<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended September 30, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ........ to ........
Commission file number 0-82
NORTH CAROLINA NATURAL GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 56-0646235
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
150 Rowan Street, Fayetteville, North Carolina 28301
(Address of principal executive offices)
(Zip Code)
(910) 483-0315
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common stock,par value New York Stock Exchange
$2.50 per share
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) had filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) had
been subject to such filing requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. [ X ]
Estimated aggregate market value of the voting stock held by
nonaffiliates of the registrant at November 25, 1994 $140,859,786
Number of shares of Common Stock outstanding at November 25, 1994 .....
6,366,544
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement dated December 5, 1994 relating to the
January 10, 1995 Annual Meeting of Shareholders, are incorporated by
reference into Part III of this annual report.
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NORTH CAROLINA NATURAL GAS CORPORATION
FORM 10-K
ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED SEPTEMBER 30, 1994
TABLE OF CONTENTS
Item Page
- ---- ----
PART I.
1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Executive Officers of the Registrant. . . . . . . . . . . . . 14
2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . 15
3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . 15
4. Submission of Matters to a Vote of Security Holders. . . . . 15
PART II.
5. Market for Registrant's Common Equity and
Related Stockholder Matters. . . . . . . . . . . . . . . . 16
6. Selected Financial Data. . . . . . . . . . . . . . . . . . . 17
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations. . . . . . . . . . . . 18
8. Financial Statements, Notes and Supplementary Data. . . . . . 24
9. Changes in and Disagreements on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . 43
10. Management's Responsibility for Financial Statements . . . . 44
PART III.
11. Directors and Executive Officers of the Registrant . . . . . 45
12. Executive Compensation . . . . . . . . . . . . . . . . . . . 45
13. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . 45
14. Certain Relationships and Related Transactions . . . . . . . 46
PART IV.
15. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . 47
Report of Independent Public Accountants . . . . . . . . . . 58
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . 59
Index to Exhibits. . . . . . . . . . . . . . . . . . . . . . 60
<PAGE> 3
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
PART I
------
Item 1. Business
General
North Carolina Natural Gas Corporation (Company), whose principal office
is located at 15O Rowan Street, Fayetteville, North Carolina, was
incorporated in 1955 under the laws of the State of Delaware. It is
engaged in the transmission and distribution of natural gas through
approximately 1,006 miles of transmission pipeline and approximately
2,490 miles of distribution mains. Natural gas is sold under regulated
rates to approximately 135,500 customers in 63 cities and towns and
four municipal gas distribution systems in eastern and southcentral
North Carolina.
The Company purchases and transports natural gas under long-term
contracts with Transcontinental Gas Pipe Line Corporation (Transco),
Columbia Gas Transmission Corporation (Columbia) and several major oil
and gas producers. Approximately 75% of NCNG's total available gas
supply in 1994 was purchased under long-term contracts, in the spot
market or with non-pipeline suppliers for system supply. The Company
also serves propane gas to approximately 8,200 customers and sells
gas appliances and home insulation services to gas customers and
new home builders.
NCNG Exploration (NCNGE) was organized in 1974 and another subsidiary,
Cape Fear Energy Corporation (CFEC), was organized in 1980, both under
the laws of the State of North Carolina. These subsidiaries have been
engaged in prior years in the exploration and production of natural gas
and oil. All of NCNG Exploration's operating assets were sold for a
small gain in June 1994. Cape Fear Energy Corporation is now primarily
engaged in the purchase of natural gas for the Company's system supply
and for sale to large industrial plants and the municipalities served
by the Company.
Financial Information About Industry Segments
- ---------------------------------------------
The Company is engaged in principally one industry as described above
and has no other reportable industry segments.
Narrative Description of Business
- ---------------------------------
General -
The Company distributes natural gas to residential, commercial,
industrial and municipal customers in a substantial portion of the
southcentral and eastern sections of North Carolina. The population
in the Company's franchised territory is approximately 1,957,000.
Principal cities or towns served include Albemarle, Dunn, Fayetteville,
Goldsboro, Greenville, Kinston, Lumberton, New Bern, Monroe, Roanoke
Rapids, Rockingham, Rocky Mount, Smithfield/Selma, Southern Pines,
Wilmington and Wilson.
The Company's service area is attractive to industry due largely
to good climate, favorable labor relations, responsible local and
state government, good transportation, and the proximity of this
area to major markets.
<PAGE> 4
Item 1. Business (Continued)
Industrial activities in the service area are diverse. The
Company serves customers engaged in the manufacture of chemicals,
fertilizers, glass, nuclear fuels, textiles, brick, plywood and other
wood products, and in the processing of metals, tobacco, rubber,
dairy and food products. The Company also provides natural gas
service to three large military bases and two electric utilities.
Following is a summary of operating revenues (in 000's) by major
customer classification for the years 1990 through 1994:
1990 1991 1992 1993 1994
---- ---- ---- ---- ----
Residential & Commercial $ 46,099 $ 46,023 $ 47,534 $ 57,163 $ 58,748
Municipalities for Resale 16,653 16,236 21,448 22,312 23,471
Industrial/electric power
generation 65,787 64,342 81,528 93,670 78,118
------- ------- ------- ------- ------
Total Operating Revenues $128,539 $126,601 $150,510 $173,145 $160,337
======= ======= ======= ======= =======
The above amounts include revenues from both gas sold to customers and
for transportation of customer-owned gas. The Company's revenues from
transportation are lower than from sales because it does not incur or
bill the commodity cost of gas for transported volumes. However, the
Company generally earns the same margin on a dekatherm of gas whether
transported or sold because transportation rates exclude only the
commodity cost of gas which the customer pays directly to his supplier.
Operating revenues decreased to $126.6 million in 1991 from $128.5
million in 1990 due to a combination of factors, primarily winter
weather that was 24% warmer than normal and 7% warmer than 1990,
transportation which replaced sales and a continuing decline in the
cost of purchased gas which was passed on to the Company's customers.
The warmer than normal winter period weather had a significant impact
on the sale and transportation of gas for 1991. Sales volumes declined
1,145,000 Dt in 1991, while transportation volumes increased 2,425,000
Dt. The switch from sales to transportation volumes resulted in an
approximate revenue reduction of $4.5 million in 1991, but did not
impact the Company's margin.
Operating revenues increased to $150.5 million in 1992 from $126.6
million in 1991 due to a combination of factors, primarily the shift
of 8,165,000 Dt from transportation to sales, the increase in total
throughput and the impact of the December 1991 general rate increase
(see "Regulations and rates", Page 8). Those increases were partially
offset by a decline in the unit cost of purchased gas passed along to
all customers. The shift from transportation to sales resulted in a
revenue increase of $15.5 million in 1992, but did not impact the
Company's margin.
Operating revenues increased to $173.1 million in 1993 from $150.5
million in 1992 due to a combination of factors, primarily the
increase in the customer base and total throughput, and increased
gas costs passed on to customers and a full year's impact of the
general rate increase.
<PAGE> 5
Item 1. Business (Continued)
- ----------------------------
Operating revenues declined to $160.3 million in 1994 from $173.1
million in 1993 due to a combination of factors, primarily lower
gas costs passed on to customers and the shift to more transportation
service and less sales to large customers in 1994 compared to 1993.
The strong customer growth and slight increase in net throughput
volumes increased revenues but only partially offset these factors
causing revenues to decline.
Natural gas supply -
During 1994, the Company received 4,681,000 Dt of natural gas under
its firm sales contract with Transco. It purchased 30,224,000 Dt
in the spot market or from other non-traditional sources, including
long-term contracts with seven major producers. The Company also
transported 13,400,000 Dt of customer-owned gas in 1994. The
outlook for natural gas supplies in the Company's service area
remains favorable as both Transco and Columbia are "open access"
pipelines, and the Company has many sources of gas, available on a
firm basis. Nationally, gas supplies are plentiful and no supply
curtailments are anticipated, although pipeline capacity is expected
to be tight if winter weather is colder than normal. Effective
November 1, 1993, both Transco and Columbia implemented FERC Order 636.
The Company has not experienced any changes in its daily operations
because of implementation.
See Pages 9 and 10 of this report for additional information regarding
federal regulation of interstate pipelines.
<PAGE> 6
Item 1. Business (Continued)
- -----------------------------
The following table summarizes the supply sources which are under
contract or otherwise available to the Company as of November 1, 1994:
Daily Maximum Contract
Deliver- Annual Expiration
ability (a) Quantity (a) Date
------- -------- ----------
(Dt) (Dt)
Transco -
Firm Transportation (FT) 145,935(b) 53,266,275 2013
Firm Sales (FS) 55,935 20,416,275 2001
General Storage 2,070 103,500 2013(c)
Washington Storage 32,154(d) 2,734,180 1998
Liquefied Gas Storage 5,320 26,600 1991(h)
Southern Expansion (FT) 16,871(e) 3,070,522 2005
Eminence Storage 34,123(i) 240,268 2013
Columbia Gas Transmission (F) -
Firm Transportation (FT) 19,801(b) 7,227,365 2004
Firm Storage Service (FSS) 5,199 223,238 2004
Amerada Hess
Firm Sales 15,000(g) 2,488,500 2003
Enron Gas Marketing
Firm Sales 15,500(g) 2,340,500 1998
Exxon Company, U.S.A. -
Firm Sales 14,903(g) 5,439,595 2003
Mobil Natural Gas, Inc.
Firm Sales 24,903(g) 9,089,595 1998
Natural Gas Clearinghouse -
Firm Sales 9,995(g) 1,509,245 1997
Texaco
Firm Sales 5,000(g) 1,825,000 1996
Texaco
Firm Sales 12,500(g) 2,957,500 1997
Union Pacific
Firm Sales 9,400(g) 2,489,000 1996
BP Gas 9,715(g) 3,545,975 1998
Vastar (Arco) 10,000(g) 1,510,000 1998
LNG Plant (Company owned) 70,000(j) 1,000,000 N/A
(a) Quantities are shown in dekatherms (Dt) (one Dt equals 1,000,000 Btu
or one Mcf at 1000 Btu/cu. ft.) and are based on current heating
values used by Transco and the Company.
<PAGE> 7
Item 1. Business (Continued)
- -----------------------------
(b) Firm Transportation (FT) contracts are for pipeline capacity only.
The Company is responsible for acquiring its own gas supplies to be
transported on a firm basis under the FT contracts. Gas supplies are
available under Transco's FS Agreement, other long-term agreements
(see (g) below), multi-month term agreements or one-month agreements
for supplies purchased in the spot market.
(c) The Company has entered into a new contract with Transco which
expires on March 31, 2013 for 56,267 dekatherms of General Storage
Service provided under Transco's agreements with Consolidated
Natural Gas Transmission Corporation (CNG). The Company anticipates
that Transco will continue to provide the balance of the Company's
service entitlement under its Rate Schedule GSS tariff pending new
agreements between Transco and other storage operators utilized by
Transco to provide General Storage Service.
(d) Washington Storage volumes may be withdrawn to the extent that the
basic contract gas from Transco or other suppliers is unavailable on
any day or if the Company elects to take such gas instead of other
supplies.
(e) Winter months only (October through March).
(f) In December 1989, the Company became the first natural gas distribution
company in North Carolina to have a hard-pipe connection with two
interstate pipelines as it began receiving gas from Columbia at
Pleasant Hill, North Carolina, a delivery point near the North
Carolina/Virginia border.
(g) The Amerada Hess, Enron, Exxon, Mobil, Natural Gas Clearinghouse,
Texaco, BP, Vastar (Arco) and Union Pacific contracts are for gas
supply only - no pipeline capacity is included. Supplies purchased
from these suppliers flow on the Company's FT contracts with Transco
and Columbia (see (b) above).
(h) The primary term of the Company's contract with Transco for LGA
storage service expired on October 31, 1991. The Company anticipates
that Transco will continue to provide this service under its Rate
Schedule LGA tariff.
(i) Transco salt dome storage capacity allocated to customers of Transco
FS sales service by mandate of FERC Order 636. Transco will continue
to schedule injections and withdrawals of gas from this storage
capacity under agency agreements with the Company and the other FS
sales service customers.
(j) The deliverability away from the LNG Plant is limited by the Company's
pipeline capacity. The Company is currently on a four-year plan to
increase the capacity which will ultimately increase the LNG output
to 120,000 Mcf/day.
<PAGE> 8
Item 1. Business (Continued)
- -----------------------------
As part of the Company's plan to diversify its supply sources, NCNG
has converted 100% of its original Transco sales contract to firm
transportation (FT), thus giving the Company an FT contract of
145,935 Dt per day on Transco. Also, the Company has approximately
17,000 Dt per day of additional winter season FT capacity from
Transco's Southern Expansion. The Company has also converted 100%
of its original Columbia sales contract to a combination of firm
transportation and firm storage service under Columbia's November
1, 1993 service restructuring mandated by the Federal Energy
Regulatory Commission's Order 636. The FT contracts enable the
Company 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 the Company's 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 the Company works with each pipeline and the
customers to arrange transportation service for them when possible.
End-user transportation volumes increased 42% in 1994 from 1993 due
primarily to favorable spot market gas prices available to those
customers during the summer period (April - October) and the
continuation of a temporary increment in the Company's natural gas
sales rates, but not its transportation rates, to recover base
period margin losses under the Industrial Sales Tracker (IST)
ratemaking mechanism. The Company's primary objectives are to
secure adequate and reliable gas supplies on reasonable terms and
conditions consistent with its obligation to provide service to its
customers at the lowest reasonable cost. Spot market purchases will
continue to be utilized primarily in the off-peak months (generally
March through November) when such transactions offer economic savings
compared to other firm purchase options.
As of November 1, 1994, the Company had entered into long-term gas
supply contracts with major producers or national natural gas marketers
for firm supplies in the winter season totaling 126,916 Dt/day on
Transco and Columbia. Additionally, the Company has a firm sales
contract with Transco to provide gas supplies of 55,935 Dt/day which
the Company uses as its primary "swing" supply to accommodate changes
in the level of demand on its system. The Company renegotiated its
long-term contract with Mobil Natural Gas, Inc. to extend the primary
term of that contract two years, to October 31, 1998.
The Company has a liquefied natural gas (LNG) storage plant which
provides 70,000 dekatherms per day to the Company's peak day delivery
capability.
Franchises -
The Company holds a certificate of public convenience and necessity
granted by the North Carolina Utilities Commission (NCUC) to provide
service to the area now being served. Under North Carolina law, no
company may construct or operate properties for the sale or distribution
of natural gas without having obtained 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.
<PAGE> 9
Item 1. Business (Continued)
- ----------------------------
The Company has nonexclusive franchises from 48 municipalities in which
it distributes natural gas and four municipalities to which the Company
sells or transports gas for resale. The expiration dates of those
franchises which have specific expiration provisions are from 1999 to
2011. The franchises are substantially uniform in nature. They contain
no restrictions of a materially burdensome nature and are adequate for
the Company's business as presently and as now proposed to be conducted.
The Company, in addition, serves 15 communities from which no franchises
are required.
Seasonal nature of business -
The Company's business is seasonal in nature. Cold weather affects
customer demand in high priority markets and generally results in
greater earnings during the winter months. However, the Company's
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. In 1991, however, the seasonal fluctuation in
earnings became more pronounced due to the increase in pipeline fixed
charges. In the Company's December 1991 general rate order, seasonal
rates were adopted, having the effect of increasing winter period
margins and reducing summer period margins compared to the rates
previously in effect, further increasing the seasonal variation in
revenues and earnings.
The Company normally injects gas into storage during periods of warm
weather and withdraws it during periods of cold weather. The storage
and various other contracts as shown on Pages 4 and 5 provide
adequate daily supply to meet the Company's peak day requirements.
Short-term debt is used for the seasonal financing of stored gas
inventories and for the Company's ongoing construction program prior
to obtaining long-term financing. These loans, either conventional
notes or bankers' acceptances, are normally repaid from the funds
generated by the winter sale of the stored gas. At September 30,
1994, $26.0 million in short-term debt was outstanding compared to
$15.5 million at September 30, 1993. The increase was due primarily
to increased construction expenditures in Fiscal 1994.
<PAGE> 10
Item 1. Business (Continued)
- ----------------------------
Exploration and development -
NCNGE was formed in 1974 when the North Carolina Utilities Commission
approved and authorized customer participation in four exploration
and development programs. Effective June 7, 1994, the Company and
the other three natural gas distribution utilities in North Carolina
sold their combined interests in all of the exploration and development
programs in which NCNGE was involved. NCNGE's share of the net
proceeds was $615,000, of which $144,500 was deposited in an escrow
account to remain until December 31, 1995 to cover any potential
claims presented by the buyers. NCNGE recognized a pretax gain of
$58,000 (shareholders' portion) on the sale, excluding the amount held
in escrow. Approximately 75% of the net proceeds from the sale, along
with net revenues and expenses of the programs prior to the sale, will
be considered in the final amounts due to or from customers under
these programs.
CFEC was formed in fiscal 1980 to make investments without customer
participation in future exploration and drilling programs. CFEC has
no material remaining commitments but will make some minor additional
investment for development of successful prospects. In 1994, Cape
Fear sold 2.2 million Dt of natural gas to NCNG customers and earned
a profit margin of $43,000 on such sales.
Regulations and rates -
The Company is subject to regulation by the North Carolina Utilities
Commission (NCUC) as to rates, service area, adequacy of service,
safety standards, acquisition, extension and abandonment of facilities,
accounting and issuance of securities. The Company operates only in
the State of North Carolina and is not subject to Federal regulation as
a "natural gas company" under the Natural Gas Act.
The NCUC authorized a general rate increase for the Company effective
December 6, 1991 providing $2.6 million in additional revenues, a 12.7%
return on common equity, and approved the establishment of demand/
commodity rates for six large, firm service customers; seasonal rate
differentials for all customer classes; increases in facilities charges
and reconnection fees for residential and commercial customers; and the
establishment of a Weather Normalization Adjustment (WNA) Rider.
The Weather Normalization Adjustment benefits both the Company and its
space heating customers by reducing large swings in customers' bills and
Company revenues due to fluctuations in winter weather. This WNA Rider
increases margins to the Company on its temperature sensitive load
during warmer than normal winter weather and decreases the margin during
colder than normal weather. During 1994, the WNA Rider provided
$462,000 in revenues to offset lower volume gas sales to temperature
sensitive customers due to 3% warmer than normal weather.
<PAGE> 11
Item 1. Business (Continued)
- -----------------------------
The Company's rate tariff contains an Industrial Sales Tracker (IST)
Rider. The purpose of the IST is to stabilize the Company's margin
(difference between revenues and purchased gas cost) earned from sales
or transportation to interruptible industrial customers who use heavy
fuel oil as an alternative fuel. To the extent that actual margins
realized from sales or transportation to such customers exceed, or are
less than, the margins included in the Company's most recent general rate
case for IST volumes, refunds payable or additional receivables are
recorded. The actual margins earned from IST deliveries were less than
the base period margin by $3,940,000 and $5,166,000 in 1994 and 1993,
respectively.
The NCUC, in a general rulemaking proceeding, revised its Purchased Gas
Adjustment (PGA) procedures in April 1992. The revised procedures
continue to allow the Company to recover all of its prudently incurred
gas costs, but such procedures provide for several significant changes
which include: (1) the establishment of a benchmark commodity cost of
gas which represents the Company's estimate of the actual commodity cost
of gas from all suppliers that it will incur in a future period; (2) 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; (3) the notice period for requesting PGA rate
changes was reduced to 14 days from 30 days; (4) the establishment of a
tariff provision which allows the Company to recover margin losses from
negotiated rates to non-IST large commercial and industrial customers;
(5) a true-up of fixed gas costs recovered from the Company's customers;
(6) a true-up of the Company's lost, unaccounted for and Company use
volume compared to such volumes included in the last general rate case;
and (7) an annual review of the Company's gas costs, including the
prudence thereof, by the Public Staff of the NCUC and a hearing before
the NCUC. The Company's second annual review of its gas costs for the
12 months ended November 30, 1993 was held in April 1994. The NCUC
found the Company's gas costs and gas purchasing practices to be prudent,
as it had for the first annual review in 1993.
In August 1994, the Company filed with the NCUC its second annual true-up
of lost, unaccounted for and company use volumes for 12 months ended
June 30, 1994. Because such volumes exceeded the base period amounts
included in the last general rate case, the Company recouped $1,292,000
in 1994 from the true-up by charging that amount to the deferred gas cost
account for future recovery in rates from customers.
The Federal Energy Regulatory Commission (FERC) issued its landmark Order
636 in April 1992. Essentially, Order 636 introduces more competition
into the natural gas industry as pipelines must "unbundle" their merchant
services from their transportation services. The Company's major
pipeline supplier, Transco, largely completed the unbundling of its
services in 1991, and NCNG has been purchasing its gas supplies directly
from producers and marketers operating on the Transco system for a
number of years. The Company's other pipeline supplier, Columbia Gas
Transmission, has offered a bundled sales/transportation service to the
Company since 1989, but it has implemented Order 636 effective November 1,
1993, as has Transco.
<PAGE> 12
Item 1. Business (Continued)
- -----------------------------
Another significant aspect of Order 636 is capacity release and
assignment. To manage its supply portfolio most effectively and also
to permit its large customers and independent marketers selling gas to
end users on the NCNG system to obtain access to firm capacity on
Transco, the Company entered into several agreements which permit
end-use customers or marketers access to the Company's firm
transportation on Transco while paying NCNG a fee for the use of its
capacity. While Order 636 transfers the risk of gas supply management
from the pipeline to the local distribution company such as NCNG, the
Company has been working in such an environment for several years, and
has carefully planned for the full implementation of Order 636. In
July 1994, the NCUC issued a rulemaking order in which it required that
all natural gas utilities flow through to customers 90% of the net
compensation received for capacity release and similar transactions
while retaining 10% of such compensation. The Company had been
accounting for such transactions in accordance with the 90/10 sharing
mechanism pursuant to a previous Commission Order issued in 1993.
Competition -
With the exception of four municipalities that operate municipal gas
distribution systems within the Company's service territory, the
Company is the sole distributor of natural gas in its franchise
service territory. Natural gas competes with electricity, residual
fuel oil, propane and, to a lesser extent, coal. The Company has
the lowest residential rates in North Carolina and is in a favorable
competitive position. However, competition for every customer or
potential customer is becoming more intense throughout the energy
industry. The electric utilities in North Carolina have become more
active in promoting high-efficiency heat pumps to counter the growth
of natural gas in the home space-heating market. Such competition
intensified to the point during 1994 that the NCUC established a
separate docket to investigate competition between electric and
natural gas utilities. The Commission required all companies to
file testimony on competitive issues and scheduled a hearing to be
held on December 6, 1994.
During 1994, approximately 65% of total throughput on the Company's
system was to customers having alternative fuel usage capabilities
under interruptible rates. However, the Company's tariffs
(Industrial Sales Tracker ("IST") for heavy fuel oil customers and
PGA Rider B for others) allow it to negotiate rates lower than the
filed tariff rates and recover the lost margin from core market
customers to keep industrial customers from leaving the system when
the price of their alternative fuel is lower than the gas tariff rate.
In exchange for the Company's having the right to recover negotiated
losses, the IST requires that when margin is earned from the delivery
of volumes to IST customers in excess of a base level set in the
Company's last general rate case, that margin must be returned to the
core market customers. That is not the case for additional margin
earned from sales or transportation to non-IST industrial customers.
Although the Company has benefitted from the favorable spread between
both the price of delivered No. 2 fuel oil and propane compared to
natural gas and has remained competitive in many 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. The
Company's sales or transportation to IST customers were up 290,000 Dt
in fiscal 1994 due to lower wellhead gas prices during the summer period.
<PAGE> 13
Item 1. Business (Continued)
- -----------------------------
Sales to higher margin non-IST industrial customers and electric
generation facilities having No. 2 fuel oil, propane or no alternative
fuels increased by a net amount of 417,817 Dt due to customer growth
and lessened price competition from No. 2 oil. However, deliveries for
electric power generation were adversely affected by other factors
described below.
The Company's largest electric power generation customer is the Public
Works Commission of the City of Fayetteville (PWC). For several years
PWC had been considering the feasibility of eliminating entirely its
purchases of bulk power from Carolina Power & Light Company (CP&L),
its primary supplier of electric power, and instead relying on its
existing generating plant, which is served by NCNG, and to consider
entering into an agreement with a private contractor who would construct
an additional gas-fired or coal-fired power plant for PWC's base-load
requirements. In February 1994, PWC elected to accept a competitive
proposal from CP&L because, in PWC's opinion, the CP&L proposal would
be a lower cost option with more electric power supply security.
Accordingly, CP&L and PWC entered into an agreement in May 1994 which
provides, among other things, that CP&L would lower its rates charged
to PWC and, in exchange for that, CP&L would assume control of the
dispatch of PWC's existing power plant. This agreement, along with
much milder weather during the summer of 1994, resulted in a significant
reduction in the dispatch of PWC's power plant with a negative impact on
the Company from a reduction in gas load of 1,729,000 Dts, or 61% less
gas delivered to the plant than in 1993.
Environmental matters -
The Company is subject to regulation with regard to environmental
matters by various Federal, state and local authorities. During fiscal
year 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 estimated the costs of investigation and remediation of this site
based on its work to date to be between $1.4 million and $2.8 million
over a four-to-six- year period. The Company owns another site of a
former manufactured gas plant site in New Bern, North Carolina, and
was the former owner of three other similar sites on which no
significant environmental problems have arisen. The Company believes
that any appreciable costs not previously provided for will be
recovered from third parties, including liability insurance carriers,
or in natural gas rates. In 1992, the Company received from third
parties $457,000 relating to the Kinston site; an additional $24,000
and $28,000 was received in 1994 and 1993, respectively, and no
significant additional costs were incurred.
The passage by Congress of The Clean Air Act of 1990 is generally
beneficial to the natural gas industry because of the clean-burning
characteristics of natural gas compared to oil and coal. Also, the
Energy Policy Act of 1992 is generally beneficial to the natural gas
industry because of provisions regarding alternative fuels for vehicles,
taxation, and reform of the Public Utility Holding Company Act to allow
a new class of electricity producers known as "Exempt Wholesale
Generators".
<PAGE> 14
Item 1. Business (Continued)
- -----------------------------
Other -
Effective October 1, 1993, the Company adopted FASB Statement No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions,"
on a prospective basis. This statement requires accounting for these
benefits on an accrual basis using a single actuarial method which
spreads the expected cost of such benefits to each year of an employee's
service until the employee becomes fully eligible to receive the
benefits. Prior to October 1, 1993, the Company accounted for these
benefits on a cash basis consistent with current ratemaking treatment.
The costs of such benefits charged to expense amounted to $501,000 in
1993 and $568,000 in 1992. The NCUC, in rate cases where Statement No.
106 accounting has been presented, has expressed its preference for the
accrual basis of accounting and, accordingly, the Company expects that
the regulatory treatment of these costs under Statement No. 106 in the
Company's next general rate case will be the same prospectively as the
accrual method that has been adopted. The Company is not currently
funding this plan.
Effectively October 1, 1993, the Company adopted FASB Statement No. 109,
"Accounting for Income Taxes". The adoption of Statement No. 109
resulted in cumulative adjustments to the balance sheet and had no
effect on consolidated net income. As a result of Statement No. 109,
the Company reduced accumulated deferred income taxes and recorded
related regulatory assets and liabilities. The regulatory liability
related to income taxes, net is due primarily to deferred income taxes
recognized in years prior to 1987 at rates higher than currently enacted.
NCNG's service area of southcentral and eastern North Carolina is
economically underdeveloped in many ways, including availability of
natural gas service. The extension of natural gas service to currently
unserved areas of North Carolina is a high priority with the Company
and many state officials. NCNG is very interested in extending its
pipeline system into other parts of its service territory where
economically feasible to help promote economic development and
provide future growth opportunities for the Company. Construction is
currently underway on a 13-mile extension of the Company's system into
a portion of Wayne County that does not have natural gas service.
NCNG expects to begin construction soon on a 16-mile transmission
pipeline to extend service to the southwest portion of Columbus County.
This project will be financed through a cooperative effort between
Columbus County and NCNG.
Natural gas expansion funds were authorized for use by the North
Carolina natural gas companies through legislation passed in 1991 by
the North Carolina General Assembly, and an expansion fund for NCNG
was approved by the North Carolina Utilities Commission in February
1993. However, use of these funds was delayed by appeal of the
Commission's decision to the courts by parties representing some of
the Company's industrial and municipal customers. In July of this
year, the North Carolina Supreme Court issued a decision which affirmed
<PAGE> 15
Item 1. Business (Continued)
- -----------------------------
the Commission's Order. There are approximately $13.5 million in gas
supplier refunds currently available for possible inclusion in the
Company's natural gas expansion fund. The Company will soon file for
Commission approval to use money from this fund, together with Company
funds, to make economically feasible the extension of NCNG's pipeline
system into one or more other unserved areas of eastern North Carolina.
Employees -
At September 30, 1994, the Company had 536 full time employees.
Employee relations are good and the Company has not had any material
work stoppage due to labor disagreements. The Company has a
noncontributory Employee Retirement Plan for substantially all regular
employees, provides a group life and extended hospital insurance
program, and other employee benefits, including an employee stock
purchase plan which became effective in mid-1990. Shares were
purchased by employees in 1994, 1993, 1992 and 1991.
EXECUTIVE OFFICERS OF THE COMPANY
Date
Elected
Name and Age* Title An Officer
- ----------------------- ----------------------- ----------
Calvin B. Wells Chairman, President and O9/11/74
Age - 58 Chief Executive Officer
Gerald A. Teele Senior Vice President and O1/O8/8O
Age - 50 Chief Financial Officer
James C. Buie Vice President - 01/13/87
Age 47 Computer Services
Terrence D. Davis Vice President - Operations 01/07/91
Age - 49 and Industrial Sales
Cecil C. Dew Vice President and Treasurer O1/13/7O
Age - 64
Stuart B. Dixon Vice President 01/10/89
Age 57 Government Relations
Louis L. Hanemann Vice President - Human Resources 01/10/89
Age - 46
E. J. Mercier, Jr. Vice President - O9/O7/77
Age - 56 Customer Service
* As of December 3, 1994
The executive officers of the Company are appointed annually by the
Board of Directors immediately following the annual meeting of
stockholders. The present term of all executive officers expires
on January 10, l995, the date of the next annual meeting of stockholders.
All of the executive officers have been employed by the Company in the
position indicated or other similar managerial positions for more than
five years except for Terrence D. Davis who was employed on January 7,
1991 as Vice President. He has over 20 years experience in the
natural gas industry. Prior to joining the Company, he was Vice
President of Operations at Chesapeake Utilities Corporation in Delaware.
There is no family relationship between any of the executive officers
or directors.
There have been no events under any bankruptcy act, no criminal
proceedings and no judgments or injunctions material to the evaluation
of the ability and integrity of any executive officer during the past
five years.
<PAGE> 16
Item 2. Properties
- -------------------
The Company owns approximately 1,006 miles of transmission pipelines of
two to 16 inches in diameter which connect its 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 the
Company at various points conveniently located with respect to the
Company's distribution area. Columbia delivers gas to one delivery
point near the North Carolina-Virginia border. Gas is distributed by
the Company through 2,490 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 others.
During Fiscal 1994, the Company invested approximately $20.8 million in
new plant facilities. Approximately 8,000 natural gas and 500 propane
residential and small commercial customers were added along with several
new industrial customers. In Fiscal 1986, the Company completed and
placed in service a liquefied natural gas storage plant on its system to
provide additional peak day gas supply for future growth in customer
demand. The LNG plant enabled the Company to establish an all-time high
peak-day sendout of 249,260 dekatherms on January 19, 1994.
As discussed elsewhere in this report, NCNG Exploration Corporation and
Cape Fear Energy Corporation participated in several oil and gas
exploration and development programs for several years. The Company's
interest in these oil and gas programs is not material to the Company's
overall operations, and all of the NCNGE properties have been sold.
Item 3. Legal Proceedings
- --------------------------
None, other than those related to issues before the North Carolina
Utilities Commission and the North Carolina Department of Environment,
Health and Natural Resources discussed above and in Note 10 to the
Company's Consolidated Financial Statements for the year ended
September 30, 1994, and other routine litigation incidental to the
Company's business.
Item 4. Submission
- --------------------
No matters were submitted to a vote of NCNG's security holders during
the three months ended September 30, 1994.
<PAGE> 17
PART II
-------
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters
-----------------------------------------
Principal market - The Company's common stock is traded on the New York
Stock Exchange.
Approximate number of holders of common stock - The number of holders
of record of the Company's common stock as of September 30, 1994: 5,250
Stock price and dividend information -
The table below presents the reported high and low common stock sale
prices along with cash dividends declared per share for each quarter of
fiscal 1994 and 1993.
Sept.30 Jun.30 Mar.31 Dec.31 Sept.30 Jun.30 Mar.31 Dec.31
Quarter Ended 1994 1994 1994 1993 1993 1993 1993 1992
COMMON STOCK PRICES-
High ............. $24.00 $25.13 $27.38 $29.13 $29.38 $28.63 $26.75 $24.38
Low ................ 22.00 22.63 24.25 24.86 26.63 26.13 21.88 21.00
Cash dividends
per share ........ .29 .29 .29 .27 .27 .27 .27 .25
A quarterly dividend of $0.29 per share was declared by the Board of Directors
payable on December 15, 1994 to holders of record on December 1, 1994. Cash
dividends have been paid on common shares every year since 1969 and the
annual dividend rate has been increased each year since 1978. Under terms
of the Company's debt agreements, there are various provisions relating to
the maintenance of certain financial ratios and conditions. At September
30, 1994, approximately $17,838,000 of the Company's retained earnings is
unrestricted.
<PAGE> 18
Item 6. Selected Financial Data
- --------------------------------
Years Ended September 30
1994 1993 1992 1991 1990
-----------------------------------------------
. (Amounts in Thousands Except Per Share Data)
Operating revenues...........$160,337 $173,145 $150,510 $126,601 $128,539
Gross margin.................. 55,097 54,045 50,162 42,234 40,026
Net income.................... 11,150 10,977 9,697 7,014 7,441
Earnings per share (1)......... 1.76 1.84 1.79 1.31 1.04
Cash dividends declared
per share (1)............... 1.14 1.06 .983 .923 .87
Total assets................ 205,173 194,178 186,550 151,714 138,472
Net utility plant in
service .................. 164,843 152,543 144,412 127,205 111,644
Capital expenditures........ 20,756 15,469 23,773 21,200 16,483
Long-term debt.............. 37,000 39,000 45,088 23,452 27,741
Common equity .............. 86,399 80,944 57,413 51,967 49,106
Book value per share....... $ 13.57 $ 12.85 $ 10.54 $ 9.65 $ 9.20
Average number of common
shares outstanding...... 6,331 5,981 5,414 5,362 5,311
Rate of return on year-end
common equity.......... 12.91% 13.56% 16.89% 13.50% 15.15%
(1) Prior period amounts have been restated to reflect a 3-for-2 common stock
split effective October 30, 1992.
<PAGE> 19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
- -----------------------------------------------------------
GENERAL
North Carolina Natural Gas Corporation is engaged primarily in the
business of transporting and distributing natural gas at regulated
rates to customers in 63 cities, towns and communities in southcentral
and eastern North Carolina, with approximately 135,500 natural gas
customers as of September 30, 1994. The Company also has a propane
division with 8,200 customers. NCNG continues to expand its
transmission and distribution systems to keep pace with the economic
development and residential, commercial and industrial growth in
its service area. The Company's financial condition and results
of operations are substantially dependent upon its receiving adequate
and timely increases in rates, which are regulated by the North Carolina
Utilities Commission (NCUC).
LIQUIDITY AND CAPITAL RESOURCES
The Company has bank lines of credit for a total amount of $35.5 million
including amounts based upon the cost of gas in storage. Borrowings
under the lines can include bankers' acceptances and promissory notes
not to exceed 90 days, with a maximum rate of the lending bank's
commercial prime interest rate. At September 30, 1994, $26.0 million
was outstanding at interest rates ranging from 5.065% to 5.35% and $9.5
million was available under these arrangements. At September 30, 1993,
borrowings of $15.5 million were outstanding.
North Carolina Natural uses short-term bank loans temporarily, along
with net cash provided from operating activities, to finance construction
expenditures, and it replaces the bank loans with permanent financing
when total borrowings approach the maximum amount provided under the
lines of credit. Construction expenditures for 1994 were $20.8 million,
an increase of $5.3 million from 1993 primarily because of construction
in 1994 to expand the vaporization of the LNG plant and to strengthen
two pipeline laterals. The Company has budgeted construction
expenditures of $25.3 million for 1995. The construction program
includes $3.0 million for an expansion project into an unserved area
and $2.3 million to loop a section of the pipeline between NCNG's LNG
plant and Fayetteville.
The Company's ratio of long-term debt to total capitalization was 31%
at September 30, 1994, down from 36% at September 30, 1993, due to
sinking fund payments of $6,088,000 made on debt issues and growth in
common equity from retained earnings and proceeds from the sale of stock
in the Company's dividend reinvestment and employee stock purchase plans.
The Company did not issue any new long-term debt in 1994 but may seek
long-term debt financing during Fiscal 1995 or early in Fiscal 1996.
RESULTS OF OPERATIONS
NCNG earned $11.1 million or $1.76 per share in 1994, compared to $11.0
million or $1.84 per share in 1993 and $9.7 million or $1.79 per share
in 1992. The slight increase in earnings in 1994 was due to increased
earnings in the Company's nonutility division, including its
subsidiaries, and lower utility interest charges, which offset a
decline in operating income. Reduction of throughput volumes in the
electric power generation market caused 1994 operating income and net
income to decline $472,000, or $.07 per share.
<PAGE> 20
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations (Continued)
--------------------------------------------------------
The increase in earnings in 1993 was primarily due to (1) increased
margin resulting from increased sales and transportation (throughput)
volumes to all customer classes due to customer growth and weather
that was 6% colder than the prior year, and (2) lower interest expenses.
Earnings per share in both 1994 and 1993 were diluted by the effect of
the 786,500 additional shares issued in a public offering in February
1993. The increase in earnings in 1992 was primarily due to the general
rate increase that became effective in December 1991, together with
increased throughput volumes to all customer classes due to customer
growth and weather that, even though 12% warmer than normal, was 18%
colder than the prior year.
The Company's total throughput volumes in 1994 increased only 107,000
dekatherms (dt), or 0.23%, to 47,000,000 dt. However, throughput volumes
to the Company's firm service customers and interruptible industrial
customers increased substantially, due to strong customer growth
(up 6.2%) and the recapture of some industrial load that had been using
residual oil in 1993, while throughput to one market segment -
interruptible electric power generation - declined 1,729,000 dt (or
61%). Weather in both 1994 and 1993 was approximately 4% warmer than
normal, so the weather had no significant impact on annual throughput.
The significant volume decline in the electric power generation market
occurred primarily during the fourth quarter of Fiscal 1994 due to (1)
a new power supply and operating agreement between the Public Works
Commission of Fayetteville (PWC), the Company's largest electric power
generation customer, and Carolina Power & Light Company (CP&L), PWC's
supplier of bulk electricity; and (2) much milder weather in the summer
of 1994 compared to 1993. The new agreement between PWC and CP&L,
effective in May 1994, provides, among other things, that CP&L will
charge PWC lower rates for the power CP&L sells to PWC and that CP&L
will assume control of the dispatch of PWC's power generating plant
served by the Company. The practical effect of this arrangement is
to reduce usage of gas at PWC's generating plant unless CP&L must
dispatch the plant at times of high peak demand on CP&L's system or
when one or more of its base load nuclear or coal-fired plants is out
of service. In the summer of 1994, all of CP&L's base load plants were
operating and PWC's plant was dispatched only a few days, whereas in
1993, it generated power using natural gas on a regular basis even
when temperatures were relatively mild.
The increase in throughput to the firm service customers, who pay
the highest rates, together with increased facilities charges from
customer growth; the increase in throughput to the interruptible
industrial customers (except those having residual oil as their
alternative fuel); substantial overrun penalties paid by industrial
customers related to cold weather operations in January 1994; an
increase in contract demand by three of the four municipal customers
and the Company's 10% share of interstate pipeline firm transportation
capacity release cost recoupment enabled the Company to increase its
margin by $1,839,000 in 1994 over 1993. However, the loss of
throughput in the electric power generation market caused a margin
decline of $787,000, so the net margin growth in 1994 was $1,052,000.
<PAGE> 21
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations (Continued)
---------------------------------------------------------
The period-to-period comparison of changes in operating revenues and
cost of gas is not a reliable indication of the Company's level of
operations. Transportation gas volumes purchased directly from
producers or other marketers by large industrial and municipal
customers reached 14,547,000 dt or approximately one-third of the
Company's total throughput in 1991, but declined to 6,381,000 dt in
1992, and then increased to 9,480,000 dt in 1993 and increased again
to 13,511,000 dt in 1994. 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 as
transportation rates exclude the commodity cost of gas which is paid
by the customer directly to its gas supplier. The Company, however,
still delivers the gas and earns transportation revenue equivalent to
the margin contained in a comparable sales rate.
Operating revenues declined to $160.3 million in 1994 from $173.1
million in 1993 due to a combination of factors, primarily lower gas
costs passed on to customers and the shift to more transportation
service and less sales to large customers in 1994 compared to 1993.
The strong customer growth and slight increase in net throughput
volumes increased revenues but only partially offset these factors
causing revenues to decline. The revenue increase to $173.1 million
in 1993 from $150.5 million in 1992 was also due to a variety of
factors, primarily an increase in the customer base and total
throughput, increased gas costs passed on to customers and the full
year's impact of the December 1991 general rate increase.
The Company continued to have significant volumes of negotiated sales
in 1994, primarily due to the ongoing price competition in the
residual fuel oil market, but such negotiations did not result in a
loss of margin due to the operation of the IST and the Company's
PGA procedures.
Cost of gas declined to $105.2 million in 1994 from $119.1 million
in 1993 due to three factors: (1) a decline in the volumes of gas
purchased in 1994 due to the increase in gas purchased directly by
end users for transportation on the Company's system; (2) a decline
in the average gas commodity price paid by the Company to $2.21 per
dt in 1994 from $2.39 per dt in 1993; and (3) a decrease of $1.1
million in net fixed charges paid to interstate pipelines and other
gas suppliers due to capacity release credits and restructuring of
some contracts. Natural gas commodity prices were higher during the
winter months of 1993/94, but declined significantly throughout the
summer of 1994. FERC Order 636 permits holders of firm transportation
capacity on interstate pipelines to release any portion of it,
even for just one day at a time, to others at market-based prices not
to exceed the pipeline's rate. NCUC rules require that 90% of any cost
recoupment be passed on to the Company's customers while the Company
can retain 10% of the capacity release credits. During each month of
the summer of 1994, the Company released some capacity deemed excess to
its needs and recouped $1 million in pipeline FT reservation charges.
Cost of gas increased to $119.1 million in 1993 from $100.3 million in
1992, primarily due to higher gas commodity prices in 1993 when the gas
market recovered from abnormally low levels in 1992. Additionally, the
Company incurred an increase of $4.7 million in fixed charges for
pipeline capacity and storage services caused by a full year's effect
of general rate increases for both pipelines in 1992 when they changed
their rate designs to the straight fixed-variable method which increases
fixed charges.
<PAGE> 22
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
---------------------------------------------
Margin increased $1,052,000 to $55,097,000 in 1994 for reasons explained
above. In 1993, margin increased $3,883,000 to $54,045,000 from
$50,162,000 in 1992 because of substantial customer growth and throughput
increases to the residential, commercial, municipal and non-IST
industrial markets.
The slow down in margin growth in 1994, coupled with expected increases
in operations and maintenance expenses, depreciation and general taxes,
caused utility operating income to decline $689,000 in 1994 following
substantial increases in 1993 and 1992.
Operations and maintenance expenses increased to $19.5 million in 1994
from $18.4 million in 1993 and $17.8 million in 1992 primarily because
of the Company's growing customer base which requires more employees
(19 added in 1994) to serve additional customers and expand, operate
and maintain the Company's distribution, transmission and storage
facilities. Additionally, the Company adopted FASB Statement No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions"
effective October 1, 1993, which increased expenses approximately
$500,000 in 1994. Wage and salary increases granted to employees and
officers averaged 4.5% in 1994. Decreases in expenses in 1994 occurred
in the areas of sales promotion due to cost-cutting efforts and
transmission maintenance due to nonrecurring work in 1993 on the main
transmission line. Expenses in 1993 also increased because of rapid
customer growth, additional employees and wage and salary increases. In
1992, additional maintenance costs of $500,000 relating to environmental
matters were incurred; such costs did not recur in either 1993 or 1994.
Depreciation expense increased from $6.1 million to $7.4 million from
1992 to 1994 due to the substantial growth in plant in service,
particularly from transmission line extensions and new compressors and,
also, distribution mains and service line extensions into Cumberland,
New Hanover, Johnston and Union counties. Depreciation rates were
approximately the same in all years.
The federal and state income tax provision in 1994 was essentially
unchanged from 1993 because, even though operating income declined in
1994, utility interest charges also declined and the 35% federal tax
rate was in effect for all of 1994 compared to only nine months in 1993.
Tax provisions for each of the years 1994, 1993 and 1992 were reduced by
approximately $200,000 due to amortization of excess deferred income
taxes authorized in the December 1991 general rate order. The Company's
adoption of FASB Statement No. 109 on accounting for income taxes
effective October 1, 1993, had no appreciable impact on the income tax
provision. Earnings from the Company's nonutility division increased
to $723,000 in 1994 from $313,000 in 1993 due to continuing growth in
propane gas operations and the reduction of 1993 earnings caused by
the writedown of the carrying value of certain nonutility assets.
Utility interest charges decreased to $4.1 million in 1994 from $4.4
million in 1993 and $5.0 million in 1992 because of several factors.
Long-term debt, including current maturities, decreased to $39,000,000
at September 30, 1994 from $45,088,000 at September 30, 1993 and
$48,452,000 at September 30, 1992 through sinking fund payments,
including the prepayment on September 1, 1994 of the remaining
$4,088,000 principal balance of the 12 7/8% Debentures due September 1,
1996. The $17.5 million net proceeds from a public offering of common
stock in February 1993 were used entirely to reduce short-term debt
then outstanding. While short-term debt has increased to $26 million
<PAGE> 23
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations (Continued)
---------------------------------------------------------
at September 30, 1994 from $15.5 million at September 30, 1993, and
short-term interest rates have increased in 1994, the reduction in
long-term debt interest expense has more than offset the increased cost
of short-term borrowings in 1994. Another factor causing the decline in
utility interest charges in 1994 is the increase in the allowance for
funds used during construction (AFUDC) to $500,000 in 1994 from $204,000
in 1993 due to the higher level of construction spending in 1994 compared
to 1993 and a resulting increase in construction work in progress on
which AFUDC is taken. Partially offsetting these factors was a net
decrease in recoverable purchased gas costs. Under NCUC rules, amounts
owed to, or due from, customers for purchased gas cost and IST over or
under collections accrue interest at the rate of 10% per annum.
IMPACT OF INFLATION
Inflation impacts the Company primarily in the prices it pays for labor,
materials and services. Because the Company can adjust its rates to
recover cost increases only through the regulatory process, increased
costs can have a significant impact on the results of operations. Under
present regulatory commission Orders, the Company passes on to its
customers substantially all increases or decreases in the cost of gas
which comprises approximately two-thirds of the Company's revenues.
OTHER MATTERS
In 1991, the North Carolina Department of Environment, Health and
Natural Resources advised the Company of possible environmental
contamination arising from the site of a former manufactured gas
facility in Kinston, North Carolina. The Company retained an
environmental services consulting firm which has estimated the costs
of investigation and remediation based on its work to date to be between
$1.4 million and $2.8 million over a four-to-six year period. The
Company believes that any appreciable costs not previously provided for
will be recovered from third parties, including liability insurance
carriers, or in natural gas rates.
The Company also owns another site of a former manufactured gas plant in
New Bern, North Carolina, and was a previous owner of three small former
manufactured gas plant sites on which no significant problems have arisen.
SIGNIFICANT TRENDS
The implementation in November 1993 of FERC Order 636 by all U.S.
interstate pipelines, including the two serving the Company, essentially
completes the decade-long process of restructuring, at the federal
regulatory level, the natural gas industry into a more competitive
environment. The new rules provide the natural gas industry more
freedom in the way it operates, and the increasing competition is
changing the way local distribution companies (LDCs) such as NCNG
conduct business with the result that consumers have more choices and
lower gas costs than they had before. Also, LDCs, including NCNG, have
more risk as they assume the majority of the gas supply aggregation
burden formerly shouldered almost exclusively by the pipelines. The
Company has developed strategic goals and action plans to compete
successfully in the new era, and Management believes that additional
opportunities for growth in the Company's service area continue to be
abundant.
<PAGE> 24
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operaitons (Continued)
---------------------------------------------------------
While the Company, since 1990, has extended its pipeline to serve the
Johnston County towns of Smithfield, Selma and Clayton; built a 27-mile,
12" pipeline to serve a major industrial plant in Brunswick County;
expanded its distribution system in Union County; and is presently
extending its pipeline 13 miles to serve the Town of Mount Olive in
southern Wayne County, there remain several counties in the Company's
service area with no natural gas service. The North Carolina General
Assembly in 1991 passed legislation that authorized creation of an
expansion fund for each local natural gas distribution company.
The Company applied to the NCUC for establishment of an expansion fund
in 1992 and for approval of an expansion project. By Order of the NCUC
dated February 8, 1993, an Expansion Fund for the Company was created,
but the NCUC did not rule on the proposed expansion project. This
Commission decision was opposed by several major existing industrial
and municipal customers who subsequently appealed the NCUC Order to the
Supreme Court of North Carolina. In July 1994, the Court upheld the
Commission's Order, thus clearing the way for the Company to apply once
again for authorization from the NCUC to extend its pipeline into one or
more unserved areas utilizing its Expansion Fund. On October 20, 1994,
the Company transferred an additional $6.6 million to its Expansion Fund
administered by the NCUC which, when a previous transfer in April 1993
and cumulative interest earned to date are considered, brings the total
amount in the Expansion Fund to $10.8 million at that date. Additionally,
the Company had on hand at September 30, 1994 an additional $2.7 million
of pipeline refunds which have not been transferred yet to the Expansion
Fund because Transco has appealed FERC's rate order directing Transco to
make such refunds.
<PAGE> 25
Item 8. Financial Statements and Supplementary Data
- ----------------------------------------------------
Consolidated Balance Sheets
as of September 30, 1994 1993
---- ----
Assets
GAS UTILITY PLANT:
In service $240,270,999 $224,127,260
Less - Accumulated depreciation 79,033,948 72,402,705
and amortization ----------- -----------
161,237,051 151,724,555
Construction work in progress 3,605,664 818,641
----------- -----------
164,842,715 152,543,196
----------- -----------
INVESTMENTS:
Nonutility property, less
accumulated depreciation
(1994, $2,417,285; 1993, $2,195,826) 2,867,415 2,448,454
Investment in exploration and development
activities, net of accumulated
depletion and amortization
(1994 $3,052,534; 1993 $9,441,190) 90,227 180,177
----------- -----------
2,957,642 2,628,631
----------- -----------
CURRENT ASSETS:
Cash and temporary cash investments 158,432 1,591,512
Restricted temporary cash investment 9,281,583 4,862,746
Accounts receivable, less allowance for
doubtful accounts (1994, $416,049;
1993, $434,375) 11,795,395 12,796,224
Recoverable purchased gas costs 1,505,124 6,396,284
Inventories, at average cost --
Gas in storage 8,091,210 7,169,436
Materials and supplies 2,634,021 1,973,181
Merchandise 1,415,030 1,312,719
Deferred gas cost - unbilled volumes 473,136 638,265
Prepaid expenses and other 387,125 383,659
----------- -----------
35,741,056 37,124,026
----------- -----------
DEFERRED CHARGES AND OTHER:
Debt discount and expense, being
amortized over lives of related debt 300,477 379,036
Prepaid pension cost 1,178,344 1,368,736
Other 67,036 134,465
----------- -----------
1,545,857 1,882,237
----------- -----------
$205,087,270 $194,178,090
=========== ===========
(The accompanying notes are an integral part of these financial statements.)
<PAGE> 26
Stockholders' Investment and Liabilities
as of September 30, 1994 1993
---- -----
CAPITALIZATION (see accompanying statements):
Stockholders' investment $ 86,398,741 $ 80,944,184
Long-term debt 37,000,000 39,000,000
----------- -----------
123,398,741 119,944,184
----------- -----------
CURRENT LIABILITIES:
Current maturities of long-term debt 2,000,000 6,088,000
Notes payable 26,000,000 15,500,000
Accounts payable 9,675,443 14,723,470
Customer deposits 1,994,444 1,882,568
Restricted supplier refunds 9,281,583 4,862,746
Accrued interest 1,599,999 1,662,655
Accrued income and other taxes 1,684,596 2,427,561
Other 2,395,492 2,235,894
----------- -----------
54,631,557 49,382,894
----------- -----------
OTHER CREDITS:
Deferred income taxes 18,279,090 20,363,137
Regulatory liability related to
income 3,922,719 --
Unamortized investment tax credits 3,121,692 3,324,492
Postretirement benefit liability 633,666 --
Miscellaneous 1,099,805 1,163,383
----------- -----------
27,056,972 24,851,012
----------- -----------
$205,087,270 $194,178,090
=========== ===========
(The accompanying notes are an integral part of these financial statements.)
<PAGE> 27
Consolidated Statements of Income
For the Years Ended September 30,
1994 1993 1992
---- ---- ----
OPERATING REVENUES $160,336,678 $173,145,401 $150,509,653
COST OF GAS 105,239,767 119,100,211 100,347,522
----------- ----------- -----------
GROSS MARGIN 55,096,911 54,045,190 50,162,131
----------- ----------- -----------
OPERATING EXPENSES AND TAXES:
Operations 16,739,190 15,512,283 14,619,132
Maintenance 2,738,814 2,872,565 3,183,799
Depreciation 7,372,928 6,891,264 6,125,136
General taxes 7,524,483 7,374,822 6,833,926
Income taxes --
Federal 4,995,000 4,942,000 3,990,200
State 1,323,000 1,360,000 1,179,100
----------- ----------- -----------
TOTAL OPERATING EXPENSES AND TAXES 40,693,415 38,952,934 35,931,293
----------- ----------- -----------
OPERATING INCOME 14,403,496 15,092,256 14,230,838
OTHER INCOME, NET 722,582 313,276 450,025
INCOME (LOSS) FROM SUBSIDIARIES 79,274 (4,129) 26,579
----------- ----------- -----------
GROSS INCOME 15,205,352 15,401,403 14,707,442
----------- ----------- -----------
UTILITY INTEREST CHARGES:
Interest on long-term debt 4,126,636 4,454,556 4,521,555
Other interest 349,980 129,609 1,006,456
Amortization of debt discount
and expense 78,559 44,546 42,409
Allowance for funds used during
construction (499,754) (204,386) (559,644)
----------- ----------- -----------
TOTAL UTILITY INTEREST CHARGES 4,055,421 4,424,325 5,010,776
----------- ----------- -----------
NET INCOME $ 11,149,931 $ 10,977,078 $ 9,696,666
=========== =========== ===========
AVERAGE COMMON SHARES OUTSTANDING 6,331,155 5,981,248 5,414,495
=========== =========== ===========
EARNINGS PER SHARE $1.76 $1.84 $1.79
=========== =========== ===========
(The accompanying notes are an integral part of these financial statements.)
<PAGE> 28
Consolidated Statements of Cash Flows
For the Years Ended September 30, 1994 1993 1992
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $11,149,931 $10,977,078 $9,696,666
Add (deduct) items which did
not use (provide) cash-
Depreciation charged to:
Operating expenses 7,372,927 6,891,264 6,125,136
Other income 340,888 296,749 267,174
Amortization of deferred charges 168,954 98,923 65,784
Deferred income taxes 1,838,672 1,500,000 (395,000)
Investment tax credits, net (202,800) (202,800) (198,000)
Depletion and amortization of
investment in exploration and
development activities 23,018 30,219 53,192
Other 514,451 (253,194) 997,573
Changes in other assets and
liabilities:
Accounts receivable, net 989,329 (921,536) (2,690,373)
Refundable income taxes -- -- 345,355
Gas in storage (921,775) (1,098,888) (114,122)
Materials, supplies and
merchandise (763,150) 20,755 (33,288)
Accounts payable (5,048,026) (1,759,499) 4,817,661
Refunds payable and recoverable
purchased gas costs 4,442,298 545,700 (22,697,407)
Accrued income and other taxes (742,965) (2,821,460) 3,999,244
Other 439,298 503,752 721,476
---------- ---------- ----------
Net cash provided by
operating activities 19,601,050 13,807,063 961,071
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (20,756,334) (15,468,859) (23,772,900)
Proceeds from sale of property 1,076,210 -- --
Other, net (70,632) (50,121) (38,650)
---------- ---------- ----------
Net cash used in
investing activities (19,750,756) (15,518,980) (23,811,550)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of Debentures, Series C -- -- 25,000,000
Increase (decrease) in
notes payable 10,500,000 (7,000,000) 5,500,000
Retirement of long-term debt (6,088,000) (3,364,000) (3,364,000)
Cash dividends paid (7,215,800) (6,447,579) (5,322,452)
Issuance of common stock
through dividend
reinvestment plan 1,255,984 1,123,266 969,492
Issuance of common stock
through employee stock
purchase plan 264,442 228,846 102,416
Issuance of common stock
through public offering -- 17,518,306 --
Issuance of common stock
through key employee
stock option plan -- 131,400 --
---------- ---------- ----------
Net cash (used in) provided
by financing activities (1,283,374) 2,190,239 22,885,456
---------- ---------- ----------
Net increase (decrease) in cash
and temporary cash investments (1,433,080) 478,322 34,977
Cash and temporary cash
investments, beginning of year 1,591,512 1,113,190 1,078,213
---------- ---------- ----------
Cash and temporary cash
investments, end of year $158,432 $1,591,512 $1,113,190
========== ========== ==========
Cash paid for:
Interest (net of amounts
capitalized) $4,533,508 $4,796,222 $4,656,005
Income taxes (net of refunds) 5,653,288 7,654,079 2,742,540
(The accompanying notes are an integral part of these financial statements.)
<PAGE> 29
Consolidated Statements of Capitalization
as of September 30, 1994 1993
---- ----
STOCKHOLDERS' INVESTMENT :
Common stock, par value $2.50;
12,000,000 shares authorized;
shares outstanding: 1994-6,366,544;
1993-6,300,999 $ 15,916,360 $ 15,752,498
Capital in excess of par value 25,498,420 24,141,856
Retained earnings 44,983,961 41,049,830
----------- -----------
Total stockholders' investment 86,398,741 80,944,184
----------- -----------
LONG-TERM DEBT:
Debentures, 12 7/8% Series A, due
September 1, 1996 -- 4,088,000
Debentures, 8 3/4% Series B, due
June 15, 2001 14,000,000 16,000,000
Debentures, 9.21% Series C, due
November 15, 2011 25,000,000 25,000,000
----------- -----------
39,000,000 45,088,000
Less - Current maturities (2,000,000) (6,088,000)
----------- -----------
Total long-term debt 37,000,000 39,000,000
----------- -----------
TOTAL CAPITALIZATION $123,398,741 $119,944,184
=========== ===========
CAPITALIZATION RATIOS:
Stockholders' investment 68.9% 64.2%
Long-term debt (including current
maturities) 31.1% 35.8%
----------- -----------
100.0% 100.0%
=========== ===========
<PAGE> 30
Consolidated Statements of Retained Earnings
For the Years Ended September 30, 1994 1993 1992
---- ---- ----
BALANCE AT BEGINNING OF YEAR $41,049,830 $36,520,331 $36,686,439
Net Income 11,149,931 10,977,078 9,696,666
Cash dividends on common stock
(per share - $1.14 in 1994,
$1.06 in 1993 and $.983 in 1992) (7,215,800) (6,447,579) (5,322,452)
Stock split effected in the form of
a stock dividend -- -- (4,540,322)
---------- ---------- ----------
BALANCE AT END OF YEAR $44,983,961 $41,049,830 $36,520,331
========== ========== ==========
(The accompanying notes are an integral part of these financial statements.)
<PAGE> 31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1994)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation -
The consolidated financial statements include North Carolina Natural
Gas Corporation (the Company) and its wholly owned subsidiaries, NCNG
Exploration Corporation (NCNGE) and Cape Fear Energy Corporation
(Cape Fear). All significant intercompany transactions have been
eliminated in consolidation.
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 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 current rates have been approved by
the North Carolina Utilities Commission (NCUC). Depreciation was
approximately 3.2% of the cost of total depreciable property in 1994
and 1993, and 3.1% in 1992.
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.
In years prior to 1994, income taxes were accounted for under
Accounting Principles Board Opinion No. 11. Effective October 1, 1993,
the Company adopted FASB Statement No. 109, "Accounting for Income
Taxes". Statement No. 109 required, among other things, a change to
<PAGE> 32
the liability method of accounting for deferred income taxes. See Note
3 for more information regarding income taxes.
The Company uses the deferred method of accounting for investment tax
credits. Investment tax credits generated in prior years have been
deferred and are being amortized to income over the service life of the
related property, which is approximately 30 years.
Recognition of Revenue -
The Company follows the practice of rendering customer bills on a
cyclical 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.
Gas in Storage -
Inventories of gas in storage are maintained on the basis of average
cost. Such cost is recovered from customers at the time the gas is
withdrawn from storage and sold.
Temporary Cash Investments -
Temporary cash investments are securities with maturities of 90 days or
less. For purposes of the Consolidated Statements of Cash Flows,
temporary cash investments are considered cash equivalents.
Restricted 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 have been restricted by a previous Order of the NCUC. Pursuant
to the February 1993 Order, the Company remitted $3,795,000 to the NCUC
for the Expansion Fund in April 1993. At September 30, 1993, the refunds
received plus interest, which had not been remitted to the NCUC, amounted
to $4,863,000 and were reported on the balance sheet in restricted
temporary cash investments and restricted supplier refunds.
During 1994 an additional $4.2 million of pipeline refunds were received
which, together with interest earned on funds invested by the Company,
brought the amount reported on the balance sheet as restricted temporary
cash investments and restricted supplier refunds to $9,282,000 at
<PAGE> 33
September 30, 1994. In October 1994, the Company remitted an additional
$6,645,000 to the NCUC for the Expansion Fund.
Pursuant to the NCUC Orders, the funds not yet transferred to the
Expansion Fund administered by the NCUC 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.
Amounts remitted to the NCUC through September 30, 1994 are not included
in the Company's financial statements.
Fair Value of Financial Instruments -
FASB Statement No. 107, "Disclosure About Fair Value of Financial
Instruments" requires disclosure of the fair value of financial
instruments, both assets and liabilities, for which it is practicable
to estimate fair value.
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 September 30, 1994 is approximately
$39.7 million as compared to a carrying value of $39.0 million and at
September 30, 1993 the estimated fair value was approximately $52.3
million as compared to a carrying value of $45.1 million.
Reclassifications -
Certain Financial Statement items in 1993 and 1992 have been
reclassified to conform with the 1994 presentation.
2. REGULATORY AND GAS SUPPLY MATTERS:
In the general rate case filed in May 1991, the NCUC granted, effective
December 6, 1991, additional annual revenues of $2,565,000 and rates of
return of 11.16% and 12.70% on net investment and common equity,
respectively. Additionally, the NCUC allowed the Company to continue to
include in its rate tariff an Industrial Sales Tracker (IST) which is
designed to stabilize the Company's margin (difference between revenues
and purchased gas costs) earned from sales and transportation to
interruptible industrial customers who use heavy fuel oil as an
<PAGE> 34
alternative fuel. To the extent that actual margins realized from
deliveries to such customers exceed, or are less than, the base period
margins included in the general rate case from IST sales or
transportation, refunds payable or additional receivables are recorded.
The actual margins earned from IST deliveries were less than the base
period margin by $3,940,000 and $5,166,000 in 1994 and 1993,
respectively.
Also as part of the December 6, 1991 rate Order, the NCUC approved the
Company's application to establish a Weather Normalization Adjustment
(WNA) for the space heating market. 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. In Fiscal 1994, winter
weather was 3% warmer than normal and, accordingly, the WNA increased
net billings to customers by $462,000.
The NCUC, in a general rulemaking proceeding, revised its Purchased Gas
Adjustment (PGA) procedures in April 1992. The revised procedures
continue to allow the Company to recover all of its prudently incurred
gas costs, but such procedures provide for several significant changes
which include: (1) the establishment of a benchmark commodity cost of
gas which represents the Company's estimate of the actual commodity
cost of gas from all suppliers that it will incur in a future period;
(2) 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; (3) the notice period for requesting
PGA rate changes was reduced to 14 days from 30 days; (4) the
establishment of a tariff provision which allows the Company to recover
margin losses from negotiated rates to non-IST large commercial and
industrial customers; (5) a true-up of fixed gas costs recovered from
the Company's customers; (6) a true-up of the Company's lost,
unaccounted for and company use volumes compared to such volumes
included in the last general rate case; and (7) an annual review of
the Company's gas costs, including the prudence thereof, by the Public
Staff of the NCUC and a hearing before the NCUC. The Company's second
annual review of its gas costs was held in April 1994 for the 12 months
ended November 30, 1993. The NCUC found the Company's gas costs and gas
purchasing practices to be prudent, as it had for the first annual
review in 1993.
<PAGE> 35
In July 1994 the NCUC issued another rulemaking order in which it
required that all natural gas utilities flow through to customers 90% of
the net compensation received for capacity release and similar
transactions while retaining 10% of such compensation. The Company had
been accounting for such transactions in accordance with the 90/10
sharing mechanism pursuant to a previous Commission Order issued in 1993.
In August 1994 the Company filed with the NCUC its second annual true-up
of lost, unaccounted for and company use volumes for the 12 months ended
June 30, 1994. Because such volumes exceeded the base period amounts
included in the last general rate case, the Company charged $1,292,000
in 1994 from the true-up to the deferred gas cost account for future
recovery in rates from customers.
3. INCOME TAXES:
The components of income tax expense are as follows (in thousands):
For the years ended September 30,
------------------------------------------------
1994 1993 1992
-------------- -------------- ---------------
Federal State Federal State Federal State
------- ----- ------- ----- ------- -----
Income taxes ...............(In Thousands)...................
charged to
operations-
Payable
currently... $3,937 $ 937 $4,016 $1,000 $4,473 $1,189
Deferred to
subsequent
years..... 1,256 386 1,124 360 (285) (10)
Investment tax
credits,
net........ (198) -- (198) -- (198) --
----- ----- ----- ----- ----- -----
$4,995 $1,323 $4,942 $1,360 $3,990 $1,179
===== ===== ===== ===== ===== =====
Income taxes
charged to
other income $ 429 $ 106 $ 165 $ 42 $ 149 $ 136
===== ===== ===== ===== ===== =====
The effective income tax rate, computed by dividing total income tax
expense by the sum of certain income tax expense and net income, is 38.1% in
1994, 37.2% in 1993, and 36.0% in 1992.
<PAGE> 36
A reconciliation of income tax expense at the federal statutory rate to
recorded income tax expense is as follows (in thousands):
1994 1993 1992
---- ---- ----
Federal taxes at 35% for 1994,
34.75% for 1993 and 34% for 1992 .... $6,301 $6,076 $5,152
State income taxes, net of
federal benefit ..................... 929 915 868
Amortization of investment tax credits.. (203) (203) (198)
Amortization of excess deferred
income taxes returned to customers... (222) (222) (222)
Tax credit - supplier refunds........... ( 17) (133) --
Tax effect of allowance for funds used
during construction - equity portion. ( 97) ( 40) (107)
Other................................... 162 116 ( 39)
----- ----- -----
Total income tax expense................ $6,853 $6,509 $5,454
===== ===== =====
Effective October 1, 1993, the Company adopted FASB Statement No. 109,
"Accounting for Income Taxes". The adoption of Statement No. 109
resulted in cumulative adjustments to the balance sheet and had no
effect on consolidated net income. As a result of Statement No. 109,
the Company reduced accumulated deferred income taxes and recorded
related regulatory assets and liabilities. The regulatory net liability
is due primarily to deferred income taxes recognized in years prior to
1987 at rates higher than currently enacted.
The major timing differences for 1992 and 1993 were accelerated tax
depreciation and producer settlement payments. The tax effects of
temporary differences in the carrying amounts of assets and liabilities
in the Financial Statements and their respective tax bases that give rise
to deferred tax assets and liabilities are as follows:
1994
----
Deferred Tax Liabilities:
Accelerated Depreciation $19,903
Property Basis Differences 3,435
------
Total Deferred Tax Liabilities $23,338
------
Deferred Tax Assets:
Unamortized Investment Tax Credits $ 1,245
Regulatory Liability Related to
Income Taxes, Net 1,571
Other 2,243
------
Total Deferred Tax Assets $ 5,059
------
Net Deferred Tax Liabilities $18,279
======
<PAGE> 37
4. SUBSIDIARY OPERATIONS:
NCNGE and Cape Fear participated in oil and gas exploration and
development programs for several years. Under a program approved by
the NCUC, the Company's customers participated in several NCNGE
exploration and development programs by providing through rates
approximately 75% of the net costs of those programs and receiving
approximately 75% of net program revenues in return.
Effective June 7, 1994, the Company and the other three natural gas
distribution utilities in North Carolina sold their combined interests
in all of the exploration and development programs in which NCNGE was
involved. NCNGE's share of the net proceeds was $615,000, of which
$144,500 was deposited in an escrow account to remain until December 31,
1995 to cover any potential claims presented by the buyers. NCNGE
recognized a pretax gain of $58,000 (shareholders' portion) on the sale,
excluding the amount held in escrow. Approximately 75% of the net
proceeds from the sale, along with net revenues and expenses of the
programs prior to the sale, will be considered in the final amounts due
to or from customers under these programs.
Cape Fear also purchases natural gas for transportation for the
Company's system supply and for certain of the Company's customers who
have requested Cape Fear's services.
5. SHORT-TERM BORROWING ARRANGEMENTS:
The Company has lines of credit with North Carolina banks for an
aggregate amount of $35,500,000. Under these lines, the Company
borrows funds on a short-term basis in connection with its construction
program and also for seasonal financing of storage gas, usually on a
demand basis for a period of 90 days. The Company also uses bankers'
acceptances to finance the cost of gas in storage for periods up to 180
days. The maximum amount of such bankers' acceptances is dependent upon
the market value of gas in storage and these loans are made at rates
below the prime rate. At September 30, 1994, $26,000,000 was outstanding
at interest rates ranging from 5.065% to 5.35% and $9,500,000 was
available under these arrangements.
In connection with the lines of credit, the Company is expected to
maintain certain annual average nonrestricted cash balances in the banks
ranging from 5% to 10% of the loans outstanding. In addition, there are
nominal commitment fees on the unused lines of credit. To the extent
that bankers' acceptances are outstanding, no commitment fees are
payable.
<PAGE> 38
6. PENSION AND OTHER POSTRETIREMENT BENEFITS:
The Company has a pension plan which provides retirement benefits for
its employees within specified age limits and periods of service. Plan
benefits are based on years of service and the employee's compensation
during the last five years of employment. The Company's funding policy
is to contribute annually an amount equal to the maximum allowable tax
deductible amount.
The total pension cost was $222,000 in 1994, $131,000 in 1993, and
$63,000 in 1992, of which approximately 20% was capitalized in each year.
The plan's funded status as of September 30, 1994 and 1993 and pension
costs for 1994, 1993 and 1992 were as follows (in thousands):
Funded Status: 1994 1993
-------------- ---- ----
Actuarial present value of accumulated
plan benefits:
Vested $14,355 $12,883
Nonvested 97 97
------ ------
Subtotal 14,452 12,980
Effect of salary progression 3,989 3,776
------ ------
Projected benefit obligation 18,441 16,756
Plan assets at market value 18,920 20,003
------ ------
Plan assets in excess of projected
benefit obligation 479 3,247
Unrecognized prior service cost being
amortized over twelve years 707 298
Unrecognized net(gain)loss being
amortized over ten years 721 (1,189)
Unrecognized net asset existing at the
date of transition, being amortized
over approximately ten years (729) (987)
------ ------
Prepaid pension cost $ 1,178 $ 1,369
====== ======
Pension Cost 1994 1993 1992
------------ ---- ---- ----
Net pension cost was comprised of
the following items:
Service Cost $ 633 $ 610 $ 536
Interest cost on projected
benefit obligation 1,346 1,225 1,108
Actual return on plan assets 299 (1,908) (2,024)
Amortization of unrecognized
prior service cost 66 32 32
Amortization of transition net asset (258) (258) (258)
Deferred gain (loss) on net assets (1,864) 430 669
------ ----- -----
Net pension cost $ 222 $ 131 $ 63
====== ===== =====
<PAGE> 39
The expected long-term rate of return on plan assets was 8%. At
September 30, 1994, plan assets were invested approximately 63% in
fixed income securities and 37% in equity securities, including 2% in
the common stock of the Company.
The Company also provides certain health care and life insurance
benefits for retired employees, and substantially all employees may
remain eligible for these benefits when they retire. Effective October
1, 1993 the Company adopted FASB Statement No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," on a
prospective basis. This statement requires accounting for these
benefits on an accrual basis using a single actuarial method which
spreads the expected cost of such benefits to each year of an employee's
service until the employee becomes fully eligible to receive the
benefits. Prior to October 1, 1993, the Company accounted for these
benefits on a cash basis consistent with current ratemaking treatment.
The costs of such benefits charged to expense amounted to $501,000 in
1993 and $568,000 in 1992. The NCUC, in rate cases where Statement No.
106 accounting has been presented, has expressed its preference for the
accrual basis of accounting and, accordingly, the Company expects that
the regulatory treatment of these costs under Statement No. 106 in the
Company's next general rate case will be the same prospectively as the
accrual method that has been adopted. The Company is not currently
funding this plan.
<PAGE> 40
The following tables show the funded status of the plan and the
components of the plan's net costs (in thousands) for fiscal year 1994:
Funded Status Medical Life
------------- ------- ----
Actuarial present value of
benefit obligation:
Retirees and dependents $ 2,112 $ 335
Employees eligible to retire 818 106
Other Employees 1,966 197
------ ------
Accumulated benefit obligation 4,896 638
Unrecognized net gain 112 38
Unrecognized transition obligation (4,446) (604)
------ ------
Postretirement benefit liability $ 562 $ 72
====== ======
Components of Net Cost
----------------------
Service cost during the year $ 128 $ 12
Interest cost on accumulated
benefit obligation 363 49
Amortization of unrecognized transition
obligation over 20 years 234 32
------ ------
Net periodic postretirement benefit cost $ 725 $ 93
====== ======
Of the net postretirement medical and life insurance costs recorded
in 1994, $670,000 was charged to operating expenses and the remainder
was charged to construction and other accounts.
The discount rate and rate of increase in future compensation levels
used in determining the actuarial present value of the projected
benefit obligations (pension, health care and life insurance) previously
shown were 8% and 6%, respectively.
An additional assumption used in measuring the accumulated postretirement
medical benefit obligation was a medical care cost trend rate of 12.5% for
1994, decreasing gradually to 5.5% through the year 2005 and remaining at
that level thereafter. An annual increase in the assumed medical care cost
trend rate by 1% would increase the accumulated medical benefit obligation
at September 30, 1994, by $965,000 and the aggregate of the service and
interest cost components of the net retiree medical cost by $108,000.
The Financial Accounting Standards Board (FASB) issued Statement No. 112,
"Employers' Accounting for Postemployment Benefits", which requires that
all types of benefits provided to former or inactive employees and their
families prior to reitrement be accounted for on an accrual basis. The
Company plans to adopt this standard in Fiscal 1995 and it is not
expected to have a material impact on the financial statements.
<PAGE> 41
7. STOCKHOLDERS' INVESTMENT:
The changes in common stock and capital in excess of par value for the
three years ended September 30, 1994, were as follows:
Common Stock
$2.50 Par, Authorized
12,000,000 Shares
--------------------- Capital In
Shares Excess of
Outstanding Amount Par Value
----------- ---------- ----------
Balance at September 30, 1991 3,591,905 $8,979,763 $6,300,543
Issuance through Dividend
Reinvestment Plan (DRP) 35,350 88,375 881,117
Issuance through Employee
Stock Purchase Plan (ESPP) 5,002 12,505 89,911
Issuance through
stock split effected in
the form of a dividend 1,816,129 4,540,322 --
--------- ---------- ---------
Balance at September 30, 1992 5,448,386 13,620,965 7,271,571
Issuance through DRP. . . 44,946 112,365 1,010,901
Issuance through ESPP . . 15,992 39,980 188,866
Issuance through exercise
of stock options . . . 5,175 12,938 118,462
Issuance through
public offering of
common stock . . . . . 786,500 1,966,250 15,552,056
--------- ---------- ----------
Balance at September 30, 1993 . 6,300,999 15,752,498 24,141,856
Issuance through DRP. . . 52,868 132,170 1,123,814
Issuance through ESPP . . 12,677 31,692 232,750
--------- ---------- ----------
Balance at September 30, 1994 . 6,366,544 $15,916,360 $25,498,420
========= ========== ==========
In February 1993, the Company issued common stock through a public
offering at a price of $23.50 per share with net proceeds of $17.5
million after expenses of the offering.
The Company's common stock was split three-for-two effective October 30,
1992, in the form of a stock dividend. All earnings and dividends per
share amounts in the accompanying consolidated financial statements and
notes thereto reflect the stock split.
At September 30, 1994, there are 893,818 shares of common stock reserved
for issuance under the Company's Dividend Reinvestment Plan and for other
reasons. Under the most restrictive covenants of the Company's long-term
debt agreements, approximately $17,838,000 of the Company's retained
earnings at September 30, 1994, is unrestricted.
<PAGE> 42
8. LONG-TERM DEBT MATURITIES:
Maturities of existing long-term debt during each of the next five years
will be as follows: 1995, $2,000,000; 1996, $2,000,000; 1997, $2,000,000;
1998, $2,000,000 and 1999, $3,250,000.
9. STOCK PURCHASE AND OPTION PLANS:
In 1990, the Company instituted a stock purchase plan and a key employee
nonqualified stock option plan. The stock purchase plan enables
employees to contribute up to 6% of their wages toward purchase of the
Company's common stock at 90% of the lower of current or prior year-end
market value. Shares have been purchased by employees each year since
1991. Under the terms of the nonqualified stock option plan, 300,000 of
authorized but unissued shares were available for purchase under the
plan.
Under the terms of the nonqualified stock option plan, a maximum of
150,000 shares are reserved for issuance. The option price is equal
to 90% of the market value of the stock at the grant date. The period
during which these options are exercisable begins five years after, but
may not exceed seven years after, the date of grant. In addition, the
plan provides that an amount equal to 50% of the dividends that would
have been paid on the stock from the date of grant shall be paid in
cash at the exercise date. The plan provides that retired officers may
exercise a pro rata number of options based on the number of months'
service after the date of grant.
Transactions for 1994 and 1993 respectively, are as follows:
Shares Subject Average Option
To Option Price Per Share
-------------- ---------------
Balance at September 30, 1992 86,400 $13.82
Exercised upon retirement
of two officers.... ( 5,175) 13.80
Canceled...... ( 8,475) 13.80
------ -----
Balance at September 30, 1993 72,750 $13.83
Granted.. 2,600 24.98
------ -----
Balance at September 30, 1994 75,350 $14.21
====== =====
1994 1993 1992
---- ---- ----
Options Exercisable
at Year End........ -- -- --
Options Available for
Grant at Year End.. 69,475 72,075 63,600
<PAGE> 43
10. COMMITMENTS AND CONTINGENCIES:
During fiscal year 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 to
date 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 over a four-to-six-year period.
As of September 30, 1994, the Company had incurred no significant
expenditures which were not covered by reimbursements from third parties,
and none of these costs or reimbursements were included in the Company's
natural gas rates. 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 financial condition or
results of operations.
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 business,
financial condition, or results of operations.
<PAGE> 44
Supplementary data -
The following table presents certain financial information for each
quarter during the fiscal years ended September 30, 1994 and 1993
(amounts in thousands, except per share data). Amounts have been
restated to reflect a 3-for-2 common stock split in the form of a
common stock dividend effective October 30, 1992.
1994
--------------------------------------
Fourth Third Second First
------ ----- ------ -----
Operating revenues $26,117 $29,523 $62,615 $42,082
Gross margin 9,617 9,264 21,080 15,136
Operating income 1,148 1,148 7,676 4,431
Net income 28 127 7,301 3,693
Earnings per share .004 .02 1.15 .59
1993
--------------------------------------
Fourth Third Second First
------ ----- ------ -----
Operating revenues $29,195 $38,638 $53,916 $51,396
Gross margin 9,872 10,103 19,855 14,215
Operating income 1,756 1,852 7,391 4,093
Net income 424 700 6,652 3,201
Earnings per share(1) .07 .11 1.12 .59
1) The sum of the quarterly earnings per share amounts for 1993 does not
equal the annual earnings per share amount reflected in the
consolidated statement of income due to the effect of changes in
average common shares outstanding during the fiscal year.
Item 9. Changes in and Disagreements on
Accounting and Financial Disclosures
- ---------------------------------------------
None.
<PAGE> 45
Item 10. Management's Responsibility for Financial Statements
- ---------------------------------------------------------------
Management is responsible for the preparation, presentation and
integrity of the financial statements and other financial information
in this report. The accompanying financial statements have been
prepared in accordance with generally accepted accounting principles
applicable to rate-regulated public utilities, including estimates and
judgments made by management that were necessary to prepare the
statements in accordance with such accounting principles, and are not
misstated due to material fraud or error. To assure the integrity of
the underlying financial records supporting the financial statements,
management maintains a system of internal accounting controls sufficient
to provide reasonable assurances that NCNG assets are properly accounted
for, safeguarded and are utilized only in accordance with management's
authorization. The concept of reasonable assurance recognizes that the
costs of a system of internal controls should not exceed the related
benefits derived from it.
The system of internal accounting controls is augmented by NCNG's
internal audit department, which has unrestricted access to all levels
of NCNG management. The internal audit department meets periodically,
with and without the presence of management, with the Audit Committee of
the Board of Directors to discuss, among other things, NCNG's system of
internal accounting controls and the adequacy of the internal audit
program. The Audit Committee is comprised of four directors who are
not officers or employees of NCNG.
The Audit Committee also meets periodically with Arthur Andersen LLP,
NCNG's independent public accountants, with and without the presence of
management, to discuss the results of the annual audit of NCNG's
financial statements and related data. The Audit Committee and Arthur
Andersen LLP also discuss internal accounting control matters that come
to the attention of Arthur Andersen LLP during the course of the audit.
s/Calvin B. Wells s/Gerald A. Teele
--------------------------- ----------------------
Calvin B. Wells Gerald A. Teele
Chairman, President and Senior Vice President and
Chief Executive Officer Chief Financial Officer
<PAGE> 46
PART III
--------
Item 11. Directors and Executive Officers of the Registrant
- ------------------------------------------------------------
Directors -
The information for this item covering directors of the Company is set
forth in the section entitled "Election of Directors and Information as
to Members" on Pages 1, 2 and 3 in the Company's Proxy Statement dated
December 5, 1994 relating to the January 10, 1995 Annual Meeting of
Stockholders, which section is hereby incorporated by reference.
Executive officers -
The information for this item concerning executive officers of the
Company is set forth on Page 14 of this annual report.
Item 12. Executive Compensation
- --------------------------------
The information for this item is set forth in the sections entitled
"Executive Compensation", "Key Employee Stock Option Plan", "Employee
Stock Purchase Plan", "Employee Retirement Plan" and "Executive Employment
Agreements in the Event of Change in Control" and "Report of Personnel
Committee on Executive Compensation" on Pages 4, 5, 6, 7, 8, and 9 in the
Company's Proxy Statement dated December 5, 1994 relating to the January
10, 1995 Annual Meeting of Stockholders, which sections are hereby
incorporated by reference.
Item 13. Security Ownership of Certain Beneficial Owners
and Management
- ----------------------------------------------------------
Security ownership of certain beneficial owners -
There is no person who is known to the Company to be the beneficial
owner of more than five percent of the Company's common stock as of
September 30, 1994.
Security ownership of management -
The information for this item is set forth in the section entitled
"Election of Directors and Information as to Members" on Pages 1, 2 and
3 in the Company's Proxy Statement dated December 5, 1994 relating to
the January 10, 1995 Annual Meeting of Stockholders, which section is
hereby incorporated by reference.
Changes in control -
The Company knows of no contractual arrangements which may at a
subsequent date result in a change in control of the Company.
<PAGE> 47
Item 14. Certain Relationships and Related Transactions
- ----------------------------------------------------------
The information for this item is set forth in the sections entitled
"Directors Transactions" and "Compensation Interlocks and Insider
Participation" on Pages 1 and 9 in the Company's Proxy Statement dated
December 5, 1994 relating to the January 10, 1995 Annual Meeting of
Stockholders, which section is hereby incorporated by reference.
<PAGE> 48
PART IV
-------
Item 15. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K
- -------------------------------------------------------
(a) 1. Financial Statements
Page
----
Consolidated Balance Sheets as of September 30, 1994 and
1993. 24
Consolidated Statements of Income for the Years Ended
September 30, 1994, 1993 and 1992. 26
Consolidated Statements of Cash Flows for the Years Ended
September 30, 1994, 1993, and 1992. 27
Consolidated Statements of Capitalization as of September 30,
1994 and 1993. 28
Consolidated Statements of Retained Earnings for the Years
Ended September 30, 1994, 1993 and 1992. 29
Notes to Consolidated Financial Statements for years ended
September 1994, 1993 and 1992. 30
Management's Responsibility for Financial Statements. 44
No separate financial statements are presented for the Company's
consolidated subsidiaries because the Company and its subsidiaries
meet the requirements for omission set forth in Regulation S-X, Rule 3-O9.
(a) 2. Financial Statement Schedules
--------------------------------------
The following data and financial statement schedules are
included herein:
Page
----
Report of Independent Public Accountants 58
Schedule V - Gas Utility Plant (Including
Intangibles) and Nonutility Property for
Years Ended September 30, 1994, 1993 and 1992. 49-51
Schedule VI - Reserves for Depreciation and
Amortization for the Years Ended September 30,
1994, 1993 and 1992. 52-54
Schedule VIII - Valuation and Qualifying Accounts
for the Years Ended September 30, 1994, 1993
and 1992. 55
Schedule IX - Short-term Borrowings for the
Years Ended September 30, 1994, 1993 and 1992. 56
Schedule X - Supplementary Income Statement
Information for the Years Ended September 30,
1994, 1993 and 1992. 57
<PAGE> 49
Item 15. (Continued)
- ---------------------
All other financial statement schedules are omitted as not
applicable, or nor required, or because the required information
is given in the Consolidated Financial Statements or Notes thereto.
(a) 3. Exhibits
----------------
See Index of Exhibits on Page 60 of this report.
(b) Reports on Form 8-K
------------------------
There were no reports on Form 8-K filed during the three months
ended September 30, 1994.
<PAGE> 50
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE V - GAS UTILITY PLANT (INCLUDING INTANGIBLES) AND
NONUTILITY PROPERTY
FOR THE YEAR ENDED SEPTEMBER 30, 1994
<CAPTION>
Col. A Col. B Col. C Col. D. Col. E Col. F
Other
Balance At Changes - Balance
Beginning Additions Retirements Transfers - at End
Major Classification of Period at Cost or Sales Add (Deduct) of Period
- -------------------- --------- --------- ----------- ------------ ---------
<S> <C> <C> <C> <C> <C>
GAS UTILITY PLANT:
Intangible $ 990,524 $ - $ - $ - $ 990,524
Tangible -
NG Storage 21,182,309 24,557 - - 21,206,866
Transmission 60,050,219 5,228,831 ( 9,188) 21,801 65,291,663
Distribution 128,935,384 9,396,435 (250,226) (21,801) 138,059,792
General 12,968,824 2,633,293 (879,963) - 14,722,154
----------- ---------- ---------- -------- -----------
Total Plant in Service $224,127,260 $17,283,116 $(1,139,377) $ - $240,270,999
Const. work in progress 818,641 2,787,023 - - 3,605,664
----------- ---------- ---------- -------- -----------
Total Utility Plant,
Including Intangibles $224,945,901 $20,070,139 $(1,139,377) $ - $243,876,663
=========== ========== ========== ======== ===========
NONUTILITY PROPERTY,
Primarily liquefied
petroleum gas
equipment $ 4,644,280 $ 686,195 $ ( 45,775) $ - $ 5,284,700
=========== ========== ========== ======== ===========
</TABLE>
<PAGE> 51
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE V - GAS UTILITY PLANT (INCLUDING INTANGIBLES)
AND NONUTILITY PROPERTY
FOR THE YEAR ENDED SEPTEMBER 30, 1993
<CAPTION>
Col. A Col. B Col. C Col. D Col. E Col. F
Other
Balance At Changes - Balance
Beginning Additions Retirements Transfers- at End
Major Classification of Period at Cost or Sales Add (Deduct) of Period
- -------------------- ---------- --------- ---------- ------------ ---------
<S> <C> <C> <C> <C> <C>
GAS UTILITY PLANT:
Intangible $ 990,524 $ - $ - $ - $ 990,524
Tangible -
LNG Storage 21,118,585 71,514 ( 7,790) - 21,182,309
Transmission 57,056,630 3,052,525 (61,444) 2,508 60,050,219
Distribution 118,007,948 11,040,780 (110,836) (2,508) 128,935,384
General 12,295,308 1,341,374 (667,858) - 12,968,824
----------- ---------- ---------- -------- -----------
Total Plant
in Service $209,468,995 $15,506,193 $ (847,928) $ - $224,127,260
Construction work
in progress 1,291,691 (473,050) - - 818,641
----------- ---------- ---------- -------- -----------
Total Utility Plant,
Including Intangibles $210,760,686 $15,033,143 $ (847,928) $ - $224,945,901
=========== ========== ========== ======== ===========
NONUTILITY PROPERTY,
Primarily liquefied
petroleum gas
equipment $ 4,229,918 $ 435,716 $ ( 21,354) $ - $ 4,644,280
=========== ========== ========== ======== ===========
</TABLE>
<PAGE> 52
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE V - GAS UTILITY PLANT (INCLUDING INTANGIBLES)
AND NONUTILITY PROPERTY
FOR THE YEAR ENDED SEPTEMBER 30, 1992
<CAPTION>
Col. A Col. B Col. C Col. D Col. E Col. F
Other
Balance At Changes- Balance
Beginning Additions Retirements Transfers- at End
Major Classification of Period at Cost or Sales Add (Deduct) of Period
- -------------------- --------- --------- ----------- ------------ ---------
<S> <C> <C> <C> <C> <C>
GAS UTILITY PLANT:
Intangible $ 990,524 $ - $ - $ - $ 990,524
Tangible -
LNG Storage 20,987,206 131,379 - - 21,118,585
Transmission 45,618,775 11,446,507 ( 15,330) 6,678 57,056,630
Distribution 108,529,691 9,671,210 (186,275) (6,678) 118,007,948
General 11,506,653 1,009,225 (220,570) - 12,295,308
----------- ---------- -------- ------- -----------
Total Plant
in Service $187,632,849 $22,258,321 $(422,175) $ - $209,468,995
Construction work
in progress 245,794 1,045,897 - - 1,291,691
----------- ---------- -------- ------- -----------
Total Utility Plant,
Including
Intangibles $187,878,643 $23,304,218 $(422,175) $ - $210,760,686
=========== ========== ======== ======= ===========
NONUTILITY PROPERTY,
Primarily liquefied
petroleum gas
equipment $ 3,845,235 $ 468,682 $( 83,999) $ - $ 4,229,918
=========== ========== ======== ======= ===========
</TABLE>
<PAGE> 53
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE VI - RESERVES FOR DEPRECIATION AND AMORTIZATION
FOR THE YEAR ENDED SEPTEMBER 30, 1994
<CAPTION>
Col. A Col. B Col. C Col. D Col. E
Additions Deductions
------------------------------------ -------------------
Provision Charged to Cost of
Balance at Clearing Original Removal Balance
Beginning Operating Accounts & Salvage Cost and at End
Description of Period Expenses Other Income Recoveries Retired Transfers of Period
- ----------- ---------- -------- ------------- ---------- ------------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
GAS UTILITY PLANT:
Intangible $ 455,209 $ - $ - $ - $ - $ - $ 455,209
Tangible -
LNG Storage Plant 5,984,218 880,887 - - - - 6,865,105
Transmission 22,902,256 1,775,548 - 6,163 ( 9,188) ( 1,803) 24,672,976
Distribution 39,583,114 3,907,158 - 16,760 (250,226) ( 90,061) 43,166,745
General 3,477,908 809,838 49,866 38,102 (395,779) (106,022) 3,873,913
---------- --------- -------- ------- -------- -------- ----------
Total utility
plant, including
intangibles $72,402,705 $7,373,431 $ 49,866 $ 61,025 $(655,193) $(197,886) $79,033,948
========== ========= ======== ======== ======== ======== ==========
NONUTILITY PROPERTY,
primarily liquefied
petroleum gas $ 2,195,827 $ - $ 290,516 $ - $( 45,775) $( 23,283) $ 2,417,285
========== ========= ======== ======== ======== ======== ==========
</TABLE>
<PAGE> 54
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE VI - RESERVES FOR DEPRECIATION AND AMORTIZATION
FOR THE YEAR ENDED SEPTEMBER 30, 1993
<CAPTION>
Col. A Col. B Col. C Col. D Col. E
Additions Deductions
--------------------------------- ------------------------
Provision Charged to Cost of
Balance at Clearing Original Removal Balance
Beginning Operating Accounts & Salvage Cost and at End
Description of Period Expenses Other Income Recoveries Retired Transfers of Period
- ----------- ---------- --------- ------------ ---------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
GAS UTILITY PLANT:
Intangible $ 455,209 $ - $ - $ - $ - $ - $ 455,209
Tangible -
LNG Storage Plant 5,113,100 878,908 - - ( 7,790) - 5,984,218
Transmission 21,289,574 1,688,334 - 4,106 ( 61,444) (18,314) 22,902,256
Distribution 36,165,040 3,588,824 - 12,536 (110,836) (72,450) 39,583,114
General 3,325,475 735,198 45,871 43,922 (667,858) ( 4,700) 3,477,908
---------- --------- --------- ------- -------- ------- ----------
Total utility
plant, including
intangibles $66,348,398 $6,891,264 $ 45,871 $ 60,564 $(847,928) $(95,464) $72,402,705
========== ========= ========= ======= ======== ======= ==========
NONUTILITY PROPERTY,
primarily liquefied
petroleum gas $ 1,981,793 $ - $ 250,880 $ - $( 21,354) $(15,492) $ 2,195,827
========== ========= ========= ======= ======== ======= ==========
</TABLE>
<PAGE> 55
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE VI - RESERVES FOR DEPRECIATION AND AMORTIZATION
FOR THE YEAR ENDED SEPTEMBER 30, 1992
<CAPTION>
Col. A Col. B Col. C Col. D Col. E
Additions Deductions
------------------------------------- -------------------- ---------
Provision Charged to Cost of
Balance at Clearing Original Removal Balance
Beginning Operating Accounts & Salvage Cost and at End
Description of period Expenses Other Income Recoveries Retired Transfers of Period
- ----------- ---------- ---------- ------------ ---------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
GAS UTILITY PLANT:
Intangible $ 455,209 $ - $ - $ - $ - $ - $ 455,209
Tangible -
LNG Storage
Plant 4,238,718 874,382 - - - - 5,113,100
Transmission 19,975,516 1,327,131 - 2,434 ( 15,330) ( 178) 21,289,574
Distribution 33,125,261 3,285,942 - 3,629 (186,275) ( 63,517) 36,165,040
General 2,878,444 637,681 40,987 9,632 (220,570) ( 20,698) 3,325,475
---------- --------- -------- -------- -------- -------- ----------
Total utility
plant, including
intangibles $60,673,148 $ 6,125,136 $ 40,987 $ 15,695 $(422,175) $( 84,393) $66,348,398
========== ========== ======== ======== ======== ======== ==========
NONUTILITY PROPERTY,
primarily
liquefied
petroleum gas $ 1,863,900 $ - $ 226,188 $ - $( 83,999) $( 24,296) $ 1,981,793
========== =========== ======== ======== ======== ======== ==========
</TABLE>
<PAGE> 56
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 AND 1992
<CAPTION>
Col. A Col. B Col. C Col. D Col. E
Additions
Balance at Charged to Balance
Beginning Operating Other Deductions At End
Description of Period Expenses Income (Note 1) of Period
- ----------- ---------- --------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
DEDUCTED IN BALANCE SHEET FROM ASSET TO
WHICH IT APPLIES: Allowance for
doubtful accounts
1994 $ 434,375 $ 328,840 $67,346 $414,513 $ 416,048
========= ======== ====== ======= =========
1993 $ 392,321 $ 218,702 $62,790 $239,438 $ 434,375
========= ======== ====== ======= =========
1992 $ 317,530 $ 73,376 $47,712 $ 46,297 $ 392,321
========= ======== ====== ======= =========
Note 1:
Deductions represent uncollectible accounts written off,
net of recoveries, as follows -
1994 1993 1992
---- ---- ----
Write-off of accounts considered to be uncollectible $505,933 $332,051 $294,084
Less - Recoveries on accounts previously written off 91,480 92,613 247,787
------- ------- -------
$414,513 $239,438 $ 46,297
======= ======= =======
</TABLE>
<PAGE> 57
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE IX - SHORT-TERM BORROWINGS
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 AND 1992
<CAPTION>
Column A Column B Column C Column D Column E Column F
Maximum Average Weighted
Amount Amount Average
Balance Weighted Outstanding Outstanding Interest Rate
Category of Aggregate At End Average During During During
Short-Term Borrowings Of Period Interest Rate The Period The Period The Period
- --------------------- --------- ------------- ----------- ----------- -------------
<S> <C> <C> <C> <C> <C> (A) (B)
September 30, 1994 -
Bankers' Acceptances &
Notes Payable to Banks $26,000,000 5.29% $27,500,000 $17,221,370 4.0%
September 30, 1993 -
Bankers' Acceptances &
Notes Payable to Banks $15,500,000 3.5% $40,500,000 $18,549,315 3.7%
September 30, 1992
Bankers' Acceptances &
Notes Payable to Banks $22,500,000 3.8% $22,500,000 $ 8,106,849 4.8%
(A) Average amount outstanding during the period was computed by dividing the total
of daily outstanding principal balances by 365.
(B) Weighted average interest rate for the year is computed by dividing the actual
short-term interest expense by the average short-term debt outstanding during
the period.
</TABLE>
<PAGE> 58
<TABLE>
NORTH CAROLINA NATURAL GAS CORPORATION AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED SEPTEMBER 30, 1994, 1993 AND 1992
<CAPTION>
Column A Column B
Charged to Costs and Expenses
---------------------------------------
Item 1994 1993 1992
- ------------------------ ---------- ---------- ---------
<S> <C> <C> <C>
Maintenance and repairs $2,738,814 $2,872,565 $3,183,799
Depreciation and amortization of
intangible assets, preoperating
costs and similar deferrals $ $ * $ *
Taxes, other than payroll and
income taxes:
Gross Receipts $5,078,960 $5,295,817 $4,779,107
Royalties $ * $ * $ *
Advertising costs $ * $ * $ *
* Less than 1% of total revenues.
</TABLE>
<PAGE> 59
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To the Stockholders and 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 September 30, 1994 and
1993, and the related consolidated statements of income, retained
earnings, and cash flows for each of the three years ended September
30, 1994. 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 generally accepted auditing
standards. 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 September
30, 1994 and 1993, and the results of their operations and their cash
flows for each of the three years ended September 30, 1994, in
conformity with generally accepted accounting principles.
As explained in Notes 3 and 6 to the consolidated financial statements,
effective October 1, 1993, the Company changed its methods of accounting
for income taxes and postretirement benefits other than pensions.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole period. The schedules listed in
the index of financial statements are presented for purposes of
complying with the Securities and Exchange Commission's rules and
are not part of the basic financial statements. These schedules have
been subjected to the auditing procedures applied in the audit of the
basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein
in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Atlanta, Georgia
November 9, 1994
<PAGE> 60
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
and Exchange Act of 1934, the Registrant has duly caused this Report to be
signed on its behalf by the undersigned, thereunto duly authorized.
NORTH CAROLINA NATURAL GAS CORPORATION
AND SUBSIDIARIES
(Registrant)
By: s/Calvin B. Wells
------------------
Calvin B. Wells
Chairman, President and
Chief Executive Officer
December 13, 1994:
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the date indicated.
Signature Title
--------- -------
s/Calvin B. Wells Chairman, President, Chief Executive
- ----------------------------- (Principal Executive Officer)
Calvin B. Wells
s/Gerald A. Teele Senior Vice President and Chief
- ----------------------------- Financial Officer
Gerald A. Teele (Principal Financial Officer)
s/Charles W. Siska, Jr. Controller
- ----------------------------- (Principal Accounting Officer)
Charles W. Siska, Jr.
s/ George T. Clark, Jr. s/William H. Prestage
- ----------------------------- ----------------------------
George T. Clark, Jr.-Director William H. Prestage-Director
s/C. Felix Harvey s/Paul A. DelaCourt
- ----------------------------- ----------------------------
C. Felix Harvey-Director Paul A. DelaCourt-Director
s/Richard F. Waid s/Hector MacLean
- ----------------------------- ----------------------------
Richard F. Waid-Director Hector MacLean-Director
<PAGE> 61
NORTH CAROLINA NATURAL GAS CORPORATION
INDEX OF EXHIBITS
The following exhibits are filed as part of this 1994 Form 10-K report.
Those exhibits previously filed and incorporated herein by reference are
identified below by a note reference to the previous filing.
Exhibit
Number
3-1 - Certificate of Incorporation and By-Laws. (1)
3-2 - Amendments of Certificate of Incorporation and By-Laws. (4)
3-3 - Amendment of Certificate of Incorporation. (10)
4-1 - Indenture dated as of September 1, 1984, covering 12 7/8%
Debentures Series A due September 1, 1996. (3)
4-2 - First Supplemental Indenture dated as of June 15, 1986,
supplementing Indenture dated as of September 1, 1984,
and creating 8.75% Debentures, Series B due June 15, 2001.
(6)
4-3 - Second Supplemental Indenture dated as of November 1,
1991, supplementing Indenture dated as of September 1,
1984, and creating 9.21% Debentures, Series C due November
15, 2011. (10)
10-1 - Service Agreement dated August 31, 1967, with
Transcontinental Gas Pipe Line Corporation covering
storage service under Rate Schedule GSS. (1)
10-2 - Service Agreement dated August 2, 1974, with
Transcontinental Gas Pipe Line Corporation covering
storage service under Rate Schedule LG-A. (1)
10-3 - Precedent Agreement to provide Contract Demand Service
of 25,000 Dt/day dated December 19, 1988, with Columbia
Gas Transmission Corporation. (7)
10-4 - Contract Demand Service Agreement dated November 1, 1989,
with Columbia Gas Transmission Corporation.(8)
10-5 - Firm Seasonal Transportation Agreement dated July 2, 1990,
with Transcontinental Gas Pipe Line Corporation.(8)
10-6 - Service Agreement dated August 1, 1991, with
Transcontinental Gas Pipeline Corporation covering
storage service under Rate Schedule WSS (9)
10-7 - Firm Sales Agreement with Transcontinental Gas Pipe Line
Corporation dated August 1, 1991 covering 54,043 Mcf per
day.(9)
<PAGE> 62
Index of Exhibits (Continued)
10-8 - Firm Transportation Agreement with Transcontinental Gas
Pipe Line Corporation dated February 1, 1991 for 141,000
Mcf per day. (10)
10-9 - Supplemental Retirement Benefit Agreement dated January
13, 1981. (2)
10-10 - Employment Agreements executed in 1985 with certain
Executive Officers. (5)
10-11 - Employment Agreements executed in 1986 with certain
Executive Officers. (6)
10-15 - Natural Gas Service Agreement dated January 9, 1992 with
the City of Wilson. (10)
10-16 - Natural Gas Service Agreement dated January 13, 1992 with
the City of Rocky Mount. (10)
10-17 - Service Area Territory Agreement dated January 13, 1992
with the City of Rocky Mount. (10)
10-18 - Natural Gas Service Agreement dated March 12, 1992 with
the Greenville Utilities Commission. (10)
10-19 - Natural Gas Service Agreement dated March 27, 1992 with
the City of Monroe. (10)
10-20 - Amendment to Natural Gas Service Agreement dated March 27,
1992 with the City of Greenville Utilities Commission.
10-21 - Amendment to Natural Gas Service Agreement dated January
13, 1992 with the City of Rocky Mount.
24 - Consent of Experts
27 - Financial Data Schedule
NOTES:
(1) Filed as exhibits to Form 10-K report for fiscal year ended
September 30, 1980.
(2) Filed as exhibits to Form 10-K report for fiscal year
ended September 30, 1981.
(3) Filed as exhibit to Form 10-K report for fiscal year
ended September 30, 1984.
(4) Filed as exhibits to Form 8-K report dated February 6, 1985.
<PAGE> 63
Index of Exhibits (Continued)
(5) Filed as exhibit to Form 10-K report for fiscal year ended
September 30, 1985.
(6) Filed as exhibit to Form 10-K report for fiscal year ended
September 30, 1986.
(7) Filed as exhibit to Form 10-K report for fiscal year ended
September 30, 1989.
(8) Filed as exhibit to Form 10-K report for fiscal year ended
September 30, 1990.
(9) Filed as exhibit to Form 10-K report for fiscal year ended
September 30, 1991.
(10) Filed as exhibit to Form 10-K report for fiscal year ended
September 30, 1992.
<PAGE> 64
SECOND AMENDMENT TO Exhibit 10-20
NATURAL GAS SERVICE AGREEMENT BETWEEN Page 1 of 2
GREENVILLE UTILITIES COMMISSION, GREENVILLE, N.C.
AND
NORTH CAROLINA NATURAL GAS CORPORATION
This Second Amendment entered into to be effective on the 1st day of
January, 1994, between Greenville Utilities Commission, Greenville,
N.C., (as "Customer") and North Carolina Natural Gas Corporation, a
Delaware corporation (as "Company"),
W I T N E S S E T H:
WHEREAS, Customer and Company are parties to a certain "Natural Gas
Service Agreement By and Between Greenville Utilities Commission,
Greenville, N.C. and North Carolina Natural Gas Corporation" dated
March 12, 1992 ("the Agreement"); and
WHEREAS, Company and Customer wish to amend that contract as more
fully set forth herein;
NOW, THEREFORE, in consideration of the premises and mutual covenants
herein and in the Agreement, Company and Customer agree as follows:
1. Section 2.01 is deleted in its entirety and the following is
substituted therefor:
2.01 Subject to the terms and provisions of this Agreement,
Company agrees to sell and deliver to Customer and
Customer agrees to purchase and receive from Company,
Customer's natural gas requirements, excluding that
portion of Customer's requirements which are transported
pursuant to Article III below. Customer agrees that the
maximum quantity of gas that Company is required to
deliver, either by sale or transportation, shall be
11,000 dekatherms ("Dth") per day and 550 Dth per hour.
For purposes of computing the Demand Charge under Rate
Schedules RE-2 and T-6, the foregoing maximum daily
quantity, subject to adjustments as provided herein,
shall constitute the Contract Demand, during the
respective periods to which each maximum is applicable,
and Customer agrees to pay Company therefor as provided
in the applicable rate schedule.
2. This Second Amendment shall become effective on January 1, 1994.
3. Except as specifically provided herein, the Agreement shall
continue in force and affect as previously written.
<PAGE> 65
Exhibit 10-20
Page 2 of 2
IN WITNESS WHEREOF, this instrument is executed effective as of the
day and year first written above.
GREENVILLE UTILITIES COMMISSION
GREENVILLE, N.C.
s/Malcolm A. Greene
--------------------------------
Malcolm A. Greene
Title: General Manager
NORTH CAROLINA NATURAL GAS COPRORATION
s/Calvin B. Wells
--------------------------------
Calvin B. Wells
Title: President
<PAGE> 66
FIRST AMENDMENT TO Exhibit 10-21
NATURAL GAS SERVICE AGREEMENT BETWEEN Page 1 of 2
THE CITY OF ROCKY MOUNT, NC
AND
NORTH CAROLINA NATURAL GAS CORPORATION
This First Amendment entered into to be effective on the 1st day
of January, 1994, between The City of Rocky Mount, North Carolina,
(as "Customer") and North Carolina Natural Gas Corporation, a
Delaware corporation (as "Company"),
WITNESSETH:
WHEREAS, Customer and Company are parties to a certain "Natural Gas
Service Agreement By and Between The City of Rocky Mount, North
Carolina and North Carolina Natural Gas Corporation" dated January
13, 1992 ("the Agreement"); and
WHEREAS, Company and Customer wish to amend that contract as more
fully set forth herein;
NOW, THEREFORE, in consideration of the premises and mutual covenants herein
and in the Agreement, Company and Customer agree as follows:
1. Section 2.01 is deleted in its entirety and the following
is substituted therefor:
2.01 Subject to the terms and provisions of this Agreement,
Company agrees to sell and deliver to Customer and
Customer agrees to purchase and receive from Company,
Customer's natural gas requirements, excluding that
portion of Customer's requirements which are
transported pursuant to Article III below. Customer
agrees that the maximum quantity of gas that Company
is required to deliver, either by sale or
transportation, shall be 18,000 dekatherms ("Dth") per
day and 1200 Dth per hour. For purposes of computing
the Demand Charge under Rate Schedules RE-2 and T-6,
the foregoing maximum daily quantity, subject to
adjustments as provided herein, shall constitute the
Contract Demand, during the respective periods to
which each maximum is applicable, and Customer agrees
to pay Company therefor as provided in the applicable
rate schedule.
2. This First Amendment shall become effective on January 1, 1994.
3. Except as specifically provided herein, the Agreement shall
continue in force and affect as previously written.
<PAGE> 67
Exhibit 10-21
Page 2 of 2
IN WITNESS WHEREOF, this instrument is executed effective as of the
day and year first written above.
CITY OF ROCKY MOUNT, N.C.
ATTEST: s/Jean M. Bailey s/Frederick E. Turnage
City Clerk ----------------------------
Title: Mayor
NORTH CAROLINA NATURAL GAS
CORPORATION
s/Calvin B. Wells
----------------------------
Title: President
<PAGE> 68
Exhibit 24
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports included in this Form 10-K, into the Company's previously
filed Registration Statement File No. 33-34779.
ARTHUR ANDERSEN LLP
Atlanta, Georgia
December 13, 1994
<PAGE> 69
<TABLE>
Exhibit 27
<CAPTION>
Financial Data Schedule
(In Thousands Except Per Share Amounts)
Item Number Item Description Amount
<S> <C> <C>
1 Total net utility Plant $ 164,843
2 Other property and investments 2,957
3 Total current assets 35,741
4 Total deferred charges 1,546
5 Balancing amount for total assets -0-
6 Total assets 205,087
7 Common stock 15,916
8 Capital surplus, paid in 25,499
9 Retained earnings 44,984
10 Total common stockholders equity 86,399
11 Preferred stock subject to mandatory -0-
redemption
12 Preferred stock not subject to -0-
mandatory redemption
13 Long-term debt, net 37,000
14 Short-term notes 26,000
15 Notes payable -0-
16 Commercial paper -0-
17 Long-term debt - current portion 2,000
18 Preferred stock - current portion -0-
19 Obligations under capital leases -0-
20 Obligations under capital leases -0-
--current portion
21 Balancing amount for capitalization 53,688
and liabilities
22 Total capitalization and liabilities 205,087
23 Gross operating revenue 160,337
24 Federal and state income taxes 6,318
expense
25 Other operating expenses 139,616
26 Total operating expenses 145,934
27 Operating income (loss) 14,403
28 Other income (loss), net 802
29 Income before interest charges 15,205
30 Total interest charges 4,055
31 Net income 11,150
32 Preferred stock dividends -0-
33 Earnings available for common stock 11,150
34 Common stock dividends 7,216
35 Total annual interest charges on -0-
all bonds
36 Cash flow from operations 19,601
37 Earnings per share - primary $ 1.76
38 Earnings per share - fully diluted $ 1.76
</TABLE>
