach of fiduciary duty as a director, except to the extent that exemption from
liability or limitation is not permitted under the
36
<PAGE>
Delaware General Corporation Law, as may be amended. Our certificate further
provides that any amendment, modification or repeal of the foregoing provision
shall not adversely affect any right or protection of a director for any act or
omission occurring prior to the time of the amendment, modification or repeal.
As permitted by the Delaware General Corporation Law, our certificate of
incorporation and bylaws eliminate personal liability of our directors to us or
our stockholders for monetary damages for breach of fiduciary duty except for:
. any breach of the director's duty of loyalty to us or our shareholders,
. acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of law,
. any transaction from which the director derived an improper personal
benefit, or
. under Section 174 of the Delaware General Corporation Law, relating to
unlawful dividends or distributions or stock repurchases or redemptions.
As a result of these provisions, we and our stockholders may be unable to obtain
monetary damages from a director for breach of the duty of care.
Our amended and restated bylaws provide for indemnification of our
directors and officers to the extent permitted under the Delaware General
Corporation Law. As permitted by the Delaware General Corporation Law, our
bylaws provide for indemnification of our directors and officers against
expenses, including attorneys' fees, judgments, money decrees, fines and amounts
paid in settlement actually and reasonably incurred by them in connection with
such action, suit or proceeding if they acted in good faith and in a manner they
reasonably believed to be in or not opposed to our best interests, and, with
respect to any criminal action or proceeding, had no reasonable cause to believe
their conduct was unlawful.
We have insurance covering expenditures we might incur in connection with
the lawful indemnification of our directors and officers for their liabilities
and expenses. Our officers and directors also have insurance that insures them
against certain liabilities and expenses.
Insofar as indemnification for liabilities under the Securities Act may be
provided to our directors, officers or controlling persons under our certificate
of incorporation, bylaws and the Delaware General Corporation Law, we are aware
that it is the opinion of the SEC that such indemnification is against public
policy as expressed in such Securities Act and is therefore unenforceable.
37
<PAGE>
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements attached to this registration statement on Form
10 as Annex F are incorporated by reference herein.
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS.
a) The financial statements filed as a part of this registration
statement are listed in Annex F which is incorporated by reference herein.
b) The following exhibits are filed with this registration statement:
Exhibit
Number Description
------- -----------
2(1) Agreement and Plan of Merger By and Among Carolina Power &
Light Company, North Carolina Natural Gas Corporation and
Carolina Acquisition Corporation, dated as of November 10,
1998. (1)
2(2) Agreement and Plan of Merger By and Among Carolina Power &
Light Company, North Carolina Natural Gas Corporation and
Carolina Acquisition Corporation, dated as of November 10,
1998, as Amended and Restated as of April 22, 1999. (2)
2(3) Agreement and Plan of Share Exchange, dated as of August 22,
1999 between Carolina Power & Light Company and CP&L
Holdings, Inc. (3)
2(4) Agreement and Plan of Exchange, dated as of August 22, 1999,
by and among Carolina Power & Light Company, Florida
Progress Corporation and CP&L Holdings, Inc. (4)
2(5) Amended and Restated Agreement and Plan of Exchange, by and
among Carolina Power & Light Company, Florida Progress
Corporation and CP&L Energy, Inc., dated as of August 22,
1999, amended and restated as of March 3, 2000 (5)
3(1) Amended and Restated Certificate of Incorporation of North
Carolina Natural Gas Corporation
3(2) Amended and Restated Bylaws of North Carolina Natural Gas
Corporation
10a(1) Service Agreement dated August 31, 1967, with
Transcontinental Gas Pipe Line Corporation covering storage
service under Rate Schedule GSS. (6)
10a(2) Service Agreement dated August 2, 1974, with
Transcontinental Gas Pipe Line Corporation covering storage
service under Rate Schedule LG-A. (6)
10a(3) Precedent Agreement to provide Contract Demand Service of
25,000 Dt/day dated December 19, 1988, with Columbia Gas
Transmission Corporation. (7)
38
<PAGE>
Exhibit
Number Description
------ -----------
10a(4) Contract Demand Service Agreement dated November 1, 1989,
with Columbia Gas Transmission Corporation. (8)
10a(5) Firm Seasonal Transportation Agreement dated July 2, 1990,
with Transcontinental Gas Pipe Line Corporation. (8)
10a(6) Service Agreement dated August 1, 1991, with
Transcontinental Gas Pipeline Corporation covering storage
service under Rate Schedule WSS. (9)
10a(7) Firm Sales Agreement with Transcontinental Gas Pipe Line
Corporation dated August 1, 1991 covering 54,043 Mcf per
day. (9)
10a(8) Firm Transportation Agreement with Transcontinental Gas Pipe
Line Corporation dated February 1, 1991 for 141,000 Mcf per
day. (10)
10a(9) Natural Gas Service Agreement dated January 9, 1992 with the
City of Wilson. (10)
10a(10) Natural Gas Service Agreement dated January 13, 1992 with
the City of Rocky Mount. (10)
10a(11) Service Area Territory Agreement dated January 13, 1992 with
the City of Rocky Mount. (10)
10a(12) Natural Gas Service Agreement dated March 12, 1992 with the
City of Greenville. (10)
10a(13) Natural Gas Service Agreement dated March 27, 1992 with the
City of Monroe. (10)
10a(14) Amendment to Natural Gas Service Agreement dated March 27,
1992 with the City of Greenville Utilities Commission. (11)
10a(15) Amendment to Natural Gas Service Agreement dated January 13,
1992 with the City of Rocky Mount. (11)
10a(16) Amendment to Natural Gas Service Agreement dated November 1,
1992 with the City of Monroe (12)
10a(17) Fourth Amendment to Natural Gas Service Agreement dated
December 1, 1995 with the Greenville Utilities Commission,
Greenville, NC. (13)
10a(18) Second Amendment to Natural Gas Service Agreement dated
November 1, 1995 with the City of Rocky Mount, NC. (13)
10a(19) Third Amendment to Natural Gas Service Agreement dated
December 1, 1995 with the City of Wilson, NC. (13)
10a(20) Addendum No. Three dated August 29, 1996 covering Standby
On-Peak Supply Service with the City of Rocky Mount,
NC. (13)
10a(21) Addendum No. Four dated August 28, 1996 covering Standby On-
Peak Supply Service with the City of Wilson, NC. (13)
10a(22) First Amendment dated March 10, 1997 to Service Area
Territory Agreement with the City of Rocky Mount, NC. (14)
10a(23) Third Amendment to Natural Gas Service Agreement dated March
10, 1997 with the City of Rocky Mount, NC. (14)
10a(24) Third Amendment to Natural Gas Service Agreement dated
November 1, 1996 with the City of Monroe, NC. (14)
10a(25) Fourth Amendment to Natural Gas Service Agreement dated
November 1, 1997 with the City of Monroe. (15)
10a(26) Fifth Amendment to Natural Gas Service Agreement dated June
1, 1998
39
<PAGE>
Exhibit
Number Description
------ -----------
with the City of Monroe. (16)
10b(1) Supplemental Executive Retirement Plan, effective January 1,
1984. (17)
10b(2) Retirement Plan for Outside Directors. (17)
10b(3) Directors Deferred Compensation Plan, effective January 1,
1982, as amended. (17)
10b(4) Resolutions of CP&L's Board of Directors dated May 8, 1991,
amending the Directors Deferred Compensation Plan. (18)
10b(5) 1997 Equity Incentive Plan, effective January 1, 1997. (19)
10b(6) Performance Share Sub-Plan of the 1997 Equity Incentive Plan
(26)
10b(7) Performance Share Sub-Plan of the 1997 Equity Incentive
Plan, as revised and restated on March 17, 1999. (25)
10b(8) Carolina Power & Light Company Restricted Stock Agreement,
pursuant to the 1997 Equity Incentive Plan. (21)
10b(9) Amended Management Incentive Compensation Plan of Carolina
Power & Light Company, as amended December 10, 1997. (20)
10b(10) Amended Management Incentive Compensation Plan of Carolina
Power & Light Company, as amended January 1, 1999. (22)
10b(11) Amended Management Incentive Compensation Plan of Carolina
Power & Light Company, as amended January 1, 2000. (25)
10b(12) Carolina Power & Light Company Management Deferred
Compensation Plan, adopted as of January 1, 2000. (24)
10b(13) Amended and Restated Supplemental Senior Executive
Retirement Plan of Carolina Power & Light Company, effective
January 1, 1984, as last amended March 15, 2000. (25)
10b(14) Carolina Power & Light Company Non-Employee Director Stock
Unit Plan.(20)
10b(15) Carolina Power & Light Company Restoration Retirement Plan,
effective January 1, 1998. (20)
10b(16) Carolina Power & Light Company Restoration Retirement Plan,
as amended January 1, 1999. (23)
10b(17) Resolutions of the CP&L Board of Directors dated July 9,
1997 amending the Supplemental Executive Retirement Plan of
Carolina Power & Light Company. (20)
10b(18) Resolutions of the CP&L Board of Directors dated July 17,
1998 amending the Supplemental Executive Retirement Plan of
Carolina Power & Light Company, effective January 1, 1999.
(22)
10b(19) Supplemental Senior Executive Retirement Plan of Carolina
Power & Light Company, as amended January 1, 1999. (23)
10b(20) Employment Agreement dated May 15, 2000 by and between Don
K. Davis and Carolina Power & Light Company
10b(21) Employment Agreement dated July 15, 1999 by and between
North Carolina Natural Gas Corporation and Terrence D. Davis
10b(22) Employment Agreement dated July 15, 1999 by and between
North Carolina Natural Gas Corporation and George M. Baldwin
12 Computation of ratios of earnings to fixed charges
21 Subsidiaries of North Carolina Natural Gas Corporation
40
<PAGE>
Exhibit
Number Description
------ -----------
27 Financial Data Schedule
Notes: (All Exhibits denoted with a footnote are incorporated by reference into
this registration statement on Form 10).
(1) Filed as an exhibit to CP&L's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1998 (File no. 1-3382).
(2) Filed as an exhibit to CP&L's Quarterly Report on Form 10-Q for the
quarterly period ended March 31, 1999 (File no. 1-3382).
(3) Filed as an exhibit to CP&L Holdings, Inc.'s registration statement on
Form S-4 dated August 31, 1999 (File no. 333- 86243).
(4) Filed as an exhibit to CP&L's Current Report on Form 8-K dated August
22, 1999 (File no. 1-3382).
(5) Filed as Annex A to joint Preliminary Proxy Statement of Carolina
Power & Light Company and Florida Progress Corporation dated March 6,
2000 (File No. 1-3382).
(6) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1980 (File nos. 0-82 and 1-10998).
(7) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1989 (File nos. 0-82 and 1-10998).
(8) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1990 (File nos. 0-82 and 1-10998).
(9) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1991 (File nos. 0-82 and 1-10998).
(10) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1992 (File nos. 0-82 and 1-10998).
(11) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1994 (File nos. 0-82 and 1-10998).
(12) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1995 (File nos. 0-82 and 1-10998).
(13) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1996 (File nos. 0-82 and 1-10998).
(14) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1997 (File nos. 0-82 and 1-10998).
(15) Filed as an exhibit to NCNG's Form 10-Q for quarterly period ended
December 31, 1997 (File nos. 0-82 and 1-10998).
(16) Filed as an exhibit to NCNG's Annual Report on Form 10-K for fiscal
year ended September 30, 1998 (File nos. 0-82 and 1-10998).
(17) Filed as an exhibit to CP&L's registration statement number 33-25560.
(18) Filed as an exhibit to CP&L's registration statement number 33-48607.
(19) Filed as Appendix A to CP&L's 1997 Proxy Statement (File No. 1-3382).
(20) Filed as an exhibit to CP&L's Annual Report on Form 10-K for fiscal
year ended December 31, 1997.
(21) Filed as an exhibit to CP&L's Quarterly Report on Form 10-Q for the
quarterly period ended March 31, 1998 (File no. 1-3382).
(22) Filed as an exhibit to CP&L's Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1998 (File no. 1-3382).
41
<PAGE>
(23) Filed as an exhibit to CP&L's Annual Report on Form 10-K for the
fiscal year ended December 31, 1998 (File no. 1-3382).
(24) Filed as an exhibit to CP&L's Form S-8 dated October 25, 1999 (File
no. 333-89685).
(25) Filed as an exhibit to CP&L's Annual Report on Form 10-K for fiscal
year ended December 31, 1999 (File no 1-3382).
(26) Filed as an exhibit to CP&L's 1997 Proxy Statement (File no. 1-3382).
42
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act
of 1934, the registrant has duly caused this registration statement to be signed
on its behalf by the undersigned, thereunto duly authorized this 21st day of
July, 2000.
NORTH CAROLINA NATURAL GAS
CORPORATION
By: /s/ Don K. Davis
-------------------------------------------
Name: Don K. Davis
Title: President and Chief Executive Officer
By: /s/ Marsha M. Lederer
--------------------------------------------
Name: Marsha M. Lederer
Title: Controller (and principal accounting officer)
43
<PAGE>
--------------------------------------------------------------------------------
ANNEX F
FINANCIAL STATEMENTS
--------------------------------------------------------------------------------
F-1
<PAGE>
Index to Consolidated Financial Statements
North Carolina Natural Gas Corporation and Subsidiaries
<TABLE>
<CAPTION>
Page
----
Audited Financial Statements
----------------------------
<S> <C>
Report of Independent Public Accountants............................................................... F-3
Consolidated Balance Sheets--as of December 31, 1999, July 14, 1999, and September 30, 1998............ F-4
Consolidated Statements of Income for the periods July 15, 1999 to December 31, 1999,
October 1, 1998 to July 14, 1999, and the years ended September 30, 1998 and 1997................... F-6
Consolidated Statements of Capitalization as of December 31 1999,
July 14, 1999 and September 30, 1998................................................................ F-7
Consolidated Statements of Retained Earnings for the periods July 15, 1999 to December 31, 1999,
October 1, 1998 to July 14, 1999, and the years ended September 30, 1998 and 1997................... F-8
Consolidated Statements of Cash Flows for the periods July 15, 1999 to December 31, 1999,
October 1, 1998 to July 14, 1999, and the years ended September 30, 1998 and 1997................... F-9
Notes to Consolidated Financial Statements for the periods July 15, 1999 to December 31, 1999,
October 1, 1998 to July 14, 1999, and the years ended September 30, 1998 and 1997................... F-10
Unaudited Interim Financial Statements
--------------------------------------
Consolidated Balance Sheets--as of March 31, 2000 and December 31, 1999................................ F-28
Condensed Consolidated Statements of Income for the three months ended March 31, 2000
and March 31, 1999.................................................................................. F-30
Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2000
and March 31, 1999.................................................................................. F-31
Notes to Unaudited Condensed Consolidated Financial Statements as of March 31, 2000 and December 31,
1999 and for the three months ended March 31, 2000 and March 31,1999................................ F-32
Unaudited Pro Forma Financial Data..................................................................... F-36
----------------------------------
Unaudited Pro Forma Consolidated Condensed Statement of Operations For The Twelve Month Period
Ended December 31, 1999............................................................................. F-37
Notes to Unaudited Pro Forma Consolidated Condensed Statement of Operations For The Twelve Month
Period Ended December 31, 1999..................................................................... F-38
</TABLE>
F-2
<PAGE>
Report of Independent Public Accountants
To the Board of Directors of
North Carolina Natural Gas Corporation:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of North Carolina Natural Gas Corporation (a Delaware
corporation) and subsidiaries as of December 31, 1999 (post-merger), July 14,
1999 (pre-merger), and September 30, 1998, and the related consolidated
statements of income, retained earnings, and cash flows for the periods July 15,
1999, to December 31, 1999 (post-merger), October 1, 1998, to July 14, 1999
(pre-merger), and the years ended September 30, 1998 and 1997. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of North
Carolina Natural Gas Corporation and subsidiaries as of December 31, 1999 (post-
merger), July 14, 1999 (pre-merger), and September 30, 1998, and the results of
their operations and their cash flows for the periods July 15, 1999, to December
31, 1999 (post-merger), October 1, 1998, to July 14, 1999 (pre-merger), and the
years ended September 30, 1998 and 1997, in conformity with accounting
principles generally accepted in the United States.
/s/ Arthur Andersen LLP
Raleigh, North Carolina,
February 23, 2000.
F-3
<PAGE>
North Carolina Natural Gas Corporation
Consolidated Balance Sheets -- As of December 31, 1999, July 14, 1999, and
September 30, 1998
(in thousands)
<TABLE>
<CAPTION>
December 31, | July 14, September 30,
Assets 1999 | 1999 1998
-------------------------------------------------------------------- -------------- | ---------- ---------------
<S> <C> | <C> <C>
Gas utility plant: |
In service $354,773 | $342,684 $322,595
Less - Accumulated depreciation and amortization 129,214 | 123,396 115,181
-------- | -------- --------
225,559 | 219,288 207,414
Construction work in progress 33,625 | 29,202 17,725
-------- | -------- --------
259,184 | 248,490 225,139
-------- | -------- --------
Investments: |
Nonutility property, less accumulated depreciation (December 31, |
1999, $2,964; July 14, 1999, $2,860; September 30, 1998, |
$2,687) 5,800 | 5,569 4,966
Investment in joint ventures 5,370 | 2,754 81
-------- | -------- --------
11,170 | 8,323 5,047
-------- | -------- --------
Current assets: |
Cash and temporary cash investments 1,157 | 4,870 2,042
Restricted cash and temporary cash investments 168 | 6,240 4,745
Accounts receivable, less allowance for doubtful accounts |
(December 31, 1999, $2,335; July 14, 1999, $809; September 30, |
1998, $777) 17,144 | 13,527 14,011
Recoverable purchased gas costs 4,431 | 294 -
Inventories, at average cost - |
Gas in storage 9,980 | 7,022 8,243
Materials and supplies 7,072 | 6,808 6,417
Merchandise 392 | 1,080 1,584
Prepaid income taxes 2,072 | - -
Deferred gas cost - unbilled volumes 6,094 | 606 618
Prepaid expenses and other 513 | 510 840
-------- | -------- --------
49,023 | 40,957 38,500
-------- | -------- --------
Deferred charges and other: |
Goodwill 236,813 | - -
Debt discount and expense, being amortized over lives of related debt 4,719 | 293 357
Prepaid pension cost 1,309 | 1,527 1,851
Other 5,218 | 748 544
-------- | -------- --------
248,059 | 2,568 2,752
-------- | -------- --------
$567,436 | $300,338 $271,438
======== | ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-4
<PAGE>
North Carolina Natural Gas Corporation
Consolidated Balance Sheets -- As of December 31, 1999, July 14, 1999, and
September 30, 1998
(in thousands)
<TABLE>
<CAPTION>
December 31, | July 14, September 30,
Stockholders' Investment and Liabilities 1999 | 1999 1998
----------------------------------------------------------------- -------------- | ---------- ---------------
<S> <C> | <C> <C>
Capitalization: |
Stockholders' investment $365,102 | $126,556 $123,201
Long-term debt - | 52,500 59,000
-------- | -------- --------
365,102 | 179,056 182,201
-------- | -------- --------
Current liabilities: |
Current maturities of long-term debt - | 2,500 2,000
Notes payable - | 47,000 20,000
Notes payable to Parent 134,983 | - -
Accounts payable 19,243 | 16,635 15,964
Customer deposits 2,139 | 2,019 2,038
Restricted supplier refunds 168 | 6,240 4,745
Accrued interest 409 | 898 2,103
Refunds payable - | - 1,930
Accrued income and other taxes 1,378 | 3,209 2,623
Other 7,008 | 7,220 3,261
-------- | -------- --------
165,328 | 85,721 54,664
-------- | -------- --------
Commitments and contingencies (Note 10) |
|
|
|
Other credits: |
Deferred income taxes 26,488 | 23,963 23,440
Regulatory liability related to income taxes, net 1,782 | 1,869 1,871
Unamortized investment tax credits 2,083 | 2,180 2,328
Postretirement and postemployment benefit liability 5,248 | 5,017 3,278
Long-term incentive compensation and directors' retirement |
obligations - | 910 1,593
Other 1,405 | 1,622 2,063
-------- | -------- --------
37,006 | 35,561 34,573
-------- | -------- --------
$567,436 | $300,338 $271,438
======== | ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-5
<PAGE>
North Carolina Natural Gas Corporation
Consolidated Statements of Income For the Periods July 15, 1999, to December 31,
1999, October 1, 1998 to July 14, 1999, and the Years Ended September 30, 1998
and 1997
(in thousands, except average common shares outstanding and per share
information)
<TABLE>
<CAPTION>
| October 1,
July 15 - | 1998 -
December 31, | July 14, September 30,
| --------------------------------
1999 | 1999 1998 1997
-------------- | ------------- ------------- ------------
<S> <C> | <C> <C> <C>
Operating revenues (Note 12) $101,504 | $ 169,787 $ 231,915 $ 235,534
Cost of sales 68,898 | 102,668 150,601 156,272
-------- | ----------- ----------- ----------
Gross margin 32,606 | 67,119 81,314 79,262
-------- | ----------- ----------- ----------
Operating expenses: |
Operations 12,454 | 23,864 25,062 25,392
Maintenance 2,525 | 3,039 3,740 4,081
Depreciation 6,572 | 9,260 11,567 10,286
Goodwill amortization 2,844 | - - -
General taxes 1,452 | 6,871 8,557 8,461
-------- | ----------- ----------- ----------
Total operating expenses 25,847 | 43,034 48,926 48,220
-------- | ----------- ----------- ----------
Operating income 6,759 | 24,085 32,388 31,042
Other income (Note 3) 730 | 324 133 1,962
-------- | ----------- ----------- ----------
Income before interest and taxes 7,489 | 24,409 32,521 33,004
-------- | ----------- ----------- ----------
Interest charges: |
Interest on long-term debt 469 | 3,767 5,096 5,278
Other interest 3,162 | 1,455 1,196 459
Amortization of debt discount and expense 524 | 64 36 36
Allowance for funds used during construction (806) | (1,697) (1,248) (1,087)
-------- | ----------- ----------- ----------
Total interest charges 3,349 | 3,589 5,080 4,686
-------- | ----------- ----------- ----------
Income before income taxes 4,140 | 20,820 27,441 28,318
-------- | ----------- ----------- ----------
Income taxes: |
Federal 2,261 | 8,089 8,241 8,549
State 500 | 2,048 2,052 2,175
-------- | ----------- ----------- ----------
Net income $ 1,379 | $ 10,683 $ 17,148 $ 17,594
======== | =========== =========== ==========
Average common shares outstanding 100 | 10,166,000 10,059,000 9,932,000
-------- | ----------- ----------- ----------
Basic and diluted earnings per share (Notes 3 and |
9) $ 13,790 | $ 1.05 $ 1.70 $ 1.77
======== | =========== =========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-6
<PAGE>
North Carolina Natural Gas Corporation
Consolidated Statements of Capitalization as of December 31, 1999, July 14,
1999, and September 30, 1998
(in thousands, except shares authorized and outstanding information)
<TABLE>
<CAPTION>
December 31, | July 14, September 30,
1999 | 1999 1998
-------------- | ---------- ---------------
<S> <C> | <C> <C>
Stockholders' investment: |
Common stock, par value $0.10; 100 shares authorized; shares |
outstanding: December 31, 1999 - 100 (Note 9) $ - | $ - $ -
|
Common stock, par value $2.50; 24,000,000 shares |
authorized; shares outstanding: July 14, 1999 - |
10,236,000; 1998 - 10,125,000 (Note 9) - | 25,590 25,312
Capital in excess of par value 363,723 | 37,651 34,625
Retained earnings 1,379 | 63,315 63,264
-------- | -------- --------
Total stockholders' investment 365,102 | 126,556 123,201
-------- | -------- --------
Long-term debt: |
Debentures, 8.75% Series B, due June 15, 2001 - | - 6,000
Debentures, 9.21% Series C, due November 15, 2011 - | 25,000 25,000
Senior Notes, 7.15%, due November 15, 2015 - | 30,000 30,000
-------- | -------- --------
- | 55,000 61,000
Less - Current maturities - | (2,500) (2,000)
-------- | -------- --------
Total long-term debt - | 52,500 59,000
-------- | -------- --------
Total capitalization $365,102 | $179,056 $182,201
======== | ======== ========
Capitalization ratios: |
Stockholders' investment 100.0% | 70.7% 66.9%
Long-term debt (including current maturities) - | 29.3 33.1
-------- | -------- --------
100.0% | 100.0% 100.0%
======== | ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
F-7
<PAGE>
North Carolina Natural Gas Corporation
Consolidated Statements of Retained Earnings For the Periods July 15, 1999, to
December 31, 1999, October 1, 1998 to July 14, 1999, and the Years Ended
September 30, 1998 and 1997
(in thousands)
<TABLE>
<CAPTION>
December 31, | July 14, September 30,
| ----------------------
1999 | 1999 1998 1997
-------------- |---------- --------- ---------
<S> <C> | <C> <C> <C>
Balance at beginning of period $ - | $ 63,264 $64,381 $55,891
Net income 1,379 | 10,683 17,148 17,594
Cash dividends on common stock (per share - $0 for the |
period ended December 31, 1999, $1.046 for the period |
ended July 14, 1999, $.983 in 1998 and $.917 in 1997) - | (10,632) (9,890) (9,104)
Stock split effected in the form of a stock dividend (Note 9) - | - (8,375) -
------ | -------- ------- -------
Balance at end of period $1,379 | $ 63,315 $63,264 $64,381
====== | ======== ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements
F-8
<PAGE>
North Carolina Natural Gas Corporation
Consolidated Statements of Cash Flows For the Periods July 15, 1999, to
December 31, 1999, October 1, 1998 to July 14, 1999, and the Years Ended
September 30, 1998 and 1997
(in thousands)
<TABLE>
<CAPTION>
| October 1,
July 15 - | 1998 -
December 31, | July 14, September 30,
| -------------------
1999 | 1999 1998 1997
---------- | --------- -------- --------
<S> <C> | <C> <C> <C>
Cash flows from operating activities: |
Net income $ 1,379 | $ 10,683 $ 17,148 $ 17,594
Adjustments to reconcile net income to net cash provided by |
(used in) operating activities- |
Depreciation 6,572 | 9,260 11,567 10,286
Amortization of goodwill 2,844 | - - -
Amortization of deferred charges 524 | 64 38 38
Deferred income taxes 2,525 | 523 483 1,694
Investment tax credits (97) | (148) (196) (196)
Other (766) | 1,378 (319) 57
Changes in other current assets and liabilities- |
Accounts receivable, net (5,116) | 484 3,348 (58)
Taxes receivable (2,072) | - - -
Gas in storage (2,958) | 1,221 556 1,184
Materials, supplies and merchandise 109 | 113 (5,130) (1,095)
Prepaid income taxes - | - 4,521 (4,521)
Accounts payable (3,411) | 4,630 25 584
Refunds payable and recoverable purchased gas costs (9,625) | (717) 3,089 1,132
Accrued income and other taxes (1,831) | 916 315 (2,441)
Other 291 | (2,789) 2,562 1,521
-------- | -------- -------- --------
Net cash provided by (used in) operating activities (11,632) | 25,618 38,007 25,779
-------- | -------- -------- --------
Cash flows from investing activities: |
Property additions (27,198) | (38,114) (36,652) (30,500)
Proceeds from Expansion Fund 9,700 | 4,900 3,675 455
Other, net (2,616) | (2,673) 219 440
-------- | -------- -------- --------
Net cash (used in) investing activities (20,114) | (35,887) (32,758) (29,605)
-------- | -------- -------- --------
Cash flows from financing activities: |
Repayment of and borrowings on notes payable (47,000) | 27,000 5,000 12,000
Borrowings from Parent 134,983 | - - -
Retirement of long-term debt (55,000) | (6,000) (2,000) (2,000)
Unamortized debt discount and expense (4,950) | - - -
Cash dividends paid - | (10,632) (9,890) (9,104)
Issuance of common stock through dividend reinvestment plan, |
employee stock purchase plan and key employee stock option |
plan - | 2,729 2,721 2,775
-------- | -------- -------- --------
Net cash provided by (used in) financing activities 28,033 | 13,097 (4,169) 3,671
-------- | -------- -------- --------
Net increase (decrease) in cash and temporary cash investments (3,713) | 2,828 1,080 (155)
Cash and temporary cash investments, beginning of period 4,870 | 2,042 962 1,117
-------- | -------- -------- --------
Cash and temporary cash investments, end of period $ 1,157 | $ 4,870 $ 2,042 $ 962
======== | ======== ======== ========
Cash paid for: |
Interest (net of amounts capitalized) $ 2,234 | $ 2,035 $ 6,022 $ 5,377
Income taxes (net of refunds) 2,834 | 9,279 4,820 16,136
======== | ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-9
<PAGE>
North Carolina Natural Gas Corporation
Notes to Consolidated Financial Statements For the Periods July 15, 1999, to
December 31, 1999, October 1, 1998, to July 14, 1999, and for the Years Ended
September 30, 1998 and 1997
1. Summary of Significant Accounting Policies and Principles of Consolidation:
Basis of Presentation
North Carolina Natural Gas Corporation (NCNG or the Company), a wholly
owned subsidiary of Carolina Power and Light Company (CP&L or the Parent) (see
Note 2) is in the business of providing natural gas, propane gas and related
services to approximately 178,000 customers in south-central and eastern North
Carolina. The Company's primary business is the sale and/or transportation of
natural gas to over 103,000 residential customers, over 13,900 commercial and
agricultural customers, 473 industrial and electric utility customers located in
110 towns and cities and four municipal gas distribution systems which serve
over 50,000 end users. For the July 15, 1999 - December 31, 1999 period,
approximately 72% of the natural gas volumes were delivered to industrial and
electric utility customers but no individual customer accounted for more than 7%
of the Company's delivered gas volumes, revenues or margin. Industrial customers
are geographically dispersed throughout the Company's service area, and they are
classified into many different industries including the manufacture of brick and
ceramics, chemicals, glass, nuclear fuels, textiles, paper and paperboard,
plywood and other wood products and the processing of aluminum and other metals,
tobacco, rubber, dairy and food products.
The Company's natural gas business is regulated by the North Carolina
Utilities Commission (NCUC). Its nonutility division provides propane gas and
related services to approximately 11,000 customers and sells and services gas
appliances.
The accompanying consolidated financial statements include the accounts of
the Company and its wholly owned subsidiaries, Cape Fear Energy Corporation,
NCNG Energy Corporation, NCNG Pine Needle Investment Corporation, and NCNG
Cardinal Pipeline Investment Corporation (see Note 5). All significant
intercompany transactions have been eliminated in consolidation.
The Company was acquired by CP&L pursuant to a merger which closed on July
15, 1999 (see Note 2). The merger was accounted for using the purchase method
of accounting in accordance with generally accepted accounting principles, and
the applicable effects were reflected in the financial statements of the Company
as of the merger date. Accordingly, the post-merger financial statements
reflect a new basis of accounting. Pre-merger and post-merger financial
statements (separated by a heavy black line) are presented.
Utility Plant
Gas utility plant is stated at original cost. Such cost includes payroll-
related costs such as taxes, pension and other fringe benefits, general and
administrative costs and an allowance for funds used during construction. The
Company capitalizes funds used during construction based on the overall cost of
capital, which includes the cost of both debt and equity funds used to
F-10
<PAGE>
finance construction. The cost of depreciable property retired, plus the cost of
removal less salvage, is charged to accumulated depreciation.
Depreciation
Depreciation is provided on the straight-line method over the estimated
useful lives of the assets. The composite depreciation rate was approximately
3.7%, 3.6%, 3.7% and 3.5% of the cost of total depreciable property for the
periods ended December 31, 1999, July 14, 1999, September 30, 1998, and
September 30, 1997, respectively.
Income Taxes
The Company uses comprehensive interperiod income tax allocation (full
normalization) to account for temporary differences in the recognition of
revenues and expenses for financial and income tax reporting purposes.
Investment tax credits are deferred and amortized to income over the
service lives, which are approximately 30 years, of the related property.
Recognition of Revenue
The Company follows the practice of rendering customer bills on a cycle
basis throughout each month and recording revenue at the time of billing. The
Company defers the cost of gas delivered but unbilled due to cycle billing and
recognizes the revenue and related cost of gas in the period in which it is
billed.
Temporary Cash Investments
Temporary cash investments are securities with original maturities of 90
days or less. For purposes of the consolidated statements of cash flows,
temporary cash investments are considered cash equivalents.
Restricted Cash and Temporary Cash Investments and Restricted Supplier Refunds
In February 1993, the NCUC issued its Order establishing an Expansion Fund
for the Company to be funded initially by refunds the Company had received from
its pipeline suppliers. The investment and use of these funds had been
restricted by a previous Order of the NCUC. At December 31, 1999, July 14,
1999, and September 30, 1998, the refunds received plus accrued interest, which
had not been remitted to the NCUC, amounted to $168,000, $6.2 million and $4.7
million, respectively, and are reported on the accompanying consolidated balance
sheets in restricted cash and temporary cash investments and restricted supplier
refunds. The Company received payments of $6.6 million, $4.9 million and $3.7
million for the periods ended December 31, 1999, July 14, 1999, and the year
ended September 30, 1998, respectively, from the Expansion Fund related to the
Mount Olive/Jacksonville expansion (see Note 3). The Company received one
payment of $3.1 million from the Expansion Fund related to the Martin/Bertie
expansion (see Note 3) during the period ended December 31, 1999. At December
31, 1999, July 14, 1999, and September 30, 1998, $11.5 million, $14.5 million
and $14.0 million, respectively, was held by the NCUC for current and future
NCUC-approved expansion projects.
Pursuant to the NCUC Orders, the funds not yet transferred to the Expansion
Fund are to remain segregated from the Company's general funds and, pending
further order of the NCUC, may be remitted to the NCUC and used for expansion of
the Company's facilities into unserved areas of the Company's franchised
territory or, if not used for expansion, refunded to the Company's customers.
In July 1998, the Company filed with the NCUC to transfer $4.1 million
F-11
<PAGE>
to the Fund. In November 1998, the request for transfer was approved and the
monies were transferred to the Fund. In August 1999, the Company filed with the
NCUC to transfer $6.4 million to the Fund. In November 1999, the request for
transfer was approved and the monies were transferred to the Fund in December
1999. Amounts remitted to the NCUC are not included in the Company's
consolidated financial statements because they are no longer controlled by the
Company.
In November 1998, North Carolina voters approved a $200 million bond
referendum providing grants, loans or other financing to natural gas local
distribution companies or other entities to extend natural gas to unserved
territories. The Company plans to seek monies from the bonds for future
projects.
Change of Fiscal Year
In conjunction with the merger with CP&L, the Company changed its fiscal
year to commence on January 1 and conclude on December 31 of each year. The
Company's fiscal year previously commenced each October 1, concluding on
September 30 of the following calendar year.
Reclassifications
Certain amounts in the consolidated financial statements for the years
ended September 30, 1998 and 1997, have been reclassified to conform with the
current period presentation.
Fair Value of Financial Instruments
The fair value of the Company's long-term debt is estimated using a
discounted cash flow methodology. Based on published corporate borrowing rates
for debt instruments with similar terms and average maturities, the estimated
fair value of the Company's long-term debt (including current maturities) at
July 14, 1999, is approximately $61.0 million as compared to a carrying value of
$55.0 million, and at September 30, 1998, is approximately $68.3 million as
compared to a carrying value of $61.0 million.
Restricted temporary cash investments are invested primarily in
certificates of deposit and United States Treasury bills. The carrying value of
these investments and all other financial instruments as reflected in the
accompanying consolidated balance sheets approximates fair market value.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
New Accounting Pronouncements
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for the reporting and
display of comprehensive income and its components in a full set of general
purpose financial statements. The Company adopted SFAS No. 130 on October 1,
1998. SFAS No. 131 introduces a new model for segment reporting based
F-12
<PAGE>
on the way senior management organizes segments within the Company for making
operating decisions and assessing performance. The Company adopted SFAS No. 131
in Fiscal 1998 (see Note 12).
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosure
About Pensions and Other Postretirement Benefits." SFAS No. 132 is an amendment
of SFAS No. 87, "Employers' Accounting for Pensions," SFAS No. 88, "Employers'
Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and
for Termination Benefits," and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." SFAS No. 132 requires additional
disclosures of the changes in the benefit obligation and plan assets during the
period, including economic events during the period. Economic events include
amendments, combinations, divestitures, curtailments and settlements. This
statement is effective for fiscal years beginning after December 15, 1997. The
Company adopted this standard October 1, 1998 (see Note 8).
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 standardizes the accounting
for derivative instruments, including certain derivative instruments embedded in
other contracts, by requiring that an entity recognize those items as assets or
liabilities in the consolidated statement of financial position and measure them
at fair value. This statement is effective for fiscal years beginning after June
15, 2000, as amended by SFAS No. 137, "Accounting for Derivative Instruments and
Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133"
issued in June 1999. The Company expects to determine any effects of SFAS No.
133 by mid-2000.
2. Merger with CP&L:
On July 15, 1999, the Company was acquired by CP&L and became a wholly
owned subsidiary of CP&L. CP&L is an investor-owned electric utility which
serves nearly 1.2 million customers in eastern North Carolina, the Asheville
area and the Pee Dee Region of South Carolina. CP&L holds directly all of the
issued and outstanding common shares of the Company. As a result of the merger,
the former common shareholders of NCNG now own common shares of CP&L. The
merger was accounted for as a purchase of the Company's net assets with
8,285,734 shares of CP&L Common Stock issued through the conversion of each
outstanding NCNG share into .8054 of a share of CP&L Common Stock (fractional
shares were paid in cash). The purchase price was approximately $364 million,
which included approximately $3.7 million of merger related costs. Goodwill of
approximately $240 million was recorded in connection with the purchase, which
represented the excess of the purchase price over the Company's net assets after
fair value adjustments. Goodwill is to be amortized on a straight-line basis
over 40 years for amounts related to regulated assets, and 20 years for amounts
related to nonregulated assets. Such amount may be adjusted if additional
information produces changed assumptions over the 12 months following the
merger.
The goodwill recognized in connection with the merger represents the excess
of the purchase price, including direct costs, over the Company's adjusted net
assets on July 15, 1999. The primary purchase accounting adjustments included
estimated liabilities for severance, relocation, other compensation benefits and
a revaluation of the Company's merchandise assets and receivables pursuant to
management's decision to exit that line of business.
F-13
<PAGE>
3. Regulatory and Gas Supply Matters:
On October 27, 1995, the NCUC issued its Order granting a general rate
increase amounting to approximately $4.2 million in annual revenues effective
November 1, 1995. The NCUC's Order approved, in all material respects, the
Stipulation of Settlement reached among the Company, the Public Staff of the
NCUC, the Carolina Utility Customers Association, Inc. and other intervenors in
the rate case. The Order provided for a rate of return on net investment of
10.09% but, pursuant to the Stipulation of Settlement, did not state separately
the rate of return on common equity or the capital structure used to calculate
revenue requirements. The Order provided for significant rate design changes by
increasing residential and commercial rates while reducing industrial sales and
transportation rates to recognize, among other things, the differences in costs
of serving the various customer classes. The Order also established several new
rate schedules, including an economic development rate to assist in attracting
new industry to the Company's service area and a rate to provide standby, on-
peak gas supply service to industrial and other customers whose gas service
would otherwise be interrupted. In conjunction with the acquisition by CP&L,
NCNG signed a stipulation agreement with the Public Staff of the NCUC in which
the Company agreed to cap margin rates for gas sales and transportation service,
with limited exceptions, through November 1, 2003. Management is of the opinion
that this agreement will not impair the Company's ability to recover prudent
costs through rates and will not have a material adverse effect on the
consolidated financial position, results of operations, or cash flows of the
Company.
As part of the October 27, 1995 Rate Order, the NCUC approved continued use
of the Weather Normalization Adjustment (WNA) for the space-heating market,
originally approved in the December 6, 1991 Rate Order. The WNA stabilizes the
Company's winter revenues and customers' bills by adjusting rates when weather
deviates from normal. The nongas component of rates for space heating customers
is adjusted upward when weather is warmer than normal and downward when weather
is colder than normal. For the periods July 15, 1999 - December 31, 1999,
October 1, 1998 - July 14, 1999, Fiscal 1998 and Fiscal 1997, winter weather was
16%, 15%, 19% and 21% warmer than normal, respectively. Accordingly, the WNA
increased net billings to customers by $1.0 million, $4.4 million, $4.2 million
and $2.9 million, respectively.
Also, as a part of the October 27, 1995, Rate Order, the NCUC approved
establishment of the Price Sensitive Volume Adjustment (PSVA). The PSVA
protects the Company against loss of load from eight large, fuel-switchable
customers using heavy fuel oil as an alternative fuel, while providing that all
actual margins earned on deliveries of gas to such customers should be flowed
through to all other customers. The actual margin earned on gas delivered to
PSVA customers and flowed through to all other customers was $487,000, $382,000,
$461,000 and $1.1 million for the periods July 15, 1999 - December 31, 1999,
October 1, 1998 - July 14, 1999, Fiscal 1998 and Fiscal 1997, respectively.
Finally, the NCUC approved the accounting for and recovery in rates of
costs associated with environmental assessments and remediation of a former
manufactured gas plant (MGP) site in Kinston, North Carolina (see Note 10). The
NCUC found that NCNG acted in a reasonable and prudent manner, and, accordingly,
approved the Company's proposal to recover an annualized amount of MGP costs
based on amounts expended, net of recoveries from third parties.
F-14
<PAGE>
In May 1996, the Company filed with the NCUC to recover net customer costs
of $3.0 million from exploration and development activities. The recovery is a
result of a true-up of distributions of costs and revenue benefits from the
Company's exploration and drilling programs. In February 1997, the NCUC issued
its Order granting a pretax recovery of approximately $1.9 million. The NCUC's
Order approved, in all material respects, the Stipulation of Settlement reached
by the Company and the Public Staff of the NCUC. Due to the uncertainty of
recovery, prior to the Order, no asset or gain was recorded in the Company's
consolidated financial statements. As a result of the Order, the Company
realized a gain of $.11 per share in Fiscal 1997. The gain has been recorded in
other income in the accompanying statements of income.
In August 1995, the NCUC issued its Order approving the Company's first
project utilizing the Expansion Fund. The project extended NCNG's transmission
pipeline 71 miles from Mount Olive through Duplin County and on to the Marine
Base-Camp Lejeune in Jacksonville, North Carolina. In Fiscal 1998, the Company
constructed the first 20-mile segment of 10-inch pipeline to Warsaw in Duplin
County. Throughout calendar 1998 and 1999, the Company continued to acquire
rights-of-way and continued to perform necessary environmental studies for the
remainder of the route. The project was completed in November 1999 and final
accounting is expected to be completed in March 2000. Due to delays caused by
the environmental studies, the estimated cost to complete the project increased
$5.4 million to $24.2 million. The Expansion Fund was to provide $12.4 million
based on the original economic feasibility analysis provided to, and approved
by, the NCUC. In November 1997, the Company applied to the NCUC to request an
additional $4.3 million from the Expansion Fund to cover the net increase in
costs. In August 1998, the NCUC granted an additional $4.2 million of Expansion
Fund monies to be used for this project.
In April 1998, the Company filed an application with the NCUC to extend its
pipeline 38 miles to provide natural gas service to Bertie and Martin Counties
using the Fund. In July 1998, the Company filed an amendment to extend this
project an additional six miles to Robersonville in Martin County. The amended
main extension project would run approximately 44 miles from Ahoskie to
Robersonville and cost $12.6 million. The negative net present value of the
project requested from the Fund was $7.5 million. Hearings were held in
September 1998 and a Commission Order was issued in November 1998 approving $7.5
million from the Expansion Fund. On July 1, 1999 the Company filed a petition
for additional funding of $2.8 million due to the closing of an industrial
plant. The NCUC issued an order in October 1999 approving an additional $2.8
million from the Expansion Fund.
The NCUC's annual review of the Company's gas costs for the 12 months ended
October 31, 1998, was held in April 1999. The NCUC found NCNG's gas costs and
gas purchasing practices to be prudent.
Both of the Company's interstate pipeline suppliers, Transcontinental Gas
Pipe Line Corporation (Transco) and Columbia Gas Transmission Corporation
(Columbia), have ongoing rate and certificate matters under jurisdiction of the
Federal Energy Regulatory Commission (FERC). The Company does not expect that
any regulatory decisions or court orders will have a material impact on its
consolidated financial position, results of operations, or cash flows because
all prudently incurred gas costs, including interstate pipeline capacity and
storage service costs, are eligible for immediate recovery from the Company's
customers, and refunds from
F-15
<PAGE>
interstate pipelines must be transferred to the Expansion Fund or refunded
directly to the Company's customers.
4. Income Taxes:
The components of income tax expense are as follows (in thousands):
<TABLE>
<CAPTION>
July 15 - | October 1 For the Years
December 31, | 1998 - Ended September 30,
| ------------------------------------
1999 | July 14, 1999 1998 1997
--------------- | -------------------- ----------------- -----------------
Federal State | Federal State Federal State Federal State
-------- ----- | ---------- -------- -------- ------- -------- -------
<S> <C> <C> | <C> <C> <C> <C> <C> <C>
Income taxes charged to |
operations- |
Payable currently $2,025 $367 | $7,290 $1,766 $7,627 $1,630 $6,833 $1,658
Deferred to subsequent |
years 249 118 | 374 149 249 77 783 249
|
Amortization of investment |
tax credits (97) - | (147) - (195) - (194) -
------ ---- | ------ ------ ------ ------ ------ ------
2,177 485 | 7,517 1,915 7,681 1,707 7,422 1,907
Income taxes charged to |
nonutility operations 84 15 | 572 133 560 345 1,127 268
------ ---- | ------ ------ ------ ------ ------ ------
Total $2,261 $500 | $8,089 $2,048 $8,241 $2,052 $8,549 $2,175
====== ==== | ====== ====== ====== ====== ====== ======
</TABLE>
A reconciliation of income tax expense at the federal statutory rate to
recorded income tax expense is as follows (in thousands):
<TABLE>
<CAPTION>
July 15 - | October 1 For the Years Ended
December 31, | 1998 - September 30,
| ----------------------------
1999 | July 14, 1999 1998 1997
------------------- | ----------------- ---- ----
<S> <C> | <C> <C> <C>
Federal taxes at 35% statutory rate $1,449 | $ 7,287 $ 9,604 $ 9,910
State income taxes, net of federal |
benefit 325 | 1,331 1,334 1,413
Amortization of investment tax |
credits (97) | (147) (196) (196)
Amortization of excess deferred |
income taxes returned to customers (166) | (276) (369) (222)
|
Tax effect of allowance for funds |
used during construction - Equity |
portion (263) | (375) (437) (240)
|
Merger costs/goodwill 1,098 | 1,595 - -
Other 415 | 722 357 59
------ | ------- -------- -------
Total income tax expense $2,761 | $10,137 $ 10,293 $10,724
====== | ======= ======== =======
</TABLE>
Effective October 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes." The adoption of SFAS No. 109 resulted in additional deferred
income taxes and related regulatory assets and liabilities. The net regulatory
liability is due primarily to deferred income taxes recognized in years prior to
1987 at rates higher than currently enacted.
F-16
<PAGE>
The tax effects of temporary differences in the carrying amounts of assets
and liabilities in the consolidated financial statements and their respective
tax bases which give rise to deferred income tax assets and liabilities are as
follows (in thousands):
<TABLE>
<CAPTION>
December 31, | July 14, September 30,
1999 | 1999 1998
------------ | ---------- -------------
<S> <C> | <C> <C>
Deferred tax liabilities- |
Accelerated depreciation $26,910 | $26,521 $25,735
Property basis differences 3,804 | 4,098 4,184
Debt costs 1,716 | - -
Unbilled volumes 2,272 | (15) -
Other 1,139 | 1,139 1,017
----------- | ------- -------
Total deferred tax liabilities 35,841 | 31,743 30,936
----------- | ------- -------
Deferred tax assets- |
Unamortized investment tax credits 839 | 876 932
Regulatory liability related to income taxes, |
net 810 | 775 811
Other postretirement benefits 1,500 | 1,408 1,204
Environmental reserves 410 | 410 410
Unbilled volumes - | - 1,080
Other 5,794 | 4,311 3,059
----------- | ------- -------
Total deferred tax assets 9,353 | 7,780 7,496
----------- | ------- -------
Net deferred tax $26,488 | $23,963 $23,440
=========== | ======= =======
</TABLE>
5. Subsidiary Operations:
In April 1997, the Company formed a new subsidiary, NCNG Pine Needle
Investment Corporation (Pine Needle Investment), to participate in gas supply
and pipeline projects in North Carolina. Pine Needle Investment has a 5%
ownership interest in Pine Needle LNG Company, LLC (Pine Needle) which built and
is operating a liquefied natural gas (LNG) plant located near Transco's main
interstate pipeline north of Greensboro, North Carolina. The LNG plant cost
$106 million to build, has a storage capacity of four billion cubic feet and was
placed in service on May 1, 1999. Transco has two subsidiaries, one of which
acts as a partner and one as the operator of Pine Needle. Also, subsidiaries of
Piedmont Natural Gas Company (Piedmont), Public Service Company of North
Carolina, Inc. (Public Service) and Amerada Hess Company, as well as The
Municipal Gas Authority of Georgia, are partners in Pine Needle. Piedmont,
Public Service and NCNG are Pine Needle's largest customers. NCNG has
contracted for 400,000 dt, or 10%, of Pine Needle's capacity. Pine Needle
Investment provided capital of $2.675 million to Pine Needle in May 1999. Pine
Needle Investment accounts for its investment in Pine Needle under the equity
method of accounting.
Also, in April 1997, the Company formed another subsidiary, NCNG Cardinal
Pipeline Investment Corporation (Cardinal Pipeline Investment), which is
involved with subsidiaries of Transco, Piedmont and Public Service in the
organization of a limited liability company, known as Cardinal Extension
Company, LLC (Cardinal Extension) to acquire an existing pipeline and extend it
to provide the capacity needed to deliver gas from the Pine Needle LNG plant and
Transco's existing pipeline into NCNG's system at a point near Clayton, North
Carolina, on the Wake-Johnston County line. Cardinal Pipeline Investment owns a
5% interest in Cardinal
F-17
<PAGE>
Extension. NCNG has contracted for 40,000 dt per day of firm capacity on the
Cardinal Pipeline beginning November 1, 1999, the date the facilities were
placed in service. On October 29, 1999, Cardinal Pipeline Investment provided
capital of $2.575 million to Cardinal Extension. Cardinal Pipeline Investment
accounts for its investment in Cardinal Extension under the equity method of
accounting.
The Company has another subsidiary, NCNG Energy Corporation (Energy), which
was originally formed to participate in Pine Needle and Cardinal Extension. The
investments in these projects were transferred to Pine Needle Investment and
Cardinal Pipeline Investment, respectively, in June 1997. Energy is used for
other energy-related investments and sales to natural gas resellers.
Cape Fear Energy Corporation's (Cape Fear) primary activity was natural gas
marketing for industrial and municipal customers located on NCNG's system.
Effective July 15, 1999, Cape Fear ceased all marketing activities in accordance
with terms of the Code of Conduct and Regulatory Conditions ordered by the NCUC
in connection with the merger with CP&L.
NCNG Exploration Corporation's (Exploration) interests in all of its
exploration and development programs were sold effective June 7, 1994. On
October 1, 1997, all marketing activities in Exploration ceased and the company
was liquidated. The gas marketing activities to gas resellers are being
conducted by Energy.
6. Short-term and Long-term Debt:
Prior to the CP&L merger, the Company had lines of credit with North
Carolina banks for an aggregate amount of $69.0 million, of which $39.0 million
was on a committed basis as of July 14, 1999. Under these lines, the Company
borrowed funds on a short-term basis in connection with its construction program
and also for seasonal financing of storage gas. Such borrowings were normally
on a demand basis for a period of 90 days or less. At July 14, 1999, $47.0
million was outstanding under lines of credit at an interest rate of 5.40%. In
connection with the bank lines of credit, there were nominal commitment fees on
the unused lines of credit.
On July 16, 1999, NCNG restructured its aggregate $69.0 million lines of
credit with North Carolina banks with a $150.0 million line of credit with CP&L
and paid off all borrowings plus accrued interest due to the North Carolina
banks. In addition, in August 1999, the Company advance refunded all of its
remaining long-term debt with proceeds from the CP&L line. These advance
refundings totaled $59.9 million which represents principal of $55 million and
debt prepayment penalties (see Note 7) of $4.9 million. At December 31, 1999,
$135.0 million was outstanding under the CP&L line of credit at an interest rate
of LIBOR plus .1% (5.82% at December 31, 1999). In connection with the CP&L
line of credit, there are no commitment fees on the unused line of credit.
7. Regulatory Asset:
As a regulated entity, the Company is subject to the provisions of
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation." Accordingly, the Company records certain
assets resulting from the effects of the ratemaking process, which would not be
recorded under generally accepted accounting principles for
F-18
<PAGE>
unregulated entities. As of December 31, 1999, the Company has a regulatory
asset related to losses on reacquired debt instruments totaling $4,719,000 (see
Note 6). This amount is reflected on the accompanying consolidated balance
sheets as debt discount and expense. The total loss incurred of $4,950,000 is
being amortized over the remaining terms of the reacquired debt instruments.
The Company monitors the regulatory and competitive environment in which it
operates to determine that regulatory assets continue to be probable of
recovery. At some point in the future, if it is determined that all or a
portion of these regulatory assets no longer meet the criteria for continued
application of SFAS 71, then the Company would be required to write off that
portion which it could not recover, net of any regulatory liabilities which
would be deemed no longer necessary.
8. Pension, Postretirement, Postemployment, and Other Benefits:
Through December 31, 1999, the Company had a defined benefit pension plan
which provided retirement benefits for its employees within specified age limits
and periods of service. Plan benefits were based on years of service and the
employee's compensation during the last five years of employment. The Company's
funding policy was to contribute annually an amount equal to the maximum
allowable tax-deductible amount.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are as follows (in thousands):
<TABLE>
<CAPTION>
| October 1, For the Year
July 15 - | 1998 - Ended
December 31, | July 14, September 30,
1999 | 1999 1998
----------- | ----------- --------------
<S> <C> | <C> <C>
Change in benefit obligation- |
Benefit obligation at beginning of period $28,760 | $27,558 $23,898
Service cost 483 | 725 859
Interest cost 852 | 1,275 1,716
Actuarial (gain) loss (3,615) | - 2,059
Benefits paid (569) | (798) (974)
Amendments (370) | - -
--------- | ------- -------
Benefit obligation at end of period 25,541 | 28,760 27,558
--------- | ------- -------
Change in plan assets- |
Fair value of plan assets at beginning of period 31,348 | 28,949 27,659
Actual return on plan assets 357 | 3,197 1,425
Employer contributions - | - 839
Benefits paid (569) | (798) (974)
--------- | ------- -------
Fair value of plan assets at end of period 31,136 | 31,348 28,949
--------- | ------- -------
Funded status 5,595 | 2,588 1,391
Unrecognized net actuarial (gain) loss (4,275) | (1,454) 18
Unrecognized prior service cost (11) | 393 442
--------- | ------- -------
Prepaid pension cost $ 1,309 | $ 1,527 $ 1,851
========= | ======= =======
</TABLE>
F-19
<PAGE>
Major assumptions and net periodic pension cost include the following
(dollars in thousands):
<TABLE>
<CAPTION>
| October 1, For the Year For the Year
July 15 - | 1998 - Ended Ended
December 31, | July 14 September 30, September 30,
1999 | 1999 1998 1997
---------- | ----------- -------------- ---------------
<S> <C> | <C> <C> <C>
Weighted average assumptions- |
Discount rate 7.5% | 6.5% 6.5% 6.5%
Expected return on plan assets 8.0% | 8.0% 8.0% 8.0%
Rate of compensation increase 4.2% | 4.0% 4.0% 4.0%
Components of net periodic benefit cost- |
Service cost $ 483 | $ 725 $ 859 $ 832
Interest cost 852 | 1,275 1,716 1,738
Expected return on plan assets (1,150) | (1,725) (2,207) (1,826)
Amortization of prior service cost 33 | 50 66 66
Amortization of transition net asset - | - - (214)
Recognized net actuarial gain - | - (57) -
----------- | ---------- --------- ----------
Net periodic benefit cost $ 218 | $ 325 $ 377 $ 596
=========== | ========== ========= ==========
</TABLE>
At July 14, 1999, plan assets were invested approximately 49% in fixed
income securities and 51% in equity securities, including 3% in the common stock
of the Company. At December 31, 1999, plan assets were invested entirely in
fixed income securities. Effective December 31, 1999, the Company's pension
plan was merged into CP&L's Supplemental Retirement Plan (CP&L Plan) and the
Company became a participating employer in the CP&L Plan. Each participant in
the Company's pension plan as of December 31, 1999, received transition credits,
providing for equitable participation in the CP&L Plan.
The Company also provided certain medical and life insurance benefits for
retired employees, and substantially all employees were to remain eligible for
these benefits on a prospective basis at retirement. These benefits were accrued
using a single actuarial method which spread the expected cost of such benefits
to each year of an employee's service until the employee became fully eligible
to receive the benefits. The NCUC approved this treatment in the Company's most
recent general rate case decided on October 27, 1995.
F-20
<PAGE>
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are as follows (in thousands):
<TABLE>
<CAPTION>
| October 1, For the Year
July 15 - | 1998 - Ended
December 31, | July 14, September 30,
1999 | 1999 1998
----------- | ----------- ---------------
<S> <C> | <C> <C>
Change in benefit obligation- |
Benefit obligation at beginning of period $ 6,806 | $ 6,760 $ 6,077
Service cost 100 | 145 185
Interest cost 239 | 324 479
Actuarial loss 578 | - 478
Benefits paid (225) | (423) (459)
Amendments 1,062 | - -
-------- | -------- -------
Benefit obligation at end of period 8,560 | 6,806 6,760
-------- | -------- -------
Change in plan assets- |
Fair value of plan assets at beginning of period - | - -
Employer contributions 225 | 423 459
Benefits paid (225) | (423) (459)
-------- | -------- -------
Fair value of plan assets at end of period - | - -
-------- | -------- -------
Funded status (8,560) | (6,806) (6,760)
Unrecognized net actuarial (gain) loss 491 | (88) (88)
Unrecognized net obligation at transition 3,256 | 3,375 3,552
Unrecognized prior service cost 1,062 | - -
-------- | -------- -------
Accrued postretirement benefit liability $(3,751) | $(3,519) $(3,296)
======== | ======== =======
</TABLE>
Major assumptions and net periodic benefit cost include the following
(dollars in thousands):
<TABLE>
<CAPTION>
| October 1, For the Year For the Year
July 15 - | 1998 - Ended Ended
December 31, | July 14, September 30, September 30,
1999 | 1999 1998 1997
------------ | ------------ --------------- --------------
<S> <C> | <C> <C> <C>
Weighted average assumptions- |
Discount rate 7.5% | 6.5% 6.5% 6.5%
Rate of compensation increase 4.2% | 4.0% 4.0% 4.0%
Components of net periodic benefit cost- |
Service cost $100 | $145 $185 $179
Interest cost 239 | 324 479 509
Amortization of net obligation at |
transition 119 | 178 237 235
Recognized net actuarial gain (1) | - (6) -
-------- | -------- ------- ------
Net periodic benefit cost $457 | $647 $895 $923
======== | ======== ======= ======
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement medical benefit obligation as of July 14, 1999, was 9.0%,
decreasing gradually to an ultimate trend rate of 4.5% in 2006. The assumed
health care cost trend rates used in measuring the accumulated postretirement
medical benefit obligation as of December 31, 1999, for pre-Medicare and post-
Medicare benefits were 7.5% and 7.25%, respectively, decreasing gradually to an
ultimate trend rate of 5% in 2006.
F-21
<PAGE>
The assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have had the following effects
(dollars in thousands):
<TABLE>
<CAPTION>
| For the Year
July 15 - | October 1, 1998 - Ended
December 31, 1999 | July 14, 1999 September 30, 1998
------------------- | ------------------- -------------------
|
One Percentage- | One Percentage- One Percentage-
Point Increase | Point Increase Point Increase
------------------- | ------------------- -------------------
<S> <C> | <C> <C>
Effect on total of service and |
interest cost components $ 152 | $ 109 $ 145
Effect on postretirement benefit |
obligation 959 | 1,435 1,293
====== | ====== ======
|
One Percentage- | One Percentage- One Percentage-
Point Decrease | Point Decrease Point Decrease
----------------- | ------------------- ----------------
Effect on total of service and |
interest cost components (61) | $ (84) $ (112)
Effect on post retirement benefit |
obligation (792) | (1,228) (1,114)
========== | ============== ===========
</TABLE>
Effective December 31, 1999, the Company terminated its employee welfare
plans and the Company became a participating employer in the CP&L welfare
benefit plans for which it is eligible. All plan participants as of December
31, 1999, are eligible to participate in the CP&L benefit plans for which they
qualify.
In April 1998, the Company adopted an employee savings plan which qualifies
under Section 401(k) of the Internal Revenue Code. Participating employees were
allowed to defer up to 15% of pretax salary, but not more than statutory limits.
The Company contributed 50 cents for each dollar a participant contributed, with
a maximum contribution of 3% of a participant's earnings. Matching
contributions were $108,000, $214,000 and $109,000, for July 15 - December 31,
1999, period, the October 1, 1998 - July 14, 1999, period and the year ended
September 30, 1998, respectively. Effective December 31, 1999, the Company's
employee savings plan was merged CP&L's Stock Purchase Savings Plan and the
Company became a participating employer in this plan.
9. Stockholders' Investment:
On January 13, 1998, the Company's Board of Directors approved a three-for-
two stock split in the form of a dividend effective February 20, 1998, for
stockholders of record January 26, 1998. All shares outstanding, as well as per
share information for all periods prior to the effective date, have been
adjusted to reflect the stock split. As of July 15, 1999, the Company was
merged into a wholly owned subsidiary of CP&L (see Note 2). As a result of the
merger, the Company' issued 100 new shares of common stock with a par of value
$.10. Subsequent to the merger, there were no changes in the Company's common
stock or capital in excess of par value.
On July 23, 1999, the Company filed Form 15 with the Securities and
Exchange Commission, giving certification and notice of termination of
registration under Section 12(g) of the Securities Exchange Act of 1934.
F-22
<PAGE>
The changes in common stock and capital in excess of par value for the
October 1, 1998 - July 14, 1999, period, and for the two years ended September
30, 1998, were as follows (in thousands):
<TABLE>
<CAPTION> Common Stock
--------------------------------- Capital in
Shares Excess of
Outstanding Amount Par Value
-------------------- --------- ---------------
<S> <C> <C> <C>
Balance at September 30, 1996 6,572 $16,432 $29,635
Issuance through Dividend Reinvestment Plan (DRP) 63 158 1,743
Issuance through Employee Stock Purchase Plan (ESPP) 13 32 263
Issuance through Key Employee Stock Option Plan (KESOP) 19 47 532
------ ------- -------
Balance at September 30, 1997 6,667 16,669 32,173
Issuance through DRP 93 231 2,086
Issuance through ESPP 12 29 274
Issuance through KESOP 3 8 92
Issuance through Stock Dividend 3,350 8,375 -
------ ------- -------
Balance at September 30, 1998 10,125 25,312 34,625
Issuance through DRP 87 219 2,510
Issuance through ESPP 20 49 405
Issuance through KESOP 4 10 111
Balance at July 14, 1999 10,236 $25,590 $37,651
====== ======= =======
</TABLE>
At July 14, 1999, there were 264,905 shares of common stock reserved for
issuance under the Company's Dividend Reinvestment Plan. The Company terminated
this plan effective July 15, 1999.
Prior to the merger with CP&L, the Company sponsored an employee stock
purchase plan, a key employee nonqualified stock option plan, a long-term
incentive plan, a directors deferred compensation stock plan and a directors
deferred retirement compensation stock plan. The Company terminated these plans
effective July 15, 1999.
The stock purchase plan enabled employees to contribute up to 6% of their
compensation toward the purchase of the Company's common stock at 90% of the
lower of current or prior year-end market value. At July 14, 1999, 285,447
shares were reserved for issuance under this plan.
Under the terms of the nonqualified stock option plan, the option price was
equal to 90% of the market value of the stock at the grant date. The period
during which these options were exercisable began five years after, but could
not exceed seven years after, the date of grant. In addition, the plan provided
that an amount equal to 50% of the dividends that would have been paid on the
stock from the date of grant would have been paid in cash to the employee at the
exercise date. In Fiscal 1998, the Board of Directors canceled all shares
available for grant under the key employee nonqualified stock option plan.
F-23
<PAGE>
Option activity for the October 1, 1998 - July 14, 1999, period and the
years ended September 30, 1998 and 1997, was as follows (restated to reflect a
three-for-two stock split in the form of a stock dividend effective February 20,
1998):
<TABLE>
<CAPTION>
Options Option Price Per
Outstanding Share
-------------- -------------------
<S> <C> <C>
Balance at September 30, 1996 36,075 $ 9.20 - $16.65
Exercised (27,900) $ 9.20 - $9.40
------------
Balance at September 30, 1997 8,175 $ 9.40 - $16.65
Exercised (4,275) $ 9.40
------------
Balance at September 30, 1998 3,900 $ 16.65
Exercised (3,900) $ 16.65
------------
Balance at July 14, 1999 -
============
</TABLE>
<TABLE>
<CAPTION>
July 14, September 30,
1999 1998 1997
--------- ---- ------
<S> <C> <C> <C>
Options exercisable at period end - - 2,850
Options available for grant at period end - - 69,475
========= ==== ======
</TABLE>
Under the long-term incentive plan, senior officers of the Company, having
had the opportunity to make a significant contribution to the Company's long-
term performance, were eligible to participate. Awards were made to qualifying
participants in each plan cycle. The plan cycle was typically five plan years,
commencing with the first day of the first fiscal year (October 1, 1996), with
the exception of two special plan cycles which covered the periods of Fiscal
1997 through Fiscal 1999, and Fiscal 1997 through Fiscal 2000. Target awards for
each long-term incentive plan participant were established, stated as a
percentage of the participant's salary, by the Compensation Committee of the
Board of Directors. Those target awards were converted into a target number of
"performance shares" for each participant by dividing the participant's target
award by the average price of one share of common stock for the 12 months
preceding the end of the plan cycle. The maximum number of performance shares
that could be earned by a participant was equal to two times the participant's
target number of performance shares. As of July 14, 1999, no shares had been
issued and 225,000 shares were reserved under this plan.
Under the directors deferred compensation stock plan and a directors
deferred retirement compensation stock plan, current directors accrued stock
units in lieu of annual compensation and retirement compensation which was to be
converted into common stock of the Company upon retirement. At July 14, 1999,
no shares of common stock had been issued and 165,000 shares were reserved under
these plans.
The Company accounted for stock-based compensation plans under Accounting
Principles Board Opinion No. 25. The Company adopted SFAS No. 123 for disclosure
purposes on October 1, 1996. Under SFAS No. 123, the fair value of each option
granted after January 1995 has been estimated as of the date of grant using the
Black-Scholes option pricing model. The application of this model resulted in
no change to earnings per share for the October 1, 1998 - July 14, 1999, period.
F-24
<PAGE>
10. Commitments and Contingencies:
During Fiscal 1991, the North Carolina Department of Environment,
Health and Natural Resources advised the Company of possible environmental
contamination arising from Company-owned property in Kinston, North Carolina,
which is the former site of a manufactured gas plant. The Company retained an
environmental services consulting firm which has evaluated the site. Based on
that firm's investigation and actual expenditures for sites of similar scope and
complexity, the cost for investigation and remediation of this site is estimated
to be between $1.4 million and $2.8 million (see Note 3).
The Company owns another site of a former manufactured gas plant in
New Bern, North Carolina, and was the former owner of three other similar sites
on which no environmental problems have arisen. Management believes that any
appreciable investigation or remediation costs not previously provided for will
be recovered from third parties, including insurance carriers, or in natural gas
rates. Based on the anticipated recovery from these sources, the Company does
not believe that the cost of any evaluation and remediation work will have a
material adverse effect on the Company's consolidated financial position,
results of operations, or cash flows.
The Company is subject to claims and lawsuits arising in the ordinary
course of business. Management does not expect any litigation from such claims
or lawsuits to have a material effect on the Company's consolidated financial
position, results of operations, or cash flows.
11. Related-party Transactions:
The Company pays service fees to its Parent for certain services
provided to the Company. For the July 15, 1999 - December 31, 1999, period, such
fees amounted to $1.4 million.
The Company also has a $150.0 million revolving credit facility with
CP&L (see Note 6), with $135.0 million outstanding at December 31, 1999. For the
period ended December 31, 1999, the Company recognized interest expense of $3.0
million related to this revolving credit facility.
12. Operating Segments:
NCNG adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information," during the fourth quarter of Fiscal 1998.
SFAS No. 131 established standards for reporting information about operating
segments in annual financial statements and requires selected information about
operating segments in interim financial reports issued to stockholders. It also
established standards for related disclosures about products and services and
geographic areas. Operating segments are defined as components of an enterprise
about which separate financial information is available that is evaluated
regularly by the chief operating decision maker, or decision making group, in
deciding how to allocate resources and in assessing performance.
The Company has two segments: (1) a regulated natural gas transmission
and local distribution segment (LDC), and (2) an unregulated segment which
participates in related profit-making ventures. The customers of the regulated
LDC include residential, commercial,
F-25
<PAGE>
industrial, electric generation and wholesale classes. The unregulated segment
consists of natural gas marketing (see Note 5), propane sales and appliance
sales and services. The customers of the natural gas marketing subsidiaries are
in the industrial, wholesale and electric generation classes. The unregulated
propane business delivers and sells propane to residential, commercial and small
industrial customers. The appliance sales and services business sold primarily
to the residential and commercial customer classes. The Company operates in a
single geographic area of south-central and eastern North Carolina.
The segments follow the same accounting policies as described in the
Summary of Significant Accounting Policies and Principles of Consolidation.
Because the Company earns full margins on the transportation of natural gas in
its regulated segment, management evaluates the performance of the unregulated
natural gas marketing subsidiaries (see Note 5) based on the additional margin
added from their sales and their ability to maintain contact with customers who
choose to transport on the regulated LDC's system. The Company evaluates the
performance of the propane business and the appliance sales and service
operations based on each unit's ability to earn a required rate of return on
investment, as determined by the senior executive management team, and their
ability to add regulated natural gas and unregulated propane gas customers
through conversion of electric heat pumps, water heaters and other appliances to
natural gas or propane systems. During 1999, the Company decided to exit the
appliance sales and service business (see Note 2). Operating expenses, taxes
and interest are allocated to the unregulated segment in accordance with NCUC
guidelines.
F-26
<PAGE>
The following table reconciles reportable segment revenues and expenses (in
thousands):
<TABLE>
<CAPTION>
July 15, 1999 - December 31, 1999 | October 1, 1998 - July 14, 1999
--------------------------------- | -------------------------------
Regulated Unregulated Total | Regulated Unregulated Total
--------- ----------- ----- | --------- ----------- ------
<S> <C> <C> <C> | <C> <C> <C>
Revenues $ 98,868 $ 2,636 $101,504 | $139,102 $30,685 $169,787
Cost of gas 67,465 1,433 68,898 | 76,818 25,850 102,668
--------- ---------- ---------- | --------- --------- ---------
Gross margin 31,403 1,203 32,606 | 62,284 4,835 67,119
--------- ---------- ---------- | --------- --------- ---------
Operating expenses 24,437 1,410 25,847 | 40,009 3,025 43,034
Other (income) expense - (730) (730) | - (324) (324)
Interest expense, net 3,225 124 3,349 | 3,371 218 3,589
--------- ---------- ---------- | --------- --------- ---------
Income before taxes 3,741 399 4,140 | 18,904 1,916 20,820
Income taxes 2,662 99 2,761 | 9,432 705 10,137
--------- ---------- ---------- | --------- --------- ---------
Net income $ 1,079 $ 300 $ 1,379 | $ 9,472 $ 1,211 $ 10,683
========= ========== ========== | ========= ========= =========
Property $388,398 $ 8,764 $397,162 | $371,886 $ 8,429 $380,315
Accumulated depreciation 129,214 2,964 132,178 | 123,396 2,860 126,256
--------- ---------- ---------- | --------- --------- ---------
Net property $259,184 $ 5,800 $264,984 | $248,490 $ 5,569 $254,059
========= ========== ========== | ========= ========= =========
Capital expenditures (net) $ 17,267 $ 231 $ 17,498 | $ 32,611 $ 603 $ 33,214
========= ========== ========== | ========= ========= =========
<CAPTION>
Year ended September 30, 1998 Year ended September 30, 1997
----------------------------- -----------------------------
Regulated Unregulated Total Regulated Unregulated Total
--------- ----------- ----- --------- ----------- ------
<S> <C> <C> <C> <C> <C> <C>
Revenues $174,447 $57,468 $231,915 $181,703 $53,831 $235,534
Cost of gas 99,339 51,262 150,601 108,497 47,775 156,272
--------- ---------- ---------- --------- --------- ---------
Gross margin 75,108 6,206 81,314 73,206 6,056 79,262
--------- ---------- ---------- --------- --------- ---------
Operating expenses 45,025 3,901 48,926 43,991 4,229 48,220
Other (income) expense - (134) (134) - (1,961) (1,962)
Interest expense, net 4,795 285 5,080 4,403 283 4,686
--------- ---------- ---------- --------- --------- ---------
Income before taxes 25,288 2,154 27,442 24,812 3,505 28,318
Income taxes 9,388 906 10,294 9,329 1,395 10,724
--------- ---------- ---------- --------- --------- ---------
Net income $ 15,900 $ 1,248 $ 17,148 $ 15,483 $ 2,110 $ 17,594
========= ========== ========== ========= ========= =========
Property $340,320 $ 7,653 $347,973 $307,828 $ 6,744 $314,572
Accumulated depreciation 115,181 2,687 117,868 104,268 2,504 106,772
--------- ---------- ---------- --------- --------- ---------
Net property $225,139 $ 4,966 $230,105 $203,560 $ 4,240 $207,800
========= ========== ========== ========= ========= =========
Capital expenditures (net) $ 32,001 $ 976 $ 32,977 $ 29,201 $ 844 $ 30,045
========= ========== ========== ========= ========= =========
</TABLE>
Other Income/Expense for the 12 months ended September 30, 1997, includes a
one-time pretax credit of $1.9 million related to the recovery of past
exploration and development costs (see Note 3)
F-27
<PAGE>
North Carolina Natural Gas Corporation and Subsidiaries
Consolidated Balance Sheets -- As of March 31, 2000 and December 31, 1999
(in thousands)
<TABLE>
<CAPTION>
March 31, December 31,
Assets 2000 1999
--------------------------------------------------------------------- --------------- ---------------
(unaudited)
<S> <C> <C>
Gas utility plant:
In service $362,259 $354,773
Less - Accumulated depreciation and amortization 132,295 129,214
----------- ----------
229,964 225,559
Construction work-in-progress 31,673 33,625
----------- ----------
261,637 259,184
----------- ----------
Investments:
Nonutility property, less accumulated depreciation (March 31, 2000, 5,804 5,800
$3,034; December 31, 1999, $2,964)
Investment in joint ventures 5,369 5,370
----------- ----------
11,173 11,170
----------- ----------
Current assets:
Cash and temporary cash investments 2,948 1,157
Restricted cash and temporary cash investments 168 168
Accounts receivable, less allowance for doubtful accounts (March 31, 18,698 17,144
2000, $2,529; December 31, 1999, $2,335)
Recoverable purchased gas costs 40 4,431
Inventories, at average cost -
Gas in storage 5,679 9,980
Materials and supplies 5,162 7,072
Merchandise 349 392
Prepaid income taxes 2,072 2,072
Deferred gas cost - Unbilled volumes 4,516 6,094
Prepaid expenses and other 332 513
----------- ----------
39,964 49,023
----------- ----------
Deferred charges and other:
Goodwill 235,265 236,813
Debt discount and expense, being amortized over lives of related debt 4,521 4,719
Prepaid pension cost 1,524 1,309
Other 4,577 5,218
----------- ----------
245,887 248,059
----------- ----------
$558,661 $567,436
=========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-28
<PAGE>
<TABLE>
<CAPTION>
March 31, December 31,
Stockholder's Investment and Liabilities 2000 1999
--------------------------------------------------------------------- --------------- ---------------
(unaudited)
<S> <C> <C>
Capitalization:
Stockholder's investment $375,330 $365,102
-------- --------
Current liabilities:
Notes payable to Parent 110,263 134,983
Accounts payable 17,182 19,243
Customer deposits 2,215 2,139
Restricted supplier refunds 168 168
Accrued interest 433 409
Accrued income and other taxes 9,174 1,378
Other 6,544 7,008
-------- --------
145,979 165,328
-------- --------
Other credits:
Deferred income taxes 26,714 26,488
Regulatory liability related to income taxes, net 1,730 1,782
Unamortized investment tax credits 2,034 2,083
Postretirement and postemployment benefit liability 5,629 5,248
Other 1,245 1,405
-------- --------
37,352 37,006
-------- --------
$558,661 $567,436
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-29
<PAGE>
North Carolina Natural Gas Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
For the Three Months Ended March 31, 2000 and 1999
(in thousands except average common shares outstanding and per share amounts)
<TABLE>
<CAPTION>
2000 | 1999
-----------------------------------
(unaudited)
<S> <C> <C>
Operating Revenues $ 81,956 | $ 69,953
Cost of Sales 51,859 | 39,424
-------- | ---------
Gross Margin 30,097 | 30,529
-------- | ---------
|
Operating expenses |
Operations and Maintenance 6,960 | 7,303
Depreciation and Amortization 4,861 | 3,069
General Taxes 660 | 2,648
-------- | ---------
|
Total Operating Expenses & Taxes 12,481 | 13,020
-------- | ---------
|
Operating Income 17,616 | 17,509
|
|
Other Income 318 | 91
-------- | ---------
Income before Utility Charges 17,934 | 17,600
|
|
Utility Interest Charges, net 1,268 | 1,265
-------- | ---------
|
Net Income Before Income Taxes 16,666 | 16,335
|
Income Taxes 6,438 | 6,040
-------- | -----------
NET INCOME $ 10,228 | $ 10,295
======== | ===========
Average Common Shares Outstanding 100 | 10,165,000
-------- | -----------
Basic and diluted earnings per share $102,280 | $ 1.01
======== | ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-30
<PAGE>
North Carolina Natural Gas Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows(Unaudited)
For the Three Months Ended March 31, 2000 and 1999
(in thousands)
<TABLE>
<CAPTION>
2000 | 1999
---------------- | -------------------
(unaudited)
<S> <C> | <C>
Operating activities |
Net income $ 10,228 | $ 10,295
Adjustments to reconcile net income to cash provided by |
operating activities |
Depreciation and amortization 3,511 | 3,233
Amortization of goodwill 1,548 | -
Deferred income taxes and |
Investment tax credit, net 177 | 194
Change in current assets and liabilities, net 16,817 | 8,244
Other - | (1,605)
-------- | --------
Net Cash Provided by Operating Activities 32,281 | 20,361
-------- | --------
|
Investing Activities |
Gross property additions (9,531) | (11,776)
Proceeds from expansion fund 3,761 | 686
-------- | --------
Net Cash Used in Investing Activities (5,770) | (11,090)
-------- | --------
|
Financing Activities |
Repayments of notes payable (24,720) | (8,000)
Issuance of common stock through dividend reinvestment, |
employee stock purchase and key employee stock option plans - | 1,037
Cash dividends paid - | (2,694)
-------- | --------
Net Cash Used in Financing Activities (24,720) | (9,657)
-------- | --------
Net Increase (Decrease) in Cash and Cash Equivalents 1,791 | (386)
|
Cash and Cash Equivalents at Beginning of the Period 1,157 | 2,938
|
-------- | --------
Cash and Cash Equivalents at End of the Period $ 2,948 | $ 2,552
======== | ========
|
Supplemental Disclosures of Cash Flow Information |
Cash paid during the period: Interest $ 1,541 | $ 1,631
Income taxes - | 4,961
======== | ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-31
<PAGE>
Notes To Unaudited Condensed Consolidated Financial Statements
As of March 31, 2000 and December 31, 1999 and for the
Three Months Ended March 31, 2000 and March 31, 1999
1. Organization And Basis Of Presentation
Organization
North Carolina Natural Gas Corporation (NCNG or the Company), a wholly
owned subsidiary of Carolina Power and Light Company (CP&L or the Parent), is in
the business of providing natural gas, propane gas and related services to
approximately 182,000 customers in south central and eastern North Carolina. The
Company's primary business is the sale and/or transportation of natural gas to
residential, commercial, industrial and electric utility and municipal
customers.
Basis of Presentation
The accompanying condensed consolidated financial statements reflect only
normal recurring adjustments, which are, in the opinion of management, necessary
to fairly present the results for the periods shown. Because of the seasonal
nature of the Company's business, the results of operations for the three-month
period ended March 31, 2000 are not necessarily indicative of the results for
the full year. These financial statements have been prepared by the Company,
without audit, pursuant to the rules and regulations of the Securities and
Exchange Commission. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and
regulations, although the Company believes that the disclosures are adequate to
make the information presented not misleading. It is suggested that these
condensed financial statements be read in conjunction with the Company's
financial statements and the related notes for the period ended December 31,
1999.
The accompanying consolidated financial statements include the accounts of
the Company and its wholly owned subsidiaries, Cape Fear Energy Corporation,
NCNG Energy Corporation, NCNG Pine Needle Investment Corporation and NCNG
Cardinal Pipeline Investment Corporation. All significant intercompany
transactions have been eliminated in consolidation.
The Company was acquired by CP&L pursuant to a merger that closed on July
15, 1999 (see Note 5). The merger was accounted for using the purchase method of
accounting in accordance with generally accepted accounting principles, and the
applicable effects were reflected in the financial statements of the Company as
of the merger date. Accordingly, the post-merger financial statements reflect a
new basis of accounting. The results of operations for the quarters ended March
31 prior to and following the merger (separated by a heavy black line) are
presented.
F-32
<PAGE>
2. Restricted Supplier Refunds
At March 31, 2000, the Company had $168,000 in restricted supplier refunds,
none of which was received in the current quarter. Upon order of the North
Carolina Utilities Commission (NCUC), the Company has invested all of these
funds in U.S. Treasury securities until such time as the NCUC orders the funds
transferred to an Expansion Fund (the Fund). The Fund is administered by the
NCUC pursuant to legislation passed in July 1991, and it encourages the
expansion of natural gas service into unserved areas of the State, including
substantial portions of the Company's franchised service territory. These funds
are available to the Company only upon application to the NCUC for an expansion
project approved by the NCUC. There were no transfers to the Fund in the first
quarter of 2000, and the Company has $7.9 million, including interest, in the
Fund at March 31, 2000.
3. New Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 standardizes the accounting
for derivative instruments, including certain derivative instruments embedded in
other contracts, by requiring that an entity recognize those items as assets or
liabilities in the consolidated statement of financial position and measure them
at fair value. This statement is effective for fiscal years beginning after June
15, 2000, as amended by SFAS No. 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133,"
issued in June 1999. The Company expects to determine any effects of SFAS No.
133 during the third quarter of 2000.
4. Financial Information By Business Segment
NCNG adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," during the fourth quarter of Fiscal 1998. SFAS No. 131
established standards for reporting information about operating segments in
annual financial statements and requires selected information about operating
segments in interim financial reports issued to stockholders. It also
established standards for related disclosures about products and services and
geographic areas. Operating segments are defined as components of an enterprise
about which separate financial information is available that is evaluated
regularly by the chief operating decision maker, or decision making group, in
deciding how to allocate resources and in assessing performance.
The Company has two segments: 1) a regulated natural gas transmission and
local distribution segment (LDC), and 2) an unregulated segment which
participates in related profit-making ventures. The customers of the regulated
LDC include residential, commercial, industrial, electric generation, and
wholesale classes. The unregulated segment has historically consisted of natural
gas marketing, propane sales and appliance sales and services. The customers of
the natural gas marketing subsidiaries were in the industrial, wholesale and
electric generation classes. The unregulated propane business delivers and sells
propane to residential, commercial and small industrial customers. The appliance
sales and services business sold primarily to the residential and commercial
customer classes. The Company operates in a single geographic area of south-
central and eastern North Carolina.
F-33
<PAGE>
Because the Company earns full margins on the transportation of natural
gas in its regulated segment, management evaluated the performance of the
unregulated natural gas marketing subsidiaries based on the additional margin
added from their sales and their ability to maintain contact with customers who
chose to transport on the regulated LDC's system. The Company evaluates the
performance of the propane business and the appliance sales and service
operations based on each unit's ability to earn a required rate of return on
investment, as determined by the senior executive management team, and their
ability to add regulated natural gas and unregulated propane gas customers
through conversion of electric heat pumps, water heaters and other appliances to
natural gas or propane systems. Operating expenses, taxes and interest are
allocated to the unregulated segment in accordance with NCUC guidelines.
Effective July 15, 1999, the Company ceased all marketing activities in
accordance with the terms of the Code of Conduct and Regulatory Conditions
ordered by the NCUC in connection with the merger with CP&L. Also in 1999, the
Company exited the appliance sales and service business.
The following table reconciles reportable segment revenues and expenses
(in thousands):
<TABLE>
<CAPTION>
As of and for the | As of and for the
Three Months Ended | Three Months Ended
March 31, 2000 | March 31, 1999
--------------------------------------- | ---------------------------------------
Regulated Non-Regulated Total | Regulated Non-Regulated Total
---------- -------------- --------- | ------------ ------------- ----------
|
<S> <C> <C> <C> | <C> <C> <C>
Revenues $ 72,120 $9,836 $ 81,956 | $ 56,056 $13,897 $ 69,953
Costs of Sales 43,898 7,961 51,859 | 27,773 11,651 39,424
-------- ------ -------- | -------- ------- --------
|
Gross Margin 28,222 1,875 30,097 | 28,283 2,246 30,529
|
Operating Expenses 11,828 653 12,481 | 12,054 966 13,020
Other (income) expense (264) (54) (318)| (172) 81 (91)
Interest expense, net 1,234 34 1,268 | 1,184 81 1,265
-------- ------ -------- | -------- ------- --------
|
Income before taxes 15,424 1,242 16,666 | 15,217 1,118 16,335
Income taxes 6,087 351 6,438 | 5,608 432 6,040
-------- ------ -------- | -------- ------- --------
|
Net Income $ 9,337 $ 891 $ 10,228 | $ 9,609 $ 686 $ 10,295
======== ====== ======== | ======== ======= ========
|
Property $393,932 $8,838 $402,770 | $361,584 $ 8,246 $369,830
Accumulated Depreciation 132,295 3,034 135,329 | 120,636 2,804 123,440
-------- ------ -------- | -------- ------- --------
|
Net Property $261,637 $5,804 $267,441 | $240,948 $ 5,442 $246,390
======== ====== ======== | ======== ======= ========
Capital expenditures (net) $ 5,706 $ 64 $ 5,770 | $ 10,819 $ 272 $ 11,091
======== ====== ======== | ======== ======= ========
</TABLE>
5. Merger With CP&L
On July 15, 1999, the Company was acquired by CP&L and became a wholly
owned subsidiary of CP&L. CP&L is an investor-owned electric utility that serves
nearly 1.2 million customers in eastern North Carolina, the Asheville area and
the Pee Dee Region of South Carolina. CP&L holds directly all of the issued and
outstanding common shares of the Company. As a result of the merger, the former
common shareholders of NCNG now own common shares of CP&L. The merger was
accounted for as a purchase of the Company's net assets with 8,285,734 shares of
CP&L common stock issued through the conversion of each
F-34
<PAGE>
outstanding NCNG share into .8054 of a share of CP&L common stock (fractional
shares were paid in cash). The purchase price was approximately $364 million,
which included approximately $3.7 million of merger related costs. Goodwill of
approximately $240 million was recorded in connection with the purchase, which
represented the excess of the purchase price over the Company's net assets after
fair value adjustments. Goodwill is to be amortized on a straight-line basis
over 40 years for amounts related to regulated assets and 20 years for amounts
related to nonregulated assets.
F-35
<PAGE>
Unaudited Pro Forma Consolidated Financial Data
The following unaudited pro forma consolidated condensed statement of
operations for the 12-month period ended December 31, 1999 gives effect to the
following transactions: (i) our merger with CP&L as if it had occurred on
January 1, 1999 and (ii) the advance refunding of our outstanding debt using
proceeds of a CP&L credit facility as if the merger had occurred on January 1,
1999 and the subsequent advance refunding had occurred an equivalent length of
time following the pro forma merger effective date.
The pro forma consolidated financial data and accompanying notes should be
read in conjunction with our consolidated financial statements and related notes
thereto. The pro forma adjustments are based upon available information and
certain assumptions that management believes are reasonable and are described in
the notes accompanying the pro forma consolidated financial data. The pro forma
consolidated financial data is presented for informational purposes only and
does not purport to represent what our consolidated results of operations would
actually have been had such transactions in fact occurred at such dates, or to
project our consolidated results of operations for any future period. In the
opinion of management, all adjustments necessary to present fairly such pro
forma consolidated financial data have been made.
F-36
<PAGE>
Unaudited Pro Forma Consolidated Condensed Statement Of Operations
For the Twelve Month Period Ended December 31, 1999
(in thousands)
<TABLE>
<CAPTION>
Advance
July 15 - Merger Refunding Pro Forma
January 1, 1999 - December 31, Pro Forma Pro Forma January 1, 1999 -
July 14, 1999 1999 Adjustments Adjustments December 31, 1999
----------------- ----------------- ----------- ----------------- -----------------
<S> <C> <C> <C> <C> <C>
Operating Revenue............... $119,745 $101,504 $221,249
Cost of sales................... 73,158 68,898 142,056
Gross Margin.................... 46,587 32,606 79,193
Operating expenses
Operations & Maintenance....... 20,120 14,979 35,099
Depreciation................... 6,233 6,572 12,805
Goodwill amortization.......... 2,844 $ 3,358(1) 6,202
General taxes.................. 4,949 1,452 6,401
----------------- ----------------- ----------- ----------------- -----------------
Total operating expenses.... 31,302 25,847 3,358 60,507
Operating Income................ 15,285 6,759 (3,358) 18,686
Other Income.................... 145 730 875
----------------- ----------------- ----------- ----------------- -----------------
Income before interest and 15,430 7,489 (3,358) 19,561
taxes.....................
Utility Interest Charges....... 2,395 3,349 $(334)(2,3) 5,410
Provision for Income
Taxes................. 7,203 2,761 133 (4) 10,097
----------------- ----------------- ----------- ----------------- -----------------
Net Income.................. $ 5,832 $ 1,379 $(3,358) $ 201 $ 4,054
================= ================= =========== ================= =================
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-37
<PAGE>
Notes To Unaudited Pro Forma Consolidated Condensed Statement Of Operations
For the Twelve Month Period Ended December 31, 1999
(1) Represents the amortization of goodwill for the period from January 1, 1999
to July 14, 1999. CP&L recognized approximately $232.0 million in goodwill
on the purchase of regulated assets and approximately $8.0 million in
goodwill on the purchase of nonregulated assets, which has been reflected
in our financial statements. The regulated portion is amortized on a
straight-line basis over a period of 40 years, and the nonregulated portion
is amortized on a straight-line basis over a period of 20 years.
(2) Represents the difference in interest expense between the weighted-average
interest rate (approximately 7.0%) on all outstanding debt prior to the
advance refunding and the interest rate on intercompany debt owed to CP&L
(approximately 5.82%) for 6.5 months. Subsequent to the CP&L merger, we
paid off all of our short-term borrowings plus accrued interest and advance
refunded all of our remaining long-term debt with borrowings from CP&L.
(3) Represents the amortization of approximately $4.9 million of debt
prepayment penalties for 6.5 months incurred by us upon the early
extinguishment of debt. We amortize approximately $4.0 million of the
penalty over the remaining term of the related note of approximately eight
years, and we amortize approximately $970,000 of the penalty over the
remaining term of the related note of approximately 12 years.
(4) Represents the income tax effect of the pro forma adjustments assuming an
approximate statutory rate of 40%.
F-38
