<PAGE> 1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
<TABLE>
<CAPTION>
(MARK ONE)
<C> <S>
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
(NO FEE REQUIRED)
FOR THE FISCAL YEAR ENDED OCTOBER 31, 1998
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____________
</TABLE>
COMMISSION FILE NUMBER 1-6196
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PIEDMONT NATURAL GAS COMPANY, INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
NORTH CAROLINA
(State or other jurisdiction of 56-0556998
incorporation or organization) (I.R.S. Employer Identification No.)
1915 REXFORD ROAD,
CHARLOTTE, NORTH CAROLINA 28211
(Address of principal executive offices) (Zip Code)
</TABLE>
Registrant's telephone number, including area code (704) 364-3120
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
<TABLE>
<CAPTION>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
<S> <C>
Common Stock, no par value New York Stock Exchange
</TABLE>
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No __
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]
State the aggregate market value of the voting stock held by nonaffiliates
of the registrant as of January 14, 1999.
Common Stock, no par value -- $951,615,126
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
CLASS OUTSTANDING AT JANUARY 14, 1999
----- -------------------------------
<S> <C>
Common Stock, no par value 30,820,728
</TABLE>
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Shareholders on
February 26, 1999, are incorporated by reference into Part III.
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<PAGE> 2
PIEDMONT NATURAL GAS COMPANY, INC.
1998 FORM 10-K ANNUAL REPORT
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TABLE OF CONTENTS
Page
----
[S] [C]
Part I.
Item 1. Business 1
Item 2. Properties 6
Item 3. Legal Proceedings 6
Item 4. Submission of Matters to a Vote of Security Holders 6
Part II.
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 7
Item 6. Selected Financial Data 8
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 8
Item 8. Financial Statements and Supplementary Data 21
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 44
Part III.
Item 10. Directors and Executive Officers of the Registrant 45
Item 11. Executive Compensation 47
Item 12. Security Ownership of Certain Beneficial Owners
and Management 48
Item 13. Certain Relationships and Related Transactions 48
Part IV.
Item 14. Exhibits, Financial Statement Schedule, and
Reports on Form 8-K 49
Signatures 57
<PAGE> 3
PART I
Item 1. Business
Piedmont Natural Gas Company, Inc. (the Company), incorporated in
1950, is an energy and services company primarily engaged in the distribution
and sale of natural gas and the sale of propane to over 673,000 residential,
commercial and industrial customers in North Carolina, South Carolina and
Tennessee.
The Company is the second-largest natural gas utility in the
southeast, serving over 625,000 customers. The Company and its non-utility
subsidiaries and divisions are also engaged in acquiring, marketing and
arranging for the transportation and storage of natural gas for large-volume
purchasers, in retailing residential and commercial appliances and in the sale
of propane to over 48,000 customers in the Company's three-state service area.
In the Carolinas, the service area is comprised of numerous cities,
towns and communities including Anderson, Greenville and Spartanburg in South
Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point,
Burlington and Hickory in North Carolina. In Tennessee, the service area is the
metropolitan area of Nashville, including portions of eight adjoining counties.
The Company's propane market is in and adjacent to its natural gas market in
all three states.
Operating revenues shown in the consolidated financial statements
represent revenues from utility operations only. Such revenues totaled
$765,277,000 for the year ended October 31, 1998, of which 42% was from
residential customers, 25% from commercial customers, 21% from industrial
customers, 11% from secondary market sales and 1% from various sources.
Revenues from non-utility operations, less related costs and income taxes, are
shown in the consolidated financial statements in other income. Non-utility
revenues as a percentage of total revenues, including utility operations, were
5% in 1998. No single non-utility activity accounted for greater than 4% of
total revenues. Income from non-utility activities as a percentage of total net
income was 1% in 1998. No single non-utility activity accounted for more than
2% of net income.
The Company is principally engaged in the gas distribution industry
and has no other reportable industry segments.
The Company's utility operations are subject to regulation by the
North Carolina Utilities Commission (NCUC) and the Tennessee Regulatory
Authority (TRA) as to the issuance of securities, and by those commissions and
by the Public Service Commission of South Carolina (PSCSC) as to rates, service
area, adequacy of service, safety standards, extensions and abandonment
1
<PAGE> 4
of facilities, accounting and depreciation. The Company is also subject to or
affected by various federal regulations.
The Company holds non-exclusive franchises for natural gas service in
all communities where required, with expiration dates from 1999 to 2048. The
earliest date at which a franchise for a major service area expires is May 1999
and renewal is currently being arranged. The franchises are adequate for
operation of the gas distribution business and do not contain restrictions
which are of a materially burdensome nature. In most cases, the loss of a
franchise would not have a material effect on operations. The Company has never
failed to obtain the renewal of a franchise; however, this is not necessarily
indicative of future action.
The Company's utility business and its non-utility propane activities
are seasonal in nature as variations in weather conditions generally result in
greater earnings during the winter months. The Company normally injects natural
gas into storage during summer months (principally April 1 through October 31)
for withdrawal from storage during winter months (principally November 1
through March 31) when customer demand is higher. During 1998, the amount of
natural gas in storage varied from 7.1 million dekatherms (one dekatherm equals
1,000,000 BTUs) to 17.5 million dekatherms, and the aggregate commodity cost of
this gas in storage varied from $16,261,000 to $41,691,000.
The following is a five-year comparison of gas sales and other
statistics for the years ended October 31, 1994 through 1998:
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES (in thousands):
Sales and Transportation:
Residential $323,777 $319,722 $292,010 $229,546 $240,314
Commercial 189,341 195,862 180,415 135,933 165,805
Industrial 162,336 191,565 184,118 133,205 165,989
For Resale 87 266 2,748 3,323 815
-------- -------- -------- -------- --------
Total 675,541 707,415 659,291 502,007 572,923
Secondary Market Sales 86,333 64,411 22,152 -- --
Miscellaneous 3,403 3,691 3,612 3,216 2,431
-------- -------- -------- -------- --------
Total $765,277 $775,517 $685,055 $505,223 $575,354
======== ======== ======== ======== ========
GAS VOLUMES - DEKATHERMS (in thousands):
System Throughput:
Residential 41,142 38,339 43,357 33,513 36,093
Commercial 28,528 28,476 31,040 22,867 28,931
Industrial 64,165 65,000 62,434 65,904 60,914
Power Generation 9,141 3,236 1,620 1,831 52
For Resale 17 27 581 1,478 140
-------- -------- -------- -------- -------
Total 142,993 135,078 139,032 125,593 126,130
======== ======== ======== ======== =======
Secondary Market Sales 33,953 24,547 9,724 -- --
</TABLE>
2
<PAGE> 5
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
NUMBER OF RETAIL CUSTOMERS BILLED (12 month average):
Residential 522,451 495,739 468,803 446,118 420,861
Commercial 63,878 62,258 59,905 57,803 56,147
Industrial 3,201 2,697 2,687 2,711 2,010
------- ------- ------- ------- -------
Total 589,530 560,694 531,395 506,632 479,018
======= ======= ======= ======= =======
AVERAGE PER RESIDENTIAL CUSTOMER:
Gas Used - Dekatherms 78.75 77.34 92.48 75.12 85.76
Revenue $ 619.73 $ 644.94 $622.88 $ 514.54 $ 571.00
Revenue Per Dekatherm $ 7.87 $ 8.34 $ 6.73 $ 6.85 $ 6.66
COST OF GAS (in thousands):
Natural Gas Purchased $337,400 $362,249 $327,968 $155,683 $242,609
Liquefied Petroleum Gas (LPG) -- 77 160 60 204
Transportation Gas Received (Not
Delivered) 339 (1,840) 1,024 (181) (616)
Natural Gas Withdrawn from
(Injected into) Storage, net (2,750) 2,597 (8,078) 6,094 4,106
Other Storage 333 318 (40) 860 1,058
Other Adjustments 107,100 97,264 73,099 85,051 93,214
-------- -------- -------- -------- --------
Total $442,422 $460,665 $394,133 $247,567 $340,575
======== ======== ======== ======== ========
COST OF GAS PER DEKATHERM OF GAS SOLD $ 3.45 $ 3.81 $ 3.17 $ 2.76 $ 3.29
SUPPLY AVAILABLE FOR DISTRIBUTION - DEKATHERMS (in thousands):
Natural Gas Purchased 138,870 129,797 127,799 86,372 106,556
LPG -- 10 121 13 52
Transportation Gas 42,091 32,026 24,550 41,589 22,299
Natural Gas Withdrawn from (Injected
into) Storage, net (3,301) (3) (1,142) (750) (1,646)
Other Storage 27 16 16 (15) 25
Company Use (110) (121) (152) (118) (159)
-------- -------- -------- -------- --------
Total 177,577 161,725 151,192 127,091 127,127
======== ======== ======== ======== ========
UTILITY CAPITAL EXPENDITURES (in thousands) $ 93,513 $ 93,482 $ 98,258 $ 100,825 $ 105,787
GAS MAINS - MILES OF 3" EQUIVALENT 18,200 17,800 16,900 16,700 16,300
DEGREE DAYS - SYSTEM AVERAGE:
Actual 3,339 3,471 3,993 3,144 3,567
Normal 3,612 3,611 3,606 3,617 3,630
Percentage of Actual to Normal 92% 96% 111% 87% 98%
PROPANE OPERATIONS:
Revenues (in thousands) $ 30,789 $ 36,816 $ 44,046 $ 33,414 $ 34,972
Volumes Sold (gallons in millions) 34.6 36.7 49.3 38.4 41.3
Customers (at year end) 48,000 48,100 48,100 48,500 46,900
</TABLE>
During 1998, the Company delivered 143 million dekatherms of natural
gas to its customers, of which 42 million dekatherms were transported for large
industrial customers. This compares with 135.1 million dekatherms delivered in
1997, of which 32.7 million dekatherms were transported. In addition to this
system throughput, secondary-market sales volumes increased to 34 million
dekatherms in 1998 compared with 24.5 million dekatherms in 1997.
Sales to temperature-sensitive customers, whose consumption varies
with the weather, were 69.7 million dekatherms in 1998,
3
<PAGE> 6
compared with 66.8 million dekatherms in 1997. Weather which was 8% warmer than
normal was experienced in 1998, compared with 4% warmer-than-normal weather in
1997. The Company sold or transported 9.1 million dekatherms to power
generation customers in 1998, compared with 3.2 million dekatherms in 1997. The
Company sold or transported 64.2 million dekatherms to industrial users in
1998, compared with 65 million dekatherms in 1997. Industrial sales are the
most price-sensitive of the Company's markets and are largely a function of the
Company's ability to obtain supplies of natural gas competitively priced with
other industrial fuels.
Except as set forth below, all natural gas distributed is transported
to the Company by one or more of eight interstate pipelines, Transcontinental
Gas Pipe Line Corporation (Transco), Tennessee Gas Pipeline Company (Tennessee
Pipeline), Texas Eastern Transmission Corporation (Texas Eastern), Columbia Gas
Transmission Company (Columbia Gas), Columbia Gulf Transmission Corporation
(Columbia Gulf), National Fuel Gas Supply Corporation (National Fuel), Texas
Gas Transmission Corporation (Texas Gas) and CNG Transmission Corporation
(CNG).
As of November 1, 1998, the Company has contracted to purchase the
following pipeline long-term firm transportation capacity in dekatherms of
daily deliverability:
<TABLE>
<S> <C>
Transco (including certain upstream arrangements with CNG, Texas Gas and National Fuel) 487,800
Tennessee Pipeline 74,100
Texas Eastern 1,700
Columbia Gas (through arrangements with Transco and Columbia Gulf) 36,000
Columbia Gulf 5,000
-------
Total 604,600
=======
</TABLE>
The Company has the following additional long-term peaking capacity in
dekatherms of daily deliverability through local peaking facilities, storage
contracts and third-party city gate arrangements to meet the firm demands of
its markets. This availability varies from five days to one year.
<TABLE>
<S> <C>
Liquefied Natural Gas (LNG) 230,000
Liquefied Petroleum Gas 8,000
Transco Storage 86,000
Columbia Gas Storage 91,200
Tennessee Pipeline Storage 55,900
CNG Storage 7,000
Cove Point LNG 24,000
Third-Party City Gate Arrangements 47,100
-------
Total 549,200
=======
</TABLE>
The Company utilizes a "best cost" gas purchasing philosophy that
seeks to purchase gas on a short- or long-term basis by weighing cost against
supply security and reliability factors. Of the 138.9 million dekatherms of
natural gas purchased in 1998, approximately 12% was purchased under short-term
contracts of less than one year, 17% under contracts of from one to three years
and 71% under contracts of over three years.
4
<PAGE> 7
The Company owns or has under contract 22.8 million dekatherms of
storage capacity, either in the form of underground storage or LNG. This
capability is used to supplement regular pipeline supplies on colder winter
days when demand increases.
For further information on gas supply and regulation, see "Gas Supply
and Regulatory Proceedings" included in Management's Discussion and Analysis of
Financial Condition and Results of Operations in Item 7 of this report.
Approximately 36% of annual gas deliveries in 1998 were made to
industrial or large commercial customers who have the capability to burn a fuel
other than natural gas. The alternative fuels are primarily fuel oil and some
propane and, to a much lesser extent, coal or wood. The ability to maintain or
increase deliveries of gas to these customers depends on a number of factors,
including weather conditions, governmental regulations, the price of gas from
suppliers and the price of alternate fuels. Under existing regulations of the
Federal Energy Regulatory Commission (FERC), it is possible for certain large
commercial or industrial customers located in proximity to the interstate
pipelines delivering gas to the Company to bypass the Company and take delivery
of gas directly from the pipeline or from a third party connecting with the
pipeline. To date, the Company has experienced only minimal bypass activity in
part because of the Company's ability to negotiate competitive rates and
service terms. The future level of bypass activity cannot be predicted.
In the residential and small commercial markets, natural gas competes
primarily with electricity for such uses as cooking and water heating and with
electricity and fuel oil for space heating.
During 1998, the Company's largest customer contributed $23,898,000,
or 3%, to total revenues.
The amount of research and development costs incurred in connection
with Company-sponsored research is immaterial. The Company contributes to gas
industry-sponsored research projects; however, the amounts contributed to such
projects are minimal.
Compliance with federal, state and local environmental protection laws
had no material effect on capital expenditures, earnings or competitive
position during 1998. For further information on environmental issues, see
"Environmental Matters" included in Management's Discussion and Analysis of
Financial Condition and Results of Operations in Item 7 of this report.
5
<PAGE> 8
As of October 31, 1998, the Company had 1,841 employees, compared with
1,904 employees as of October 31, 1997.
Item 2. Properties
The Company's properties consist primarily of distribution systems and
related facilities to serve its utility customers. The Company has constructed
and owns approximately 504 miles of lateral pipelines up to 16 inches in
diameter which connect the distribution systems of the Company with the
transmission systems of its pipeline suppliers. Natural gas is distributed
through approximately 18,200 miles (three-inch equivalent) of distribution
mains. The lateral pipelines and distribution mains are located on or under
public streets and highways, or private property with the permission of the
individual owners.
The Company either owns or leases for varying periods district and
regional offices for its utility and non-utility operations.
Item 3. Legal Proceedings
There are a number of lawsuits pending against the Company for damages
alleged to have been caused by negligence of employees. The Company has
liability insurance which it believes is adequate to cover any material
judgments which may result from these lawsuits.
Item 4. Submission of Matters to a Vote of Security Holders
None.
6
<PAGE> 9
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters
(a) The Company's Common Stock is traded on the New York Stock Exchange
(NYSE). The following table provides information with respect to the high and
low sales prices on the NYSE (symbol PNY) for each quarterly period for the
years ended October 31, 1998 and 1997.
<TABLE>
<CAPTION>
1998 High Low 1997 High Low
- ---------- ---- --- ---------- ---- ---
<S> <C> <C> <C> <C> <C>
January 31 36 7/16 27 January 31 25 3/8 23
April 30 34 15/16 30 3/8 April 30 24 3/4 22
July 31 34 11/16 28 7/8 July 31 26 5/8 23 3/8
October 31 35 5/16 27 7/8 October 31 30 15/16 23 13/16
</TABLE>
(b) As of January 14, 1999, the Company's Common Stock was owned by
19,139 shareholders of record.
(c) Information with respect to quarterly dividends paid on Common
Stock for the years ended October 31, 1998 and 1997, is as follows:
<TABLE>
<CAPTION>
Dividends Paid Dividends Paid
1998 Per Share 1997 Per Share
- ---------- -------------- ---------- --------------
<S> <C> <C> <C>
January 31 30.5 cents January 31 29 cents
April 30 32.5 cents April 30 30.5 cents
July 31 32.5 cents July 31 30.5 cents
October 31 32.5 cents October 31 30.5 cents
</TABLE>
The Company's articles of incorporation and note agreements under which
long-term debt was issued contain provisions which restrict the amount of cash
dividends that may be paid on Common Stock. As of October 31, 1998, all of the
Company's retained earnings was free of such restrictions.
7
<PAGE> 10
Item 6. Selected Financial Data
Selected financial data for the years ended October 31, 1994 through
1998, is as follows:
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(in thousands except per share amounts)
<S> <C> <C> <C> <C> <C>
Margin $ 322,855 $ 314,852 $ 290,922 $257,656 $234,779
Operating Revenues $ 765,277 $ 775,517 $ 685,055 $505,223 $575,354
Net Income $ 60,313 $ 54,074 $ 48,562 $ 40,310 $ 35,506
Earnings per Share of Common Stock:
Basic $ 1.98 $ 1.81 $ 1.67 $ 1.45 $ 1.35
Diluted $ 1.96 $ 1.79 $ 1.66 $ 1.44 $ 1.34
Cash Dividends Per Share of Common Stock $ 1.28 $ 1.205 $ 1.145 $ 1.085 $ 1.025
Average Shares of Common Stock:
Basic 30,472 29,883 29,161 27,890 26,346
Diluted 30,717 30,229 29,213 28,002 26,542
Total Assets $1,162,844 $1,098,156 $1,067,086 $964,895 $889,233
Long-Term Debt (less current maturities) $ 371,000 $ 381,000 $ 391,000 $361,000 $313,000
Rate of Return on Average Common Equity 13.74% 13.42% 13.11% 12.27% 12.10%
Long-Term Debt to Total Capitalization Ratio 44.74% 47.58% 50.32% 50.42% 50.89%
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Liquidity and Capital Resources
The gas distribution business is highly weather sensitive and seasonal
and requires the use of short-term debt at times to meet working capital
requirements. This weather sensitivity and seasonality cause short-term cash
requirements to vary significantly during the year. Short-term debt is also used
to finance construction pending the issuance of long-term debt or equity.
The Company has committed bank lines of credit totaling $75 million to
finance cash requirements not generated internally. Additional uncommitted lines
are also available on an as needed, if available, basis. Borrowings under the
lines include bankers' acceptances, transactional borrowings and overnight
cost-plus loans based on the lending bank's cost of money, with a maximum rate
of the lending bank's commercial prime interest rate. Outstanding borrowings
against the lines of credit during 1998 ranged from zero to a high of $43
million and interest rates ranged from 5.18% to 6.12% during the year. At
October 31, 1998, $32 million of short-term debt was outstanding at a weighted
average interest rate of 5.55%.
8
<PAGE> 11
The Company had $381 million of long-term debt outstanding at October
31, 1998. Annual sinking fund requirements and maturities of this debt are $10
million in 1999 and 2000, $40 million in 2001, $10 million in 2002 and $55
million in 2003. Long-term debt retired in 1998 totaled $10 million.
At October 31, 1998, the Company's capitalization ratio consisted of
45% long-term debt and 55% common equity. The embedded cost of long-term debt at
that date was 8.28%. The return on average common equity in 1998 was 13.74%.
Cash provided from operations and from the issuance of Common Stock
through dividend reinvestment and stock purchase plans was sufficient to fund
capital expenditures of $94.6 million, payments of debt principal and interest
of $43.2 million and dividend payments to shareholders of $39 million.
The Company's capital expansion program is very important in meeting
the growth in the demand for natural gas evidenced by the growth in the customer
base. Capital expenditures for 1998 were $93.5 million for utility operations
and $1.1 million for non-utility activities. Capital expenditures totaling
$106.8 million for utility operations, primarily to serve customer growth, and
$2.3 million for non-utility activities are budgeted for 1999. In addition, an
estimated equity contribution of $18.7 million is required in mid-1999 in
connection with the construction of a liquified natural gas peak-demand facility
in which a subsidiary of the Company is a partner.
Competition and Accounting for Regulated Activities
The natural gas industry, including producers, pipelines and local gas
distribution companies (LDCs), has undergone significant changes in recent years
in moving toward a less-regulated marketplace. In response to the changing
competitive situation, the Company is assessing the nature of its business and
is exploring alternatives to the traditional utility role of purchase, sale and
transportation of natural gas. Non-traditional ratemaking initiatives and
market-based pricing of products and services will provide additional challenges
and opportunities for the Company. The Company anticipates that opportunities
for non-regulated sales will increase as competition intensifies and further
retail market unbundling occurs.
The Company accounts for its regulated activities in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of
9
<PAGE> 12
Regulation" (FAS 71). FAS 71 provides that rate-regulated public utilities
account for and report assets and liabilities consistent with the economic
effect of the manner in which independent third-party regulators establish
rates. In applying FAS 71, the Company has capitalized certain costs and
benefits as regulatory assets and liabilities, respectively, pursuant to orders
of state utility regulatory commissions, either in general rate proceedings or
expense deferral proceedings, in order to provide for recovery of or refunds to
utility customers in future periods. As competition increases and the Company is
further subjected to the impact of deregulation, the Company may not be able to
continue to apply FAS 71 to all or parts of its business. If this were to occur,
the Company would be required to apply accounting standards utilized by
non-regulated enterprises. At such time as the Company determines that the
provisions of FAS 71 no longer apply, costs previously deferred as regulatory
assets in the consolidated balance sheet would be eliminated, net of the
elimination of any regulatory liabilities. The composition and amount of
regulatory assets and liabilities are shown in Note 1 to the consolidated
financial statements.
While the Company believes the provisions of FAS 71 continue to apply
to its regulated operations, the changing nature of the business requires
continual assessment of the impact of those changes on its accounting policies.
Gas Supply and Regulatory Proceedings
To meet customer requirements, the Company must acquire sufficient gas
supplies and pipeline capacity to ensure delivery to its distribution system
while also ensuring that supply and capacity levels will allow it to remain
competitive. The Company has a diversified portfolio of local peaking
facilities, transportation and storage contracts with interstate pipelines and
supply contracts with major producers and marketers to satisfy the supply and
deliverability requirements of its customers.
In the Company's opinion, present rules and regulations of the North
Carolina Utilities Commission (NCUC), the Public Service Commission of South
Carolina (PSCSC) and the Tennessee Regulatory Authority (TRA) permit the pass
through of interstate pipeline capacity and storage service costs and similar
costs, as well as gas commodity costs from natural gas suppliers, that may be
incurred under orders or regulations of the Federal Energy Regulatory Commission
(FERC). The majority of the Company's natural gas supply is purchased from
producers and marketers in non-regulated transactions. The Company is permitted
to recover
10
<PAGE> 13
100% of its prudently incurred gas costs, subject to annual prudence reviews in
North Carolina and South Carolina covering historical twelve-month periods. For
the latest applicable periods, the NCUC and the PSCSC found the Company to be
prudent in its gas purchasing practices and allowed 100% recovery of its gas
costs.
In 1996, the TRA approved a two-year experimental performance incentive
plan effective July 1, 1996. The plan eliminated annual prudence reviews and
established an incentive-sharing mechanism based on differences in the actual
cost of gas purchased and benchmark rates, together with income from marketing
transportation and storage capacity in the secondary market, subject to an
overall annual cap of $1.6 million on gains or losses by the Company. Secondary
market transactions include sales for resale, off-system sales, capacity release
and other interstate transactions designed to reduce fixed gas costs during
off-peak periods. The benefits of the incentive plan are the elimination of
annual gas purchase prudence reviews, reduction of gas costs for ratepayers and
potential earnings to shareholders by sharing in gas cost reductions. On August
18, 1998, the TRA orally approved the Company's application to evergreen or
automatically renew the performance incentive plan each year. A written order is
pending.
Secondary market transactions permit the Company to market short-term
gas supplies and transportation services by contract with wholesale or
off-system customers. These sales contribute the smallest per-unit margin to
earnings; however, the program allows the Company to act as a wholesale marketer
of natural gas and transportation capacity in order to generate operating margin
from sources not restricted by the capacity of the Company's retail distribution
system. In North Carolina, a sharing mechanism is in effect where 75% of any
margin earned is refunded to firm customers. Sales in Tennessee are included in
the rate-sharing mechanism under the performance incentive plan discussed above.
Approximately 36% of annual gas deliveries in 1998 were made to
industrial or large commercial customers who have the capability to burn a fuel
other than natural gas. The alternative fuels are primarily fuel oil and some
propane and, to a much lesser extent, coal or wood. The ability to maintain or
increase deliveries of gas to these customers depends on a number of factors,
including weather conditions, governmental regulations, the price of gas from
suppliers and the price of alternate fuels. Under existing regulations of the
FERC, it is possible for certain large commercial or industrial customers
11
<PAGE> 14
located in proximity to the interstate pipelines delivering gas to the Company
to bypass the Company and take delivery of gas directly from the pipeline or
from a third party connecting with the pipeline. To date, the Company has
experienced only minimal bypass activity in part because of the Company's
ability to negotiate competitive rates and service terms. The future level of
bypass activity cannot be predicted.
In 1996, the NCUC ordered the establishment of an expansion fund for
the Company and approved initial funding with supplier refunds due customers to
enable the extension of natural gas service into unserved areas of the state. As
of October 31, 1998, the North Carolina State Treasurer held $19.1 million in
the Company's expansion fund account. This amount along with other supplier
refunds, including interest earned to date, is included in restricted cash in
the consolidated balance sheet. The use of such funds will be at the discretion
of the NCUC as individual project applications for unserved areas are filed by
the Company and approved by the NCUC. As of October 31, 1998, no funds have been
used for expansion.
In June 1998, the Company filed a petition with the NCUC for approval
of an expansion project that would extend natural gas service to the counties of
Avery, Mitchell and Yancey which are currently without natural gas service. The
Company also requested authority to use $26.3 million in expansion fund money to
partially fund the estimated cost of the project of $31.9 million. In November
1998, the NCUC issued an order approving the Company's requests.
In November 1995, the PSCSC approved a general increase in the
Company's rates in South Carolina, effective November 7, 1995, of $7.8 million
annually. The rate increase was based on a return on common equity of 12.5%. The
Consumer Advocate for the State of South Carolina appealed the order of the
PSCSC. On August 31, 1998, the South Carolina Supreme Court ruled that the PSCSC
had failed to set forth sufficient findings of fact to support the 12.5% return.
The Supreme Court also ruled that the PSCSC erred in permitting the Company to
recover certain demand-side management (DSM) costs because the Company did not
provide a cost-benefit analysis with respect to these costs. The matter was
remanded to the PSCSC for further proceedings. On October 26, 1998, the PSCSC
issued its order on remand requiring the Company to reduce its rates effective
November 1, 1998, to eliminate annual DSM costs included in its rates. The
Company is to account for DSM costs incurred since implementation of the DSM
programs as a regulatory asset for recovery in future rates. The order also set
forth the PSCSC's findings and conclusions and an
12
<PAGE> 15
analysis of relevant factors to comply with the Supreme Court's remand with
respect to return on common equity. The PSCSC affirmed its allowance of the
12.5% return on common equity.
In December 1996, the TRA issued an order in a general rate case
proceeding permitting the Company to increase its margin in Tennessee, effective
January 1, 1997, by $4.4 million annually. The TRA's decision was confirmed by a
written decision in February 1997. The Tennessee Consumer Advocate filed several
pleadings with the TRA arguing, among other things, that the Company was not
entitled to recover the increased rates prior to the date of the TRA's February
order. All parties in this proceeding, including the Company, petitioned the TRA
to reconsider its February order. In June 1997, the TRA issued an order denying
all motions and upholding its previous orders. In August 1997, the Consumer
Advocate petitioned the Court of Appeals for a review of the TRA's orders. On
July 1, 1998, the Court of Appeals affirmed the TRA's February order.
Results of Operations
Net income for 1998 was $60.3 million, compared with $54.1 million in
1997 and $48.6 million in 1996. The increase in net income in 1998, compared
with 1997, was primarily due to regulatory rate changes which increased rates
and updated gas cost components, secondary market transactions, an increase in
interest income and decreases in operations and maintenance expenses, general
taxes and interest charges, partially offset by an increase in depreciation. The
increase in net income in 1997, compared with 1996, was primarily due to
regulatory rate changes which increased rates and updated gas cost components,
secondary market transactions and an increase in interest income, partially
offset by increases in operations and maintenance expenses, depreciation,
general taxes and utility interest charges. Compared with the prior year,
weather in the Company's service area was 4% warmer in 1998, 13% warmer in 1997
and 27% colder in 1996. Volumes of gas delivered to customers were 143 million
dekatherms in 1998, compared with 135.1 million dekatherms in 1997, an increase
of 6%, and 139 million dekatherms in 1996. In addition to this system
throughput, secondary-market sales volumes increased to 34 million dekatherms in
1998, compared with 24.5 million dekatherms in 1997 and 9.7 million dekatherms
in 1996.
Operating revenues were $765.3 million in 1998, $775.5 million in 1997
and $685.1 million in 1996. The decrease in operating revenues in 1998 from 1997
was primarily due to a reduction in the embedded cost of gas which is a
component of
13
<PAGE> 16
revenue, the shift from sales of gas to transportation on which there is no
commodity cost included in revenues and increased volumes in secondary market
sales which are at wholesale market rates rather than retail tariff rates. The
increase in operating revenues in 1997 over 1996 was primarily due to higher
rates from general rate increases in North Carolina and Tennessee and increased
volumes in secondary market sales. The weather normalization adjustment
mechanism (WNA) in effect in all three states is designed to offset the impact
that unusually cold or warm weather has on customer billings and margin. Weather
8% warmer than normal was experienced in 1998, compared with 4%
warmer-than-normal weather in 1997 and 11% colder-than-normal weather in 1996.
In the Company's general rate proceedings, the state regulatory
commissions authorize the Company to recover a margin (applicable rate less cost
of gas) on each unit of gas sold. Each commission has also authorized the
Company to negotiate lower rates to certain of its industrial customers when
necessary to remain competitive. The Company is permitted to recover margin
losses resulting from these negotiated transactions through rates. The ability
to recover such negotiated margin reductions is subject to continuing regulatory
approvals.
Cost of gas was $442.4 million in 1998, $460.7 million in 1997 and
$394.1 million in 1996. The decrease in 1998, compared with 1997, was primarily
due to decreases in embedded gas costs, the shift from sales to transportation
and increased volumes in secondary market sales which are at wholesale market
rates rather than retail tariff rates. The increase in 1997, compared with 1996,
was primarily due to increases in commodity costs billed to customers and
secondary market sales. Increases or decreases in purchased gas costs from
suppliers have no significant impact on margin as substantially all changes are
passed on to customers through purchased gas adjustment procedures.
Margin was $322.9 million in 1998, $314.9 million in 1997 and $290.9
million in 1996. The increases were primarily due to regulatory-approved changes
and rate increases, increased facility charges billed to a larger base of
customers due to growth and increased volumes of gas delivered, including
secondary market transactions and special contract sales. WNA surcharges of $5
million and $10.6 million were collected in 1998 and 1997, respectively,
compared with WNA credits of $11.6 million in 1996. The margin earned per
dekatherm of gas delivered on the system decreased by $.07 in 1998 from 1997 and
increased by $.21 in 1997 over 1996.
14
<PAGE> 17
Other operations and maintenance expenses were $119.6 million in 1998,
$126.8 million in 1997 and $121.6 million in 1996. The decrease in 1998 from
1997 was primarily due to decreases in payroll, rents, advertising and the
provision for uncollectibles, partially offset by increases in outside labor.
The increase in 1997 over 1996 was primarily due to increases in outside labor
and consulting fees, payroll and the provision for uncollectibles, partially
offset by a decrease in rents and leases. As part of a plan to reduce overall
operating expenses, the Company eliminated 93 positions in 1997 which reduced
the utility workforce by 5% from the employee count as of the end of 1996. The
workforce reduction plan resulted in a charge to operations expense of $1.8
million in the fourth quarter of 1997.
Depreciation expense increased from $36 million to $42.2 million over
the three-year period 1996 to 1998 primarily due to the growth in plant in
service.
General taxes increased from $31 million to $32.6 million over the
three-year period 1996 to 1998 primarily due to increases in property taxes
resulting from rate increases and additions to taxable property and state
franchise taxes.
Other income, net of income taxes, decreased to $2.3 million in 1998
from $5 million in 1996 primarily due to decreases in earnings from propane
operations and energy-marketing services. Such decreases were partially offset
by increases in earnings from merchandise and jobbing operations, interest
earned on temporary cash investments and the allowance for funds used during
construction.
Utility interest charges were $33.2 million in 1998, $34 million in
1997 and $31.1 million in 1996. The decrease in 1998, compared with 1997, was
primarily due to decreases in interest on long-term debt due to lower balances
outstanding, interest on short-term debt due to lower balances outstanding but
at slightly higher rates, and the portion of the allowance for funds used during
construction attributable to borrowed funds. The decreases were partially offset
by increases in interest on refunds due customers due to higher balances
outstanding. The increase in 1997, compared with 1996, was primarily due to
increases in the balances outstanding on long-term debt and increases in the
balances outstanding on refunds due customers, partially offset by interest on
short-term debt due to lower balances outstanding.
Environmental Matters
The Company has owned, leased or operated manufactured gas plant (MGP)
facilities at 12 sites in its three-state service area. In October 1997, the
Company entered into a settlement with a third party with respect to nine of
these sites. As of
15
<PAGE> 18
October 31, 1998, the Company had an environmental liability of $1.4 million for
the remaining three MGP sites not covered by the settlement. This liability is
based on a generic MGP site study as site-specific evaluations have not been
performed.
The Company is authorized by its three state regulatory commissions to
utilize deferral accounting, or the creation of a regulatory asset, for
expenditures made in connection with environmental matters. In connection with
the settlement noted above and the estimated liability for the three remaining
sites, the Company has recorded a regulatory asset of $6.6 million. As of
October 31, 1998, the Company had an additional regulatory asset in the amount
of $427,000, net of recoveries from customers, for other environmental costs,
primarily legal fees and engineering assessments.
Further evaluations of the three remaining sites could significantly
affect recorded amounts; however, the Company believes that the ultimate
resolution of these matters will not have a material adverse effect on financial
position or results of operations.
Accounting Pronouncements
Effective November 1, 1999, the Company will adopt SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (FAS 133). The
Company is currently evaluating the effects of FAS 133 on financial position and
results of operations.
Other Matters
Piedmont Energy Company (PEC), a wholly owned subsidiary of the
Company, has an equity interest in SouthStar Energy Services LLC (SouthStar), a
Delaware limited liability company formed in July 1998. SouthStar intends to
offer a combination of unregulated energy products and services to industrial,
commercial and residential customers in the southeast United States. The
products and services to be offered include natural gas, electricity, fuel oil
and propane, along with related retail services. Prior to May 1998, PEC was a
51% member of Resource Energy Services Company, L.L.C. (Resource Energy), a
North Carolina limited liability company. Resource Energy offered natural gas
acquisition, transportation and storage services to industrial users and other
utilities in the southeast, mid-Atlantic and midwest regions of the United
States. Effective April 30, 1998, PEC sold its interest in Resource Energy. PEC
subsequently purchased certain assets from Resource Energy and transferred those
assets to SouthStar. The net result of the sale of the interest in Resource
Energy and the transfer of assets to SouthStar was immaterial.
16
<PAGE> 19
Year 2000
Overview
In 1996, the Company formed a Year 2000 Project Team and selected
Keane, Inc., as the principal Year 2000 consultant. Since that time, the Company
has undertaken a comprehensive enterprise-wide project to inventory, assess,
remediate and test hardware, software and embedded systems intended to render
them Year 2000 ready. In December 1997, the Company established a Year 2000
Sub-Committee comprised of senior-level executives to monitor Year 2000 efforts
and assure that the Company's core systems would be Year 2000 ready prior to the
turn of the century.
In support of Year 2000 efforts, the Company formed a Test Management
Group that has established specific testing processes and procedures that are
being used with both Information Technology (IT) and non-IT systems. The testing
methodology incorporates the use of various testing techniques such as
regression, system, parallel, interface and stress testing. Additional testing
scenarios are incorporated into the test plans to demonstrate Year 2000
readiness. The results of these tests are reviewed by the Test Management Group
to validate that a particular system's functional and Year 2000 readiness
testing is in accordance with the testing methodology.
Although extensive testing is being completed prior to the system
implementations, the Company will perform additional testing during 1999. During
the third calendar quarter of 1999, the Company intends to conduct a final Year
2000 enterprise-wide audit to verify that all issues have been adequately
addressed.
Readiness of Systems, Applications and Embedded Devices
The Company has completed an inventory and assessment of the entire
portfolio of hardware, software and embedded systems. The compliance or
non-compliance of systems was based on written responses or Internet web site
information from vendors. Based on those findings, a Year 2000 Master Plan was
developed that outlined a remediation strategy to either repair, replace,
upgrade or retire each system, application or device that was deemed
non-compliant. In an effort to prioritize the Year 2000 efforts, each system,
application or device was classified as either mission critical, support
intensive or low impact based on certain factors that describe its relative
importance to the business. These classifications and strategies were reviewed
and approved by the Year 2000 Sub-Committee.
The four criteria that were utilized to classify a system, application
or device as mission critical are as follows, listed
17
<PAGE> 20
in order of importance: (1) provide for public or employee safety, (2) provide
for gas supply or service to customers, (3) provide the ability to comply with
regulatory or legal requirements and (4) provide a sustained level of business
and income. The systems classified as support intensive are described as
"systems providing a major part of the business operation but an alternative
solution could be formulated and executed." Low-impact applications are defined
as "systems that assist with operations but whose failure would cause only minor
inconvenience."
The Company's overall strategy is to have all mission-critical systems,
applications or devices Year 2000 ready by December 31, 1998. These
mission-critical systems are both IT and non-IT hardware and software and are
included in the following environments: mainframe, mid-range, client/server,
desktop and embedded technologies. Examples of these systems are SCADA
(real-time system pressure and flow monitoring), Customer Information,
Telemetering, Materials Management, Gas Management, gas leak detection devices
and fire detection/alarm systems. Additionally, many of the Company's
support-intensive and low-impact systems will also be Year 2000 ready by the end
of December 1998. Any remaining systems are expected to be complete by the third
calendar quarter of 1999.
Suppliers and Vendors
The Company is currently evaluating the status of Year 2000 compliance
efforts of critical suppliers and vendors. Following the mailing of Year 2000
inquiries and surveys to approximately 700 critical suppliers and vendors, the
Company has received some level of written response from approximately 80% of
the companies. These responses are being carefully analyzed to determine which,
if any, supplier relationships may require further attention based on
anticipated risks and business impacts to the Company. The Company, if
warranted, will identify alternative vendor sources and develop contingency
plans for any critical vendors considered at risk. This work effort is
anticipated to be complete by the second calendar quarter of 1999.
Risks
The Company has not yet defined specific "worst case" scenarios but
will be doing so as part of its current contingency planning efforts. Management
currently believes that the worst case scenarios might involve the interruption
of service delivery by critical suppliers in the areas of telephone,
electricity, gas supply, financial institutions, data services and materials.
The loss of telecommunications voice and data traffic would be
18
<PAGE> 21
especially detrimental to the Company's core business functions and operational
stability. These activities provide the means by which customers contact the
Company for both standard and emergency service requests and provide the Company
with internal and external links to its systems and service providers.
Additionally, many of the current system contingency plans assume that the
telecommunications network is operational.
The Company currently has in place the following that will be analyzed
and employed to mitigate risks, minimize potential impacts and provide safe
uninterrupted service to customers:
-- a territory-wide radio system to overcome telecommunication outages,
-- natural gas-powered backup electrical generators at regional operations
centers,
-- liquefied natural gas facilities that can provide short-term gas
supply,
-- a hot-site disaster recovery provider for computer services, and
-- warehouse facilities that allow stockpiling of critical supplies.
The Company also perceives a potential risk that the interruption of
basic utility services or the availability of consumer goods would impact
employees on a personal level and may interfere with their availability to
report to work. Many of the Company's contingency plans rely on manual processes
or procedures and the ability to implement a particular plan could be impacted
by staff shortages. Although the Company has not yet completed a determination
of worst case scenarios or their potential impacts, it is reasonable to assume
that any combination of worst case scenarios, coupled with application or system
failures, would result in a material adverse effect on financial position or
results of operations.
Contingency Planning
The Company is currently analyzing and evaluating the existing disaster
recovery plans as they relate to Year 2000 issues. Based on certain unique
conditions or assumptions that are made, those plans will be altered or updated
as dictated by business requirements. The guidelines outlined by the General
Accounting Office for Year 2000 Business Continuity and Contingency Planning are
being followed. The contingency planning process is taking into account
facilities, suppliers, vendors, embedded technologies and critical business
processes and their interdependencies. An important part of the planning process
has been to assume that there will be multiple concurrent failures of systems,
thus requiring an additional level of
19
<PAGE> 22
planning to compensate for any assumptions that are made within a particular
contingency plan. The development of contingency plans is anticipated to be
complete by the second calendar quarter of 1999. During 1999, the Company
intends to test selected contingency plans based on potential risks to the
Company.
Financial Impact
The Company's total costs for Year 2000 readiness, including inventory,
assessment, replacements, upgrades, repairs and testing, are estimated to be
between $23 million and $25 million, of which $14.5 million has been incurred as
of October 31, 1998. Total operating costs are estimated to be between $5
million and $6 million. In accordance with an order of the NCUC, the portion of
the operating costs attributable to North Carolina (57% based on utility plant
in service) is being deferred and amortized over a three-year period. Of the
total estimated costs, the Company will capitalize costs of $18 million to $19
million to replace certain existing applications with new systems that will be
Year 2000 operational and provide additional business management information and
functionality. Until the Company has completed further analysis of the Year 2000
impacts on its supplier and vendor relationships and contingency planning, an
estimate of any additional costs to be incurred as a result of these efforts
cannot be determined. The Company has not had to defer or cancel any planned IT
projects due to Year 2000 issues.
As of October 31, 1998, the Company has expensed $3.3 million, deferred
$1.1 million and capitalized $10.1 million. The Company expects that these Year
2000 costs will be funded by revenue generated from operations or through
borrowings under credit agreements. The projected Year 2000 costs for fiscal
1999 comprise approximately 33% of the IT budget.
The Company expects that all necessary systems will be Year 2000 ready
by late December 1999. As progress is made, the master plan is continually
revised to address the risks of Year 2000 issues, including contingency plans as
appropriate to address worst case scenarios. The total capital and operating
costs to be Year 2000 ready, including assessment, replacement and remediation,
are not expected to significantly impact financial position or results of
operations.
Disclaimer
The Year 2000 statements in this document are Year 2000 Readiness
Disclosures under the Year 2000 Information and Readiness Disclosure Act and are
made to the best knowledge and belief of Piedmont Natural Gas Company.
20
<PAGE> 23
Forward-Looking Statements
This report contains forward-looking statements within the meaning of
the Private Securities Litigation Reform Act of 1995. Forward-looking statements
include, among others, statements concerning plans, objectives, proposed capital
expenditures and future events or performance. These statements reflect
management's current expectations and involve a number of risks and
uncertainties. Actual results in the future may differ materially from
management's present assessment of information regarding the estimated future
impact of transactions and events that have occurred or are expected to occur,
expected sources of liquidity and capital resources, operating trends,
commitments and uncertainties. Important factors that could cause actual results
to differ include:
-- regulatory issues, including those that affect allowed rates of return,
rate structure and financings,
-- industrial, commercial and residential growth in the service
territories,
-- deregulation, unanticipated impacts of restructuring and increased
competition in the energy industry,
-- the potential loss of large-volume industrial customers due to bypass
or the shift by such customers to special competitive contracts at
lower per unit margins,
-- economic and capital market conditions,
-- ability to meet internal performance goals,
-- the capital intensive nature of the Company's business, including
development project delays or changes in project costs,
-- changes in the availability and price of natural gas,
-- changes in demographic patterns and weather conditions,
-- changes in environmental requirements and cost of compliance, and
-- unanticipated problems related to the Company's internal Year 2000
initiative as well as potential adverse consequences related to
third-party Year 2000 compliance.
Item 8. Financial Statements and Supplementary Data
The Company's consolidated financial statements and schedules required
by this Item are listed in Item 14(a)1 and 2 in Part IV of this report.
21
<PAGE> 24
CONSOLIDATED BALANCE SHEETS
October 31, 1998 and 1997
ASSETS
<TABLE>
<CAPTION>
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Utility Plant:
Utility plant in service $1,293,797 $1,224,001
Less accumulated depreciation 381,585 342,418
---------- ----------
Utility plant in service, net 912,212 881,583
Construction work in progress 52,128 32,771
---------- ----------
Total utility plant, net 964,340 914,354
---------- ----------
Other Physical Property, at cost (net of
accumulated depreciation of $17,406,000
in 1998 and $15,947,000 in 1997) 26,300 27,382
---------- ----------
Current Assets:
Cash and cash equivalents 9,720 5,210
Restricted cash 27,484 21,385
Receivables (less allowance for doubtful
accounts of $2,314,000 in 1998 and
$2,027,000 in 1997) 24,459 32,367
Inventories:
Gas in storage 42,465 47,676
Materials, supplies and merchandise 5,673 6,781
Deferred cost of gas 5,217 7,327
Refundable income taxes 13,897 7,115
Prepayments 13,627 4,295
---------- ----------
Total current assets 142,542 132,156
---------- ----------
Deferred Charges and Other Assets:
Unamortized debt expense (amortized
over life of related debt on a
straight-line basis) 2,455 2,759
Other 27,207 21,505
---------- ----------
Total deferred charges and other assets 29,662 24,264
---------- ----------
Total $1,162,844 $1,098,156
========== ==========
</TABLE>
See notes to consolidated financial statements.
22
<PAGE> 25
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Capitalization:
Stockholders' equity:
Cumulative preferred stock - no par
value - 175,000 shares authorized $ - $ -
Common stock - no par value - 100,000,000
shares authorized; outstanding, 30,737,983
shares in 1998 and 30,193,014 shares in 1997 279,709 262,576
Retained earnings 178,559 157,250
---------- ----------
Total stockholders' equity 458,268 419,826
Long-term debt 371,000 381,000
---------- ----------
Total capitalization 829,268 800,826
---------- ----------
Current Liabilities:
Current maturities of long-term debt and sinking
fund requirements 10,000 10,000
Notes payable 32,000 25,000
Accounts payable 67,296 65,103
Customers' deposits 7,478 6,629
Deferred income taxes 15,367 10,276
Taxes accrued 12,893 11,041
Refunds due customers 28,408 15,097
Other 12,406 12,383
---------- ----------
Total current liabilities 185,848 155,529
---------- ----------
Deferred Credits and Other Liabilities:
Unamortized federal investment tax credits 7,823 8,381
Accumulated deferred income taxes 110,851 105,249
Other 29,054 28,171
---------- ----------
Total deferred credits and other liabilities 147,728 141,801
---------- ----------
Total $1,162,844 $1,098,156
========== ==========
</TABLE>
See notes to consolidated financial statements.
23
<PAGE> 26
STATEMENTS OF CONSOLIDATED INCOME
For the Years Ended October 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(in thousands except per share amounts)
<S> <C> <C> <C>
Operating Revenues $ 765,277 $ 775,517 $ 685,055
Cost of Gas 442,422 460,665 394,133
--------- --------- ---------
Margin 322,855 314,852 290,922
--------- --------- ---------
Other Operating Expenses:
Operations 104,933 110,689 105,822
Maintenance 14,708 16,160 15,776
Depreciation 42,175 39,187 36,039
Income taxes 37,249 31,948 27,609
General taxes 32,633 32,882 31,047
--------- --------- ---------
Total other operating expenses 231,698 230,866 216,293
--------- --------- ---------
Operating Income 91,157 83,986 74,629
--------- --------- ---------
Other Income:
Non-utility activities, net of
income taxes 684 2,813 4,376
Other income, net of income taxes 1,659 1,271 624
--------- --------- ---------
Total other income 2,343 4,084 5,000
--------- --------- ---------
Income Before Utility Interest Charges 93,500 88,070 79,629
--------- --------- ---------
Utility Interest Charges:
Interest on long-term debt 31,507 32,429 30,120
Allowance for borrowed funds used
during construction (credit) (1,242) (712) (783)
Other interest 2,922 2,279 1,730
--------- --------- ---------
Total utility interest charges 33,187 33,996 31,067
--------- --------- ---------
Net Income $ 60,313 $ 54,074 $ 48,562
========= ========= =========
Average Shares of Common Stock:
Basic 30,472 29,883 29,161
Diluted 30,717 30,229 29,213
Earnings Per Share of Common Stock:
Basic $ 1.98 $ 1.81 $ 1.67
Diluted $ 1.96 $ 1.79 $ 1.66
</TABLE>
See notes to consolidated financial statements.
24
<PAGE> 27
STATEMENTS OF CONSOLIDATED CASH FLOWS
For the Years Ended October 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income $ 60,313 $ 54,074 $ 48,562
--------- --------- --------
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation and amortization 46,113 43,441 40,107
Deferred income taxes 10,693 3,983 13,053
Amortization of investment
tax credits (558) (558) (558)
Allowance for funds used during
construction (2,611) (1,418) (1,419)
Changes in assets and liabilities:
Restricted cash (6,099) (904) (2,533)
Receivables 7,908 11 (11,260)
Inventories 6,319 3,059 (10,061)
Other assets, net (19,706) 19,269 (18,053)
Accounts payable 2,193 4,953 21,847
Refunds due customers 13,311 15,029 (22,221)
Other liabilities, net 5,512 (1,484) 1,460
--------- --------- --------
Total adjustments 63,075 85,381 10,362
--------- --------- --------
Net cash provided by operating activities 123,388 139,455 58,924
--------- --------- --------
Cash Flows from Investing Activities:
Utility construction expenditures (90,898) (92,057) (96,759)
Other (1,112) (1,594) (2,876)
--------- --------- --------
Net cash used in investing activities (92,010) (93,651) (99,635)
--------- --------- --------
Cash Flows from Financing Activities:
Increase (Decrease) in bank loans, net 7,000 (14,000) 25,500
Proceeds from issuance of
long-term debt -- -- 40,000
Retirement of long-term debt (10,000) (10,000) (7,000)
Issuance of common stock through
dividend reinvestment and
employee stock plans 15,136 14,420 14,787
Dividends paid (39,004) (36,008) (33,393)
--------- --------- --------
Net cash provided by (used in)
financing activities (26,868) (45,588) 39,894
--------- --------- --------
Net Increase (Decrease) in Cash and
Cash Equivalents 4,510 216 (817)
Cash and Cash Equivalents at
Beginning of Year 5,210 4,994 5,811
--------- --------- --------
Cash and Cash Equivalents at End of Year $ 9,720 $ 5,210 $ 4,994
========= ========= ========
Cash Paid During the Year for:
Interest $ 33,226 $ 33,324 $ 31,435
Income taxes $ 47,139 $ 34,636 $ 52,087
</TABLE>
See notes to consolidated financial statements.
25
<PAGE> 28
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS
For the Years Ended October 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
(in thousands)
<S> <C> <C> <C>
Balance at Beginning of Year $157,250 $139,184 $124,015
Net Income 60,313 54,074 48,562
-------- -------- --------
Total 217,563 193,258 172,577
Deduct:
Dividends declared on common
stock ($1.28 a share in 1998,
$1.205 in 1997 and $1.145 in 1996) 39,004 36,008 33,393
-------- -------- --------
Balance at End of Year $178,559 $157,250 $139,184
======== ======== ========
</TABLE>
See notes to consolidated financial statements.
26
<PAGE> 29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
A. Operations and Principles of Consolidation.
Piedmont Natural Gas Company, Inc. (the Company), an investor-owned
public utility, is primarily engaged in the sale and transportation of natural
gas to residential, commercial and industrial customers in the Piedmont region
of North Carolina and South Carolina and the metropolitan Nashville, Tennessee,
area. The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries. Significant intercompany transactions have
been eliminated in consolidation where appropriate.
B. Utility Plant and Depreciation.
Utility plant is stated at original cost, including direct labor and
materials, allocable overheads and an allowance for borrowed and equity funds
used during construction (AFUDC). The weighted average accrual rate for AFUDC
was 9.55% for 1998, 9.46% for 1997 and 9.39% for 1996. The portion of AFUDC
attributable to equity funds is included in other income, and the portion
attributable to borrowed funds is shown as a reduction of utility interest
charges. The costs of property retired are removed from utility plant and such
costs, including removal costs net of salvage, are charged to accumulated
depreciation.
Depreciation expense is computed using the straight-line method applied
to average depreciable costs. The ratio of depreciation provisions to average
depreciable property balances was 3.43% for 1998, 3.41% for 1997 and 3.40% for
1996.
Long-lived assets and certain identifiable intangibles are reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. These reviews did not result
in a material effect on the results of operations or financial condition.
C. Inventories.
Inventories are maintained on the basis of the average cost charged
thereto.
D. Deferred Purchased Gas Adjustment.
Rate schedules include purchased gas adjustment provisions that permit
the recovery of purchased gas costs. Purchased gas adjustment factors are
revised periodically without formal rate proceedings to reflect changes in the
cost of purchased gas. Charges to cost of gas are based on the amount
recoverable under approved rate schedules. The net of any over- or
under-recovered amounts is included in refunds due customers.
E. Income Taxes.
Deferred income taxes are provided for differences between the book and
tax basis of assets and liabilities, principally attributable
27
<PAGE> 30
to accelerated tax depreciation and the timing of the recording of revenues and
cost of gas. Deferred investment tax credits are amortized to income over the
estimated useful life of the related property.
F. Operating Revenues.
Revenues are recognized from meters read on a monthly cycle basis which
results in unrecognized revenue from the cycle date through month end. The cost
of gas delivered to customers but not yet billed under the cycle-billing method
is deferred.
G. Earnings Per Share.
Basic earnings per share are computed based on the weighted average
number of shares of Common Stock outstanding during each period. Effective
January 31, 1998, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 128, "Earnings Per Share" (FAS 128), which requires the
presentation of a diluted earnings per share amount. A reconciliation of basic
and diluted earnings per share for the years ended October 31, 1998, 1997 and
1996, is presented below:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(in thousands except per share amounts)
<S> <C> <C> <C>
Net Income $60,313 $54,074 $48,562
======= ======= =======
Average shares of
Common Stock
outstanding for
basic earnings
per share 30,472 29,883 29,161
Contingently issuable
shares under
the long-term
incentive plan 245 346 52
------- ------- -------
Average shares of
dilutive stock 30,717 30,229 29,213
======= ======= =======
Earnings Per Share:
Basic $ 1.98 $ 1.81 $ 1.67
Diluted $ 1.96 $ 1.79 $ 1.66
</TABLE>
H. Rate-Regulated Basis of Accounting.
SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation" (FAS 71), provides that rate-regulated public utilities account for
and report assets and liabilities consistent with the economic effect of the
manner in which independent third-party regulators establish rates. In applying
FAS 71, the Company has capitalized certain costs and benefits as regulatory
assets and
28
<PAGE> 31
liabilities, respectively, pursuant to orders of the state utility regulatory
commissions, either in general rate proceedings or expense deferral proceedings,
in order to provide for recovery of or refunds to utility customers in future
periods.
The Company monitors the regulatory and competitive environment in
which it operates to determine that its regulatory assets continue to be
probable of recovery. If the Company, at some point in the future, determines
that all or a portion of these regulatory assets no longer meet the criteria for
continued application of FAS 71, then the Company would be required to write off
that portion which it could not recover, net of any regulatory liabilities which
would be deemed no longer necessary.
The amounts recorded as regulatory assets and liabilities in the
consolidated balance sheets at October 31, 1998 and 1997, are summarized as
follows:
<TABLE>
<CAPTION>
1998 1997
------- -------
(in thousands)
<S> <C> <C>
Regulatory Assets
Unamortized debt expense $ 2,455 $ 2,759
Environmental 7,037 6,916
Pipeline transition costs 2,532 3,578
Demand-side management 3,214 413
Deferred Year 2000 costs 1,132 384
Deferred pension expense 1,016 1,016
Other 1,419 1,594
------- -------
Total $18,805 $16,660
======= =======
Regulatory Liabilities
Refunds due customers $28,408 $15,097
Excess deferred taxes 13,017 13,327
Deferred incentive plan 455 563
------- -------
Total $41,880 $28,987
======= =======
</TABLE>
I. Statement of Cash Flows.
For purposes of reporting cash flows, all highly liquid debt
instruments purchased with an original maturity of three months or less are
considered to be cash equivalents.
J. Segment Reporting.
SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information", requires disclosure of segment data based on how management makes
decisions about allocating resources to segments and measuring performance. The
Company is principally engaged in the gas distribution industry and has no other
reportable industry segments.
K. Other Recently Issued Accounting Standards.
SFAS No. 130, "Reporting Comprehensive Income" (FAS 130), requires the
reporting and display of comprehensive income and its components in
29
<PAGE> 32
an entity's financial statements. The Company has no items of other
comprehensive income in any period presented.
SFAS No. 132, "Employers' Disclosures About Pensions and Other
Postretirement Benefits" (FAS 132), standardizes the disclosure requirements for
pensions and other postretirement benefits. The Company has adopted FAS 132.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (FAS 133), requires all derivative instruments to be recognized on
the balance sheet at their fair value. Changes in the fair value of derivatives
are to be recorded each period either in other comprehensive income or in
current earnings depending on the use of the derivative and whether it qualifies
for hedge accounting. FAS 133 is effective for all fiscal quarters of fiscal
years beginning after June 15, 1999. The Company is currently evaluating the
effects of FAS 133 on financial position and results of operations.
L. Use of Estimates.
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
M. Reclassifications.
Certain financial statement items for 1997 and 1996 have been
reclassified to conform with the 1998 presentation.
2. Regulatory Matters
The Company's utility operations are subject to regulation by the North
Carolina Utilities Commission (NCUC) and the Tennessee Regulatory Authority
(TRA) as to the issuance of securities, and by those commissions and by the
Public Service Commission of South Carolina (PSCSC) as to rates, service area,
adequacy of service, safety standards, extensions and abandonment of facilities,
accounting and depreciation.
The Company has been operating in an unbundled environment with all of
its interstate pipelines for several years under Federal Energy Regulatory
Commission (FERC) Order 636. In the Company's opinion, present rules and
regulations of the NCUC, the PSCSC and the TRA permit the pass through to
customers of interstate pipeline capacity and storage service costs and similar
costs that may be incurred under Order 636. Through 1998, the Company has
recovered substantially all such costs through purchased gas adjustment
procedures.
30
<PAGE> 33
In 1996, the NCUC ordered the establishment of an expansion fund for
the Company and approved initial funding with supplier refunds due customers to
enable the extension of natural gas service into unserved areas of the state. As
of October 31, 1998, the North Carolina State Treasurer held $19.1 million in
the Company's expansion fund account. This amount along with other supplier
refunds, including interest earned to date, is included in restricted cash. The
use of such funds will be at the discretion of the NCUC as individual project
applications for unserved areas are filed by the Company and approved by the
NCUC. As of October 31, 1998, no funds have been used for expansion.
In June 1998, the Company filed a petition with the NCUC for approval
of an expansion project that would extend natural gas service to the counties of
Avery, Mitchell and Yancey which are currently without natural gas service. The
Company also requested authority to use $26,300,000 in expansion fund money to
partially fund the estimated cost of the project of $31,900,000. In November
1998, the NCUC issued an order approving the Company's requests.
In November 1995, the PSCSC approved a general increase in the
Company's rates in South Carolina, effective November 7, 1995, of $7,800,000
annually. The rate increase was based on a return on common equity of 12.5%. The
Consumer Advocate for the State of South Carolina appealed the order of the
PSCSC. On August 31, 1998, the South Carolina Supreme Court ruled that the PSCSC
had failed to set forth sufficient findings of fact to support the 12.5% return.
The Supreme Court also ruled that the PSCSC erred in permitting the Company to
recover certain demand-side management (DSM) costs because the Company did not
provide a cost-benefit analysis with respect to these costs. The matter was
remanded to the PSCSC for further proceedings. On October 26, 1998, the PSCSC
issued its order on remand requiring the Company to reduce its rates effective
November 1, 1998, to eliminate annual DSM costs included in its rates. The
Company is to account for DSM costs incurred since implementation of the DSM
programs as a regulatory asset for recovery in future rates. The order also set
forth the PSCSC's findings and conclusions and an analysis of relevant factors
to comply with the Supreme Court's remand with respect to return on common
equity. The PSCSC affirmed its allowance of the 12.5% return on common equity.
In December 1996, the TRA issued an order in a general rate case
proceeding permitting the Company to increase its margin in Tennessee, effective
January 1, 1997, by $4,400,000 annually. The TRA's decision was confirmed by a
written decision in February 1997 (the February Order). The Tennessee Consumer
Advocate filed several pleadings with the TRA arguing, among other things, that
the Company was not entitled to recover the increased rates prior to the date of
the February Order. All parties in this proceeding, including the Company,
petitioned the
31
<PAGE> 34
TRA to reconsider the February Order. In June 1997, the TRA issued an order
denying all motions and upholding its previous orders. In August 1997, the
Consumer Advocate petitioned the Court of Appeals for a review of the TRA's
orders. On July 1, 1998, the Court of Appeals affirmed the February Order.
3. Long-Term Debt
Long-term debt at October 31, 1998 and 1997, is summarized as follows:
<TABLE>
<CAPTION>
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Senior Notes:
9.19%, due 2001 $ 30,000 $ 30,000
10.02%, due 2003 20,000 24,000
10.06%, due 2004 12,000 14,000
10.11%, due 2004 24,000 28,000
9.44%, due 2006 35,000 35,000
8.51%, due 2017 35,000 35,000
Medium-Term Notes:
6.23%, due 2003 45,000 45,000
6.87%, due 2023 45,000 45,000
8.45%, due 2024 40,000 40,000
7.40%, due 2025 55,000 55,000
7.50%, due 2026 40,000 40,000
-------- --------
Total 381,000 391,000
Less current maturities 10,000 10,000
-------- --------
Total $371,000 $381,000
======== ========
</TABLE>
Annual sinking fund requirements and maturities through 2003 are
$10,000,000 in 1999 and 2000, $40,000,000 in 2001, $10,000,000 in 2002 and
$55,000,000 in 2003.
The Company's articles of incorporation and note agreements under which
long-term debt was issued contain provisions which restrict the amount of cash
dividends that may be paid on Common Stock. At October 31, 1998, all of the
Company's retained earnings was free of such restrictions.
32
<PAGE> 35
4. Capital Stock
The changes in Common Stock for the years ended October 31, 1996, 1997
and 1998, are summarized as follows:
<TABLE>
<CAPTION>
Shares Amount
---------- --------
(in thousands)
<S> <C> <C>
Balance, October 31, 1995 28,835,004 $230,964
Issue to participants in the Employee
Stock Purchase Plan (SPP) 27,713 577
Issue to the Dividend Reinvestment and
Stock Purchase Plan (DRIP) 635,046 14,210
Issue to participants in the
long-term incentive plan (LTIP) 51,105 1,156
---------- --------
Balance, October 31, 1996 29,548,868 246,907
Issue to SPP 24,948 555
Issue to DRIP 568,482 13,865
Issue to LTIP 50,716 1,249
---------- --------
Balance, October 31, 1997 30,193,014 262,576
Issue to SPP 18,668 555
Issue to DRIP 464,040 14,582
Issue to LTIP 62,261 1,996
---------- --------
Balance, October 31, 1998 30,737,983 $279,709
========== ========
</TABLE>
At October 31, 1998, 1,826,833 shares of Common Stock were reserved for
issuance as follows:
<TABLE>
<S> <C>
SPP 226,960
DRIP 607,873
LTIP 992,000
---------
Total 1,826,833
=========
</TABLE>
5. Financial Instruments and Related Fair Value
The Company has committed bank lines of credit totaling $75,000,000 to
finance current cash requirements. Additional uncommitted lines are also
available on an as needed, if available, basis. Borrowings under the lines, with
maturity dates of less than 90 days, include bankers' acceptances, transactional
borrowings and overnight cost-plus loans based on the lending bank's cost of
money, with a maximum rate of the lending bank's commercial prime interest rate.
At October 31, 1998, the lines of credit were on either a fee basis or
compensating balance basis, with average annual balance requirements of
$300,000.
At October 31, 1998, outstanding notes payable consisted of $25,000,000
in bankers' acceptances and $7,000,000 in overnight cost-
33
<PAGE> 36
plus loans. The weighted average interest rate on such borrowings was 5.5%.
The Company's principal business activity is the sale and
transportation of natural gas to customers located in North Carolina, South
Carolina and Tennessee. At October 31, 1998, gas receivables totaled $18,565,000
and other receivables totaled $8,208,000. The uncollected balance of installment
receivables which have been transferred with recourse was $20,969,000 and
$23,184,000 at October 31, 1998 and 1997, respectively. The Company has provided
an adequate allowance for any receivables which may not be ultimately collected,
including the receivables transferred with recourse.
Effective January 1, 1998, the Company adopted SFAS No. 125,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishment
of Liabilities" (FAS 125). The adoption of FAS 125 did not have a material
effect on financial position or results of operations.
The carrying amounts in the consolidated balance sheets of cash and
cash equivalents, restricted cash, receivables, notes payable and accounts
payable approximate their fair values due to the short-term maturities of these
financial instruments. Based on quoted market prices of similar issues having
the same remaining maturities, redemption terms and credit ratings, the
estimated fair values of long-term debt at October 31, 1998 and 1997, including
current portion, are as follows:
<TABLE>
<CAPTION>
1998 1997
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------ -------- -----
(in thousands)
<S> <C> <C> <C> <C>
Long-term debt $381,000 $435,840 $391,000 $425,148
</TABLE>
The use of different market assumptions or estimation methodologies may
have a material effect on the estimated fair values. The fair value amounts are
not intended to reflect principal amounts that the Company will ultimately be
required to pay.
The Company engages in minimal derivative products activities, such as
exchange-traded futures and over-the-counter forward contracts, to manage
commodity price and basis risk when appropriate. The hedging activities permit
the Company to translate physical market activities into a common pricing index
against which transaction values will be measured at the margin. Under internal
Company guidelines, limited speculative positions are permitted in the
derivatives market or in the form of fixed price gas supply contracts. The
Company's derivative
34
<PAGE> 37
products activity is not material to financial position or results of
operations.
A subsidiary of the Company is a member of SouthStar Energy Services
LLC (SouthStar) which enters into derivative instruments to hedge its exposure
to the impact of price and basis fluctuations on gas contracts. SouthStar
utilizes a balanced book approach for matching sales to customers and supply
from third parties. Market risk is managed through adherence to open position
limits, signature authorizations and day-to-day commercial procedures maintained
by SouthStar. Risk of loss is mitigated by continually assessing such risks in
the context of the business and the structure of deals. All hedge transactions
are subject to a risk management policy, approved by SouthStar's Board of
Directors, which does not permit speculative positions. SouthStar's derivative
products activity is not material to the Company's financial position or results
of operations.
6. Employee Benefit Plans
The Company has a defined-benefit pension plan for the benefit of
substantially all full-time regular employees. Plan benefits are generally based
on credited years of service and the level of compensation during the five
consecutive years of the last ten years prior to retirement during which the
participant received his or her highest compensation. The Company's policy is to
fund the plan in an amount not in excess of the amount that is deductible for
income tax purposes under applicable federal regulations. Plan assets consist
primarily of marketable securities and cash equivalents. The plan is amended
from time to time in accordance with changes in tax law.
The Company provides certain postretirement health care and life
insurance benefits to substantially all full-time regular employees. As of
October 31, 1998, the liability associated with such benefits was funded in
irrevocable trust funds which can only be used to pay the benefits.
A reconciliation of the changes in the plans' benefit obligations and
fair value of assets for the years ended October 31, 1998 and 1997, and a
statement of the funded status as of October 31, 1998 and 1997, are presented
below:
35
<PAGE> 38
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
---------------- --------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
Change in benefit obligation
Obligation at beginning of year $ 112,330 $ 106,962 $ 21,941 $ 19,418
Service cost 5,228 5,146 620 627
Interest cost 7,663 7,251 1,489 1,367
Plan amendments 1,624 -- -- --
Actuarial (gain) loss 1,641 (2,074) 512 2,701
Benefit payments (8,914) (4,955) (1,626) (2,172)
--------- --------- -------- --------
Obligation at end of year $ 119,572 $ 112,330 $ 22,936 $ 21,941
========= ========= ======== ========
Change in fair value of plan assets
Fair value of plan assets at beginning $ 141,540 $ 117,646 $ 4,709 $ 3,137
of year
Actual return on plan assets 16,827 24,827 232 202
Employer contributions -- 4,022 3,412 2,368
Benefit payments (8,914) (4,955) (1,181) (998)
--------- --------- -------- --------
Fair value of plan $ 149,453 $ 141,540 $ 7,172 $ 4,709
assets at end of year ========= ========= ======== ========
Funded status
Funded status at end of year $ 29,881 $ 29,210 $(15,764) $(17,232)
Unrecognized transition obligation 75 90 13,948 14,878
Unrecognized prior-service cost 4,969 3,805 -- --
Unrecognized (gain)loss (42,849) (39,703) 4,270 3,705
--------- --------- -------- --------
Prepaid (accrued) benefit cost $ (7,924) $ (6,598) $ 2,454 $ 1,351
========= ========= ======== ========
</TABLE>
36
<PAGE> 39
The amounts recognized in the consolidated balance sheets as of October
31, 1998 and 1997, are presented below:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
---------------- --------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
Prepaid benefit cost $ -- $ -- $2,454 $1,351
Accrued benefit (7,924) (6,598) -- --
liability ------- ------- ------ ------
Net amount recognized $(7,924) $(6,598) $2,454 $1,351
======= ======= ====== ======
</TABLE>
Net periodic benefit cost for the years ended October 31, 1998, 1997
and 1996, includes the following components:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
---------------- --------------
1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 5,228 $ 5,146 $ 5,215 $ 620 $ 627 $ 657
Interest cost 7,663 7,251 6,891 1,489 1,367 1,342
Expected return on (11,474) (10,139) (9,361) (393) (377) (289)
plan assets
Amortization of 15 15 15 930 930 930
transition
obligation
Amortization of 459 417 417 -- -- --
prior-service cost
Amortization of net
(gain) loss (565) (297) -- 108 25 --
-------- -------- ------- ------- ------- -------
Net periodic benefit
cost $ 1,326 $ 2,393 $ 3,177 $ 2,754 $ 2,572 $ 2,640
======== ======== ======= ======= ======= =======
</TABLE>
Unrecognized prior service costs are amortized over the average
remaining service period for active employees. The unrecognized net transition
asset is amortized over the average remaining service period for active
employees expected to receive benefits under the plan as of the date of
transition. Gains and losses in excess of 10% of the
37
<PAGE> 40
greater of the benefit obligation and the market-related value of assets are
amortized over the average remaining service period of active employees. The
method of amortization in all cases is straight-line.
The weighted average assumptions used in the measurement of the
Company's benefit obligation as of October 31, 1998, 1997 and 1996, are
presented below:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
---------------- --------------
1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Discount rate 6.5% 6.75% 7.0% 6.75% 7.0% 7.25%
Expected long-term 9.5% 9.5% 9.5% 9.5% 9.5% 9.5%
rate of return on
plan assets
Rate of compensation 4.5% 4.75% 5.0% 4.5% 4.75% 5.0%
increase
</TABLE>
The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation for the medical plans is 8.25% for
1999, declining gradually to 4% in 2005 and remaining at that level thereafter.
The health care cost trend rate assumption has a significant effect on the
amounts reported. A one-percentage point change in assumed health care cost
trend rates would have the following effects:
<TABLE>
<CAPTION>
1% Increase 1% Decrease
----------- -----------
(in thousands)
<S> <C> <C>
Effect on total of service and
interest cost components of
net periodic postretirement
health care benefit cost $ 107 $ 94
Effect on the health care
component of the accumulated
postretirement benefit
obligation $1,431 $1,261
</TABLE>
The Company maintains salary investment plans which are profit-sharing
plans under Section 401(a) of the Internal Revenue Code of 1986, as amended (the
Tax Code), which include qualified cash or deferred arrangements under Tax Code
Section 401(k). Employees who have completed six months of service are eligible
to participate.
38
<PAGE> 41
Participants are permitted to defer a portion of their base salary to the plans,
with the Company matching a portion of the participants' contributions. All
contributions vest immediately. For the years ended October 31, 1998, 1997, and
1996, the Company contributed $2,135,000, $2,172,000 and $2,173,000,
respectively, to the plans.
7. Income Taxes
The components of income tax expense for the years ended October 31, 1998,
1997 and 1996, are as follows:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
Federal State Federal State Federal State
------- ----- ------- ----- ------- -----
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income taxes charged to operations:
Current $ 23,101 $4,912 $ 24,074 $ 5,311 $ 11,966 $3,215
Deferred 8,035 1,759 2,696 425 11,224 1,762
Amortization of
investment tax
credits (558) -- (558) -- (558) --
-------- ------ -------- ------- -------- ------
Total 30,578 6,671 26,212 5,736 22,632 4,977
-------- ------ -------- ------- -------- ------
Income taxes charged to other income:
Current 451 208 2,101 (261) 2,683 568
Deferred 834 65 127 735 52 16
-------- ------ -------- ------- -------- ------
Total 1,285 273 2,228 474 2,735 584
-------- ------ -------- ------- -------- ------
Total income tax expense $ 31,863 $6,944 $ 28,440 $ 6,210 $ 25,367 $5,561
======== ====== ======== ======= ======== ======
</TABLE>
A reconciliation of income tax expense at the federal statutory rate to
recorded income tax expense for the years ended October 31, 1998, 1997 and 1996,
is as follows:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Federal taxes at 35% $ 34,692 $ 31,054 $ 27,822
State income taxes, net of
federal benefit 4,510 4,037 3,614
Amortization of investment tax credits (558) (558) (558)
Other, net 163 117 50
-------- -------- --------
Total income tax expense $ 38,807 $ 34,650 $ 30,928
======== ======== ========
</TABLE>
At October 31, 1998 and 1997, deferred income taxes consisted of the
following temporary differences:
<TABLE>
<CAPTION>
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Excess of tax over book depreciation and tax and
book asset basis differences $ 116,966 $ 110,746
Revenues and cost of gas 21,112 14,384
Long-term incentive plan (5,037) (4,027)
Regulatory liability related to SFAS No. 109 (4,531) (4,622)
Pension expense 225 800
Other, net (2,517) (1,756)
--------- ---------
Net deferred income taxes $ 126,218 $ 115,525
========= =========
</TABLE>
39
<PAGE> 42
Total deferred income tax liabilities were $145,669,000 and
$132,808,000 and total deferred income tax assets were $19,451,000 and
$17,283,000 at October 31, 1998 and 1997, respectively.
8. Subsidiary and Non-Utility Activities
Piedmont Energy Company (PEC), a wholly owned subsidiary of the
Company, has an equity interest in SouthStar Energy Services LLC (SouthStar), a
Delaware limited liability company formed in July 1998. SouthStar intends to
offer a combination of unregulated energy products and services to industrial,
commercial and residential customers in the southeast United States. The
products and services to be offered include natural gas, electricity, fuel oil
and propane, along with related retail services. Prior to May 1998, PEC was a
51% member of Resource Energy Services Company, L.L.C. (Resource Energy), a
North Carolina limited liability company. Resource Energy offered natural gas
acquisition, transportation and storage services to industrial users and other
utilities in the southeast, mid-Atlantic and midwest regions of the United
States. Effective April 30, 1998, PEC sold its interest in Resource Energy. PEC
subsequently purchased certain assets from Resource Energy and transferred those
assets to SouthStar. The net result of the sale of the interest in Resource
Energy and the transfer of assets to SouthStar was immaterial.
Piedmont Intrastate Pipeline Company, a wholly owned subsidiary of the
Company, is a 36% member of Cardinal Pipeline Company, L.L.C. (Cardinal), a
North Carolina limited liability company that owns and operates a natural gas
pipeline from a connection with an interstate pipeline to facilities owned by
the Company and facilities owned by another utility company, also a member.
Because the investment in Cardinal is treated as utility assets for ratemaking
purposes, the Company includes its share of the assets and operations of
Cardinal in utility operations.
Piedmont Interstate Pipeline Company (Piedmont Interstate), a wholly
owned subsidiary of the Company, is a 35% member of Pine Needle LNG Company,
L.L.C. (Pine Needle), a North Carolina limited liability company that is
currently constructing a liquified natural gas (LNG) peak-demand facility in
North Carolina with the peaking service scheduled to be available during the
winter of 1999-2000. Storage capacity will be four billion cubic feet with
vaporization capability of 400 million cubic feet per day. The Company has
subscribed to one-half of this capacity. Pine Needle has made arrangements to
finance the construction through construction loans, with permanent financing at
the end of the construction period. A portion of this permanent financing will
include an estimated equity contribution of $18,700,000 by Piedmont Interstate
in mid-1999.
40
<PAGE> 43
Piedmont Propane Company, a wholly owned subsidiary of the Company,
markets propane and propane appliances to residential, commercial and industrial
customers within and adjacent to the Company's three-state natural gas service
area.
Operating revenues shown in the consolidated financial statements
represent revenues from utility operations only. Non-utility revenues as a
percentage of total revenues, including utility operations, were 5% in 1998 and
1997 and 7% in 1996. No single non-utility activity accounted for greater than
6% of total revenues in any year. Income from non-utility activities as a
percentage of total net income was 1% in 1998, 5% in 1997 and 9% in 1996. No
single non-utility activity accounted for more than 6% of net income in any
year.
9. Environmental Matters
The Company has owned, leased or operated manufactured gas plant (MGP)
facilities at 12 sites in its three-state service area. In October 1997, the
Company entered into a settlement with a third party with respect to nine of
these sites. As of October 31, 1998, the Company had an environmental liability
of $1,360,000 for the remaining three MGP sites not covered by the settlement.
This liability is based on a generic MGP site study as site-specific evaluations
have not been performed.
The Company is authorized by its three state regulatory commissions to
utilize deferral accounting, or the creation of a regulatory asset, for
expenditures made in connection with environmental matters. In connection with
the settlement noted above and the estimated liability for the three remaining
sites, the Company has recorded a regulatory asset of $6,610,000. As of October
31, 1998, the Company had an additional regulatory asset in the amount of
$427,000, net of recoveries from customers, for other environmental costs,
primarily legal fees and engineering assessments.
Further evaluations of the three remaining sites could significantly
affect recorded amounts; however, the Company believes that the ultimate
resolution of these matters will not have a material adverse effect on financial
position or results of operations.
41
<PAGE> 44
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The management of the Company is responsible for the preparation and
integrity of the accompanying consolidated financial statements and related
notes. The statements were prepared in conformity with generally accepted
accounting principles appropriate in the circumstances and include amounts which
are necessarily based on management's best estimates and judgments made with due
consideration to materiality. Financial information presented elsewhere in this
report is consistent with that in the financial statements.
Management has established and is responsible for maintaining a
comprehensive system of internal accounting controls which it believes provides
reasonable assurance that Company policies and procedures are complied with,
assets are safeguarded and transactions are executed according to management's
authorization. This system is continually reviewed for effectiveness and
modified in response to changing business conditions and operations and as a
result of recommendations by the external and internal auditors.
The Audit Committee of the Board of Directors, consisting solely of
outside Directors, meets periodically with Deloitte & Touche LLP, the internal
auditors and representatives of management to discuss auditing and financial
reporting matters. The Audit Committee reviews audit plans and results and the
Company's accounting, financial reporting and internal control practices,
procedures and results. Both Deloitte & Touche LLP and the internal auditors
have full and free access to all levels of management.
42
<PAGE> 45
INDEPENDENT AUDITORS' REPORT
Piedmont Natural Gas Company, Inc.
We have audited the accompanying consolidated balance sheets of
Piedmont Natural Gas Company, Inc. and subsidiaries (the Company) as of October
31, 1998 and 1997, and the related statements of consolidated income, retained
earnings and cash flows for each of the three years in the period ended October
31, 1998. Our audits also included the supplemental consolidated financial
statement schedule listed in Item 14. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule 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, such consolidated financial statements present fairly,
in all material respects, the financial position of the Company at October 31,
1998 and 1997, and the results of its operations and its cash flows for each of
the three years in the period ended October 31, 1998 in conformity with
generally accepted accounting principles. Also, in our opinion, such
consolidated financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Charlotte, North Carolina
December 18, 1998
43
<PAGE> 46
QUARTERLY FINANCIAL DATA
Quarterly financial data for 1998 and 1997 is summarized as follows:
<TABLE>
<CAPTION>
Earnings
Per Share of
Operating Operating Net Common Stock
Revenues Margin Income Income Basic Diluted
- ----------------------------------------------------------------------------------------------
(in thousands except per share amounts)
<S> <C> <C> <C> <C> <C> <C>
1998
January 31 $313,255 $123,093 $ 46,994 $ 41,249 $ 1.36 $ 1.35
April 30 $261,477 $113,981 $ 42,926 $ 35,463 $ 1.17 $ 1.16
July 31 $103,026 $ 45,499 $ 3,083 $ (6,253) $ (.20) $ (.20)
October 31 $ 87,519 $ 40,282 $ (1,846) $(10,146) $ (.33) $ (.33)
1997
January 31 $312,533 $118,370 $ 43,387 $ 37,312 $ 1.26 $ 1.26
April 30 $259,306 $109,119 $ 39,623 $ 32,274 $ 1.08 $ 1.08
July 31 $103,997 $ 47,143 $ 3,692 $ (5,777) $ (.19) $ (.19)
October 31 $ 99,681 $ 40,220 $ (2,716) $ (9,735) $ (.32) $ (.32)
</TABLE>
The pattern of quarterly earnings is the result of the highly seasonal
nature of the business as variations in weather conditions generally result in
greater earnings during the winter months. Basic earnings per share are
calculated based on the weighted average number of shares outstanding during the
quarter. The annual amount may differ from the total of the quarterly amounts
due to changes in the number of shares outstanding during the year.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
44
<PAGE> 47
PART III
Item 10. Directors and Executive Officers of the Registrant
Information required under this item with respect to directors is
contained in the Company's proxy statement filed with the Securities and
Exchange Commission (SEC) on or about January 27, 1999, and is incorporated
herein by reference.
The names, ages and positions of all of the executive officers of the
Company as of October 31, 1998, are listed below along with their business
experience during the past five years.
So far as practicable, all elected officers are elected at the first
meeting of the Board of Directors held following the annual meeting of
shareholders in each year and hold office until the meeting of the Board
following the annual meeting of shareholders in the next subsequent year and
until their respective successors are elected and qualify. All other officers
hold office during the pleasure of the Board. There are no family relationships
among these officers. There are no arrangements or understandings between any
officer and any other person pursuant to which the officer was selected except
for employment agreements with Messrs. Dzuricky, Killough, Maxheim, Schiefer and
Skains.
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
<S> <C>
John H. Maxheim, 64 Elected in 1984.
Chairman of the Board, President
and Chief Executive Officer
Ware F. Schiefer, 60 Elected in 1995.
Executive Vice President Prior to his election, he
was Senior Vice
President-Marketing and
Gas Supply.
David J. Dzuricky, 47 Elected in 1995.
Senior Vice President-Finance From 1993 until his
election, he was Vice
President and Treasurer
of Consolidated Natural
Gas Company, Pittsburgh,
Pennsylvania.
</TABLE>
45
<PAGE> 48
Ray B. Killough, 50 Elected in 1993.
Senior Vice President-Operations
Thomas E. Skains, 42 Elected in 1995.
Senior Vice President-Gas Supply Prior to his election, he
and Services was Senior Vice
President, Transportation
and Customer Services, of
Transcontinental Gas Pipe
Line Corporation,
Houston, Texas.
John L. Clark, Jr., 55 Elected in February 1998.
Vice President-Tennessee Prior to his election, he
Operations was Vice President-
Operations of the
Nashville Division.
Ted C. Coble, 55 Elected in 1982.
Vice President and Treasurer, and
Assistant Secretary
Stephen D. Conner, 50 Elected in 1990.
Vice President-Corporate
Communications
Nicholas Emanuel, 49 Elected in February 1998.
Vice President-Engineering Prior to his election, he
was Director-Engineering.
Charles W. Fleenor, 48 Elected in 1987.
Vice President-Gas Supply
Paul C. Gibson, 59 Elected in 1986.
Vice President-Rates
Barry L. Guy, 54 Elected in 1986.
Vice President and Controller
Donald F. Harrow, 43 Elected in 1992.
Vice President-Governmental Relations
Dale C. Hewitt, 53 Elected in 1993.
Vice President-North Carolina
Operations
46
<PAGE> 49
Richard A. Linville, 51 Elected in 1997.
Vice President-Human Resources Prior to his election, he
was Vice President-Human
Resources of Harriet and
Henderson Yarns, Inc.,
Henderson, North Carolina.
Kevin M. O'Hara, 40 Elected in 1993.
Vice President-Corporate Planning
William R. Pritchard, Jr., 55 Elected in 1986.
Vice President-Information
Services
Martin C. Ruegsegger, 48 Elected in 1997.
Vice President, Corporate Counsel From 1993 until his election,
and Secretary he was Corporate Secretary.
David L. Trusty, 41 Elected in 1997.
Vice President-Marketing Prior to his election, he
was Vice President-
Marketing of the Nashville
Division.
Ranelle Q. Warfield, 41 Elected in 1997.
Vice President-Customer Services Prior to her election,
she was Director-Marketing.
Bartlett C. Winkler, 62 Elected in 1997.
Vice President-Piedmont Propane Prior to his election, he
was Vice President-
Marketing.
William D. Workman, III, 58 Elected in 1993.
Vice President-South Carolina
Operations
Item 11. Executive Compensation
Information required under this item is contained in the Company's
proxy statement filed with the SEC on or about January 27, 1999, and is
incorporated herein by reference.
47
<PAGE> 50
Item 12. Security Ownership of Certain Beneficial Owners and
Management
(a) Security Ownership of Certain Beneficial Owners
Information with respect to security ownership of certain beneficial
owners is contained in the Company's proxy statement filed with the SEC on or
about January 27, 1999, and is incorporated herein by reference.
(b) Security Ownership of Management
Information with respect to security ownership of directors and
officers is contained in the Company's proxy statement filed with the SEC on or
about January 27, 1999, and is incorporated herein by reference.
(c) Changes in Control
The Company knows of no arrangements or pledges which may result in a
change in control.
Item 13. Certain Relationships and Related Transactions
Information with respect to certain transactions with directors is
contained in the Company's proxy statement filed with the SEC on or about
January 27, 1999, and is incorporated herein by reference.
48
<PAGE> 51
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K
(a) 1. FINANCIAL STATEMENTS
The following consolidated financial statements of the Company and
its subsidiaries and the related independent auditors' report for the year
ended October 31, 1998, are included in Item 8 of this report as follows:
<TABLE>
<CAPTION>
Page
----
<S> <C>
Consolidated Balance Sheets - October 31, 1998 and 1997 22
Statements of Consolidated Income - Years Ended
October 31, 1998, 1997 and 1996 24
Statements of Consolidated Cash Flows - Years Ended
October 31, 1998, 1997 and 1996 25
Statements of Consolidated Retained Earnings - Years
Ended October 31, 1998, 1997 and 1996 26
Notes to Consolidated Financial Statements 27
Management's Responsibility for Financial Reporting 42
Independent Auditors' Report 43
</TABLE>
(a) 2. SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
<TABLE>
<CAPTION>
Page
----
<S> <C>
II Valuation and Qualifying Accounts 59
</TABLE>
Schedules other than those listed above and certain other information
are omitted for the reason that they are not required or are not applicable, or
the required information is shown in the financial statements or notes thereto.
(a) 3. EXHIBITS
Where an exhibit is filed by incorporation by reference
to a previously filed registration statement or report,
such registration statement or report is identified in
parentheses. Upon written request of a shareholder, the
Company will provide a copy of the exhibit at a nominal
charge.
3.1 Copy of Articles of Incorporation of the Company, filed
in the Department of State of the State of North Carolina
on December 13, 1993 (Exhibit No. 2, Registration
Statement on Form 8-B, dated March 2, 1994).
49
<PAGE> 52
<TABLE>
<S> <C>
3.2 Copy of By-Laws of the Company as amended (Exhibit No. 2,
Registration Statement on Form 8-B, dated March 2, 1994).
3.3 Articles of Amendment of the Company (Exhibit No. 3,
Amendment to Form 10-Q for the period ended April 30, 1997).
4.1 Copy of Note Agreement, dated as of August 30, 1988, between
the Company and Jefferson-Pilot Life Insurance Company, et al
(Exhibit 4.26, Form 10-K for the fiscal year ended October
31, 1988).
4.2 Copy of Note Agreement, dated as of June 15, 1989, between
the Company and The Mutual Life Insurance Company of New York
(Exhibit 4.27, Form 10-K for the fiscal year ended October
31, 1989).
4.3 Copy of Note Agreement, dated as of August 31, 1989, between
the Company and Teachers Insurance and Annuity Association of
America (Exhibit 4.28, Form 10-K for the fiscal year ended
October 31, 1989).
4.4 Copy of Note Agreement, dated as of July 30, 1991, between
the Company and The Prudential Insurance Company of America
(Exhibit 4.29, Form 10-K for the fiscal year ended October
31, 1991).
4.5 Copy of Note Agreement, dated as of September 21, 1992,
between the Company and Provident Life and Accident Insurance
Company (Exhibit 4.30, Form 10-K for the fiscal year ended
October 31, 1992).
4.6 Copy of Indenture, dated as of April 1, 1993, between the
Company and Citibank, N.A., Trustee (Exhibit 4.1,
Registration Statement No. 33-60108).
4.7 Copy of Medium-Term Note, Series A, dated as of July 23, 1993
(Exhibit 4.7, Form 10-K for the fiscal year ended October 31,
1993).
4.8 Copy of Medium-Term Note, Series A, dated as of October 6,
1993 (Exhibit 4.8, Form 10-K for the fiscal year ended
October 31, 1993).
4.9 Copy of Medium-Term Note, Series A, dated as of September 19,
1994 (Exhibit 4.9, Form 10-K for the fiscal year ended
October 31, 1994).
</TABLE>
50
<PAGE> 53
<TABLE>
<S> <C>
4.10 Copy of Pricing Supplement of Medium-Term Notes, Series B,
dated October 3, 1995 (Exhibit 4.10, Form 10-K for the fiscal
year ended October 31, 1995).
4.11 Copy of Pricing Supplement of Medium-Term Notes, Series B,
dated October 4, 1996 (Exhibit 4.11, Form 10-K for the fiscal
year ended October 31, 1996).
10.1 Copy of the Company's Executive Long-Term Incentive Plan
(Exhibit 99.1, Registration Statement No. 333-34435).
10.2 Copy of Employment Agreement between the Company and John H.
Maxheim, dated February 26, 1993 (Exhibit 10.4, Form 10-K for
the fiscal year ended October 31, 1993).
10.3 Copy of Articles of Organization of Cardinal Pipeline
Company, L.L.C., dated April 5, 1994 (Exhibit 10.1, Form 10-Q
for the quarterly period ended April 30, 1994).
10.4 Copy of Operating Agreement of Cardinal Pipeline Company,
L.L.C., dated March 23, 1994 (Exhibit 10.2, Form 10-Q for the
quarterly period ended April 30, 1994).
10.5 Copy of Construction, Operating and Management Agreement by
and between Public Service Company of North Carolina, Inc.
and Cardinal Pipeline Company, L.L.C., dated March 23, 1994
(Exhibit 10.3, Form 10-Q for the quarterly period ended April
30, 1994).
10.6 Copy of Service Agreement under Rate Schedule LG-A, dated
January 15, 1971, between the Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 67, Registration Statement
No. 2-59631).
10.7 Copy of Service Agreement (5,900 Mcf per day) (Contract No.
4995), dated August 1, 1991, between the Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10.20,
Form 10-K for the fiscal year ended October 31, 1991).
10.8 Copy of Service Agreement under Rate Schedule WSS (69,701 mcf
per day) (Contract No. 26419-001), dated August 1, 1991,
between the Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 10.10, Form 10-K for the fiscal year
ended October 31, 1995).
</TABLE>
51
<PAGE> 54
<TABLE>
<S> <C>
10.9 Copy of Service Agreement FT-Incremental Mainline (6,222 Mcf
per day) (Contract No. 2268), dated August 1, 1991, between
the Company and Transcontinental Gas Pipe Line Corporation
(Exhibit 10.16, Form 10-K for the fiscal year ended October
31, 1992).
10.10 Copy of Service Agreement (FT, 205,200 Mcf per day) (Contract
No. 3702), dated February 1, 1992, between the Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10.20,
Form 10-K for the fiscal year ended October 31, 1992).
10.11 Copy of Service Agreement (Contract #800059) (SCT, 1,677
Dt/day), dated June 1, 1993, between the Company and Texas
Eastern Transmission Corporation (Exhibit 10.28, Form 10-K
for the fiscal year ended October 31, 1993).
10.12 Copy of Gas Transportation Agreement for Use Under FT-A Rate
Schedule (Contract No. 237) (FTA, 130,000 Dt/day), dated
September 1, 1993, between the Company and Tennessee Gas
Pipeline Company (Exhibit 10.30, Form 10-K for the fiscal
year ended October 31, 1993).
10.13 Copy of Gas Storage Contract for Use Under Rate Schedule FS
(Contract No. 2400) (672,091 Dt total capacity), dated
September 1, 1993, between the Company and Tennessee Gas
Pipeline Company (Exhibit 10.31, Form 10-K for the fiscal
year ended October 31, 1993).
10.14 Copy of Service Agreement under Rate Schedule GSS, dated
October 1, 1993, between the Company and Transcontinental Gas
Pipe Line Corporation (Exhibit 10.22, Form 10-K for the
fiscal year ended October 31, 1995).
10.15 Copy of FTS Service Agreement (23,000 Dt/day), dated November
1, 1993, between the Company and Columbia Gas Transmission
Corporation (Exhibit 10.24, Form 10-K for the fiscal year
ended October 31, 1994).
10.16 Copy of Service Agreement under Rate Schedule FSS (2,263,920
dekatherm storage capacity quantity, 37,000 dekatherm maximum
daily storage deliverability) (Contract No. 38015), dated
November 1, 1993, between the Company and Columbia Gas
Transmission Corporation (Exhibit 10.25, Form 10-K for the
fiscal year ended October 31, 1994).
</TABLE>
52
<PAGE> 55
<TABLE>
<S> <C>
10.17 Copy of Service Agreement under Rate Schedule SST (Winter:
10,000 Dt/day; Summer: 5,000 Dt/day) (Contract No. 38052),
dated November 1, 1993, between the Company and Columbia Gas
Transmission Corporation (Exhibit 10.26, Form 10-K for the
fiscal year ended October 31, 1994).
10.18 Copy of FSS Service Agreement (10,000 dekatherms per day
daily storage quantity) (Contract No. 38017), dated November
1, 1993, between the Company and Columbia Gas Transmission
Corporation (Exhibit 10.26, Form 10-K for the fiscal year
ended October 31, 1995).
10.19 Copy of SST Service Agreement (37,000 dekatherms per day)
(Contract No. 38054), dated November 1, 1993, between the
Company and Columbia Gas Transmission Corporation (Exhibit
10.27, Form 10-K for the fiscal year ended October 31, 1995).
10.20 Copy of Service Agreement (20,504 Mcf per day), dated June 6,
1994, between the Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 10.29, Form 10-K for the fiscal year
ended October 31, 1995).
10.21 Copy of FTS-1 Service Agreement (5,000 dekatherms per day)
(Contract No. 43462), dated September 14, 1994, between the
Company and Columbia Gulf Transmission Company (Exhibit
10.30, Form 10-K for the fiscal year ended October 31, 1995).
10.22 Copy of FTS 1 Service Agreement (23,455 Dt per day)(Contract
No. 43461), dated September 14, 1994, between the Company and
Columbia Gulf Transmission Company (Exhibit 10.23, Form 10-K
for the fiscal year ended October 31, 1996).
10.23 Copy of Letter of Agreement of Amendment No. 1 to Gas Storage
Service Agreement (50,798 Mcf maximum storage withdrawal per
day) (Contract No. 6815), dated July 1, 1995, between the
Company and Tennessee Gas Pipeline Company (Exhibit 10.24,
Form 10-K for the fiscal year ended October 31, 1996).
</TABLE>
53
<PAGE> 56
<TABLE>
<S> <C>
10.24 Copy of Letter of Agreement of Amendment No. 1 to Gas Storage
Service Agreement (6,190 Mcf maximum storage withdrawal per
day) (Contract No. 2400), dated July 1, 1995, between the
Company and Tennessee Gas Pipeline Company (Exhibit 10.25,
Form 10-K for the fiscal year ended October 31, 1996).
10.25 Copy of Firm Transportation Agreement (FT/NT), dated
September 22, 1995, between the Company and Texas Gas
Transmission Corporation (Exhibit 10.26, Form 10-K for the
fiscal year ended October 31, 1996).
10.26 Copy of Service Agreement Applicable to Transportation of
Natural Gas Under Rate Schedule FT (X-74 Assignment) (12,875
Dt per day), dated October 18, 1995, between the Company and
CNG Transmission Corporation (Exhibit 10.27, Form 10-K for
the fiscal year ended October 31, 1996).
10.27 Copy of FT Service Agreement #01632 (24,995 Dt per day,
NIPPS), dated October 18, 1995, between the Company and
National Fuel Gas Supply Corporation (Exhibit 10.28, Form
10-K for the fiscal year ended October 31, 1996).
10.28 Copy of Service Agreement (Southern Expansion, FT 53,000 Mcf
per day peak winter months, 47,700 Mcf per day shoulder
winter months) (Contract No. 0.4189), dated November 1, 1995,
between the Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 10.29, Form 10-K for the fiscal year
ended October 31, 1996).
10.29 Copy of Service Agreement (24,140 Mcf per day) (Contract No.
1.1996 NIPPS), dated November 1, 1995, between the Company
and Transcontinental Gas Pipe Line Corporation (Exhibit
10.30, Form 10-K for the fiscal year ended October 31, 1996).
10.30 Copy of Service Agreement (12,785 Mcf per day) (Contract No.
1.1994, FT/NT), dated November 1, 1995, between the Company
and Transcontinental Gas Pipe Line Corporation (Exhibit
10.31, Form 10-K for the fiscal year ended October 31, 1996).
10.31 Copy of Rate Schedule GSS Service Agreement, dated May 15,
1996, between the Company and CNG Transmission Corporation
(Exhibit 10.32, Form 10-K for the fiscal year ended October
31, 1996).
</TABLE>
54
<PAGE> 57
<TABLE>
<S> <C>
10.32 Copy of Employment Agreement between the Company and David J.
Dzuricky, dated May 31, 1996 (Exhibit 10.33, Form 10-K for
the fiscal year ended October 31, 1996).
10.33 Copy of Employment Agreement between the Company and Ray B.
Killough, dated May 31, 1996 (Exhibit 10.34, Form 10-K for
the fiscal year ended October 31, 1996).
10.34 Copy of Employment Agreement between the Company and Ware F.
Schiefer, dated May 31, 1996 (Exhibit 10.35, Form 10-K for
the fiscal year ended October 31, 1996).
10.35 Copy of Employment Agreement between the Company and Thomas
E. Skains, dated May 31, 1996 (Exhibit 10.36, Form 10-K for
the fiscal year ended October 31, 1996).
10.36 Copy of Service Agreement (SE95/96), dated June 25, 1996,
between the Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 10.37, Form 10-K for the fiscal year
ended October 31, 1996).
10.37 Copy of FSS Service Agreement (25,000 dekatherms per day)
(Contract No. 49775), dated November 22, 1995, between the
Company and Columbia Gas Transmission Corporation (Exhibit
10.38, Form 10-K for the fiscal year ended October 31, 1997).
10.38 Copy of SST Service Agreement (25,000 dekatherms per day peak
winter months, 12,500 dekatherms per day shoulder months)
(Contract No. 49773), dated November 22, 1995, between the
Company and Columbia Gas Transmission Corporation (Exhibit
10.39, Form 10-K for the fiscal year ended October 31, 1997).
10.39 Copy of FSS Service Agreement (1,150,166 dekatherms storage
capacity quantity, 19,169 dekatherms maximum daily storage
deliverability) (Contract No. 49777), dated November 22,
1995, between the Company and Columbia Gas Transmission
Corporation.
10.40 Copy of Columbia Gas SST Service Agreement (19,169 dekatherms
per day) dated November 22, 1995, between the Company and
Columbia Gas Transmission Corporation.
</TABLE>
55
<PAGE> 58
<TABLE>
<S> <C>
10.41 Copy of Transco Sunbelt Service Agreement & Precedent
Agreement (41,400 dekatherms of transportation contract
quantity per day), dated January 24, 1997, between the
Company and Transcontinental Gas Pipe Line Corporation.
10.42 Copy of CNG Service Agreement (7,000 dekatherms per day),
dated May 15, 1996, between the Company and CNG Transmission
Corporation.
12 Computation of Ratio of Earnings to Fixed Charges.
23 Independent Auditors' Consent.
27 Financial Data Schedule (for Securities and Exchange
Commission use only).
99 Annual Report on Form 11-K.
</TABLE>
(b) Reports on Form 8-K
None.
56
<PAGE> 59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on January 26, 1999.
PIEDMONT NATURAL GAS COMPANY, INC.
----------------------------------
(Registrant)
By: /s/ John H. Maxheim
-------------------
John H. Maxheim
Chairman of the Board, President
and Chief Executive Officer
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 indicated as of January 26, 1999.
Signature Title
--------- -----
/s/ John H. Maxheim Chairman of the Board,
- --------------------- President and Chief
John H. Maxheim Executive Officer, and
Director
/s/ David J. Dzuricky Senior Vice President-
- ---------------------- Finance
David J. Dzuricky (Principal Financial
Officer)
/s/ Barry L. Guy Vice President and
- --------------------- Controller (Principal
Barry L. Guy Accounting Officer)
57
<PAGE> 60
Signature Title
--------- -----
/s/ Jerry W. Amos Director
- -----------------------------
Jerry W. Amos
/s/ C. M. Butler III Director
- -----------------------------
C. M. Butler III
/s/ Sam J. DiGiovanni Director
- -----------------------------
Sam J. DiGiovanni
/s/ John W. Harris Director
- -----------------------------
John W. Harris
Director
- -----------------------------
Muriel W. Helms
/s/ John F. McNair III Director
- -----------------------------
John F. McNair III
/s/ Ned R. McWherter Director
- -----------------------------
Ned R. McWherter
/s/ Walter S. Montgomery, Jr. Director
- -----------------------------
Walter S. Montgomery, Jr.
Director
- -----------------------------
Donald S. Russell, Jr.
/s/ John E. Simkins, Jr. Director
- -----------------------------
John E. Simkins, Jr.
58
<PAGE> 61
Schedule II
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
For the Years Ended October 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------
Balance at Additions Balance
Beginning Charged to Deductions at End
Description of Period Costs and Expenses (A) of Period
- ---------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Allowance for doubtful accounts:
1998 $2,027 $2,508 $2,221 $2,314
1997 1,960 3,922 3,855 2,027
1996 972 2,846 1,858 1,960
</TABLE>
(A) Uncollectible accounts written off, net of recoveries and adjustments.
59
<PAGE> 62
Piedmont Natural Gas Company, Inc.
Form 10-K
For the Fiscal Year Ended October 31, 1998
Exhibits
<TABLE>
<S> <C>
10.39 Copy of FSS Service Agreement (1,150,166 dekatherms storage
capacity quantity, 19,169 dekatherms maximum daily storage
deliverability)(Contract No. 49777), dated November 22, 1995,
between the Company and Columbia Gas Transmission Corporation.
10.40 Copy of Columbia Gas SST Service Agreement (19,169
dekatherms per day) dated November 22, 1995, between the
Company and Columbia Gas Transmission Corporation.
10.41 Copy of Transco Sunbelt Service Agreement & Precedent Agreement
(41,400 dekatherms of transportation contract quantity per day),
dated January 24, 1997, between the Company and Transcontinental
Gas Pipe Line Corporation.
10.42 Copy of CNG Service Agreement (7,000 dekatherms per day),
dated May 15, 1996, between the Company and CNG
Transmission Corporation.
12 Computation of Ratio of Earnings to Fixed Charges.
23 Independent Auditors' Consent.
27 Financial Data Schedule (for Securities and Exchange use
only).
99 Annual Report on Form 11-K.
</TABLE>
<PAGE> 1
EXHIBIT 10.39
SERVICE AGREEMENT NO. 49777
CONTROL NO. 1995-04-30-0080
FSS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 22nd day of November, 1995, by and
between:
COLUMBIA GAS TRANSMISSION CORPORATION
("SELLER")
AND
PIEDMONT NATURAL GAS CO
("BUYER")
WITNESSETH: That in consideration of the mutual covenants herein contained, the
parties hereto agree as follows:
Section 1. Service to be Rendered. Seller shall perform and Buyer shall receive
the service in accordance with provisions of the effective FSS Rate Schedule
and applicable General Terms and Conditions of Seller's FERC Gas Tariff, Second
Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory
Commission (Commission), as the same may be amended or superseded in accordance
with the rules and regulations of the Commission. Seller shall store quantities
of gas for Buyer up to but not exceeding Buyer's Storage Contract Quantity as
specified in Appendix A, as the same may be amended from time to time by
agreement between Buyer and Seller, or in accordance with the rules and
regulations of the Commission. Service hereunder shall be provided subject to
the provisions of Part 284.223 of Subpart G of the Commission's regulations.
Buyer warrants that service hereunder is being provided on behalf of BUYER.
Section 2. Term. Service under this Agreement shall commence as of APRIL 01,
1998, or upon completion of facilities and shall continue in full force and
effect until OCTOBER 31, 2013, and from YEAR-to-YEAR thereafter unless
terminated by either party upon 2 YEARS' written notice to the other prior to
the end of the initial term granted or any anniversary date thereafter.
Pre-granted abandonment shall apply upon termination of this Agreement, subject
to any right of first refusal Buyer may have under the Commission's regulations
and Seller's Tariff.
Section 3. Rates. Buyer shall pay the charges and furnish the Retainage
percentage set forth in the above-referenced Rate Schedule and specified in
Seller's currently effective Tariff, unless otherwise agreed to by the parties
in writing and specified as an amendment to this Service Agreement.
<PAGE> 2
SERVICE AGREEMENT NO. 49777
CONTROL NO. 1995-04-30-0080
FSS SERVICE AGREEMENT
Section 4. Notices. Notices to Seller under this Agreement shall be addressed
to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention:
Manager-Agreements. Administration and notices to Buyer shall be addressed to
it at:
PEIDMONT NATURAL GAS CO
1915 REXFORD ROAD
CHARLOTTE, NC 28211
ATTN: CHUCK FLEENOR
until changed by either party by written notice.
Section 5. Superseded Agreements. This Service Agreement supersedes and
cancels, as of the effective date hereof, the following Service Agreements:
N/A.
PIEDMONT NATURAL GAS CO
By: /s/ C.W. Fleenor
------------------------------------------
Title: Vice President - Gas Supply
----------------------------------------
Date: November 22, 1995
----------------------------------------
COLUMBIA GAS TRANSMISSION CORPORATION
By: /s/ Stephen M. Warnick
------------------------------------------
Title: Vice President
---------------------------------------
Date: November 27, 1995
----------------------------------------
<PAGE> 3
Revision No.
Control No. 1995-04-30-0080
Appendix A to Service Agreement No. 49777
Under Rate Schedule FSS
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (Buyer) PIEDMONT NATURAL GAS CO
- ---------------- ---------------------------------------------------------------
GFNT / THIS SERVICE AGREEMENT AND ITS EFFECTIVENESS ARE SUBJECT
TO PRECEDENT AGREEMENT NO. 47762 BETWEEN BUYER AND
SELLER DATED MAY 11, 1995.
- ---------------- ---------------------------------------------------------------
<PAGE> 4
Revision No.
Control No. 1995-04-30-0080
Appendix A to Service Agreement No. 49777
Under Rate Schedule FSS
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (Buyer) PIEDMONT NATURAL GAS CO
Storage Contract Quantity 1,150,166 Dth
Maximum Daily Storage Quantity 19,169 Dth per day
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A shall become effective as of APRIL
01, 1998. This Appendix A shall cancel and supersede the previous Appendix A
effective as of N/A, to the Service Agreement referenced above. With the
exception of this Appendix A, all other terms and conditions of said Service
Agreement shall remain in full force and effect.
PIEDMONT NATURAL GAS CO
By: /s/ C.W. Fleenor
------------------------------------------
Title: Vice President - Gas Supply
---------------------------------------
Date: November 22, 1995
---------------------------------------
COLUMBIA GAS TRANSMISSION CORPORATION
By: /s/ Stephen M. Warnick
------------------------------------------
Title: Vice President
---------------------------------------
Date: November 27, 1995
---------------------------------------
<PAGE> 1
EXHIBIT 10.40
SERVICE AGREEMENT NO. 49776
CONTROL NO. 1995-04-30-0079
SST SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 22nd day of November, 1995, by and
between:
COLUMBIA GAS TRANSMISSION CORPORATION
("SELLER")
AND
PIEDMONT NATURAL GAS CO
("BUYER")
WITNESSETH: That in consideration of the mutual covenants herein contained, the
parties hereto agree as follows:
Section 1. Service to be Rendered. Seller shall perform and BUYER shall receive
service in accordance with the provisions of the effective SST Rate Schedule
and applicable General Terms and Conditions of Seller's FERC Gas Tariff, Second
Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory
Commission (Commission), as the same may be amended or superseded in accordance
with the rules and regulations of the Commission. The maximum obligation of
Seller to deliver gas hereunder to or for BUYER, the designation of the points
of delivery at which Seller shall deliver or cause gas to be delivered to or
for BUYER, and the points of receipt at which BUYER shall deliver or cause gas
to be delivered, are specified in Appendix A, as the same may be amended from
time to time by agreement between BUYER and Seller, or in accordance with the
rules and regulations of the Commission. Service hereunder shall be provided
subject to the provisions of Part 284.223 of Subpart G of the Commission's
regulations. BUYER warrants that service hereunder is being provided on behalf
of BUYER.
Section 2. Term. Service under this Agreement shall commence as of NOVEMBER 01,
1998, or upon completion of facilities and shall continue in full force and
effect until OCTOBER 31, 2013, and from YEAR-to-YEAR thereafter unless
terminated by either party upon 2 YEARS' written notice to the other prior to
the end of the initial term granted or any anniversary date thereafter.
Pre-granted abandonment shall apply upon termination of this Agreement, subject
to any right of first refusal BUYER may have under the Commissions regulations
and Seller's Tariff.
Section 3. Rates. BUYER shall pay Seller the charges and furnish Retainage as
described in the above-referenced Rate Schedule, unless otherwise agreed to by
the parties in writing and specified as an amendment to this Service Agreement.
Section 4. Notices. Notices to Seller under this Agreement shall be addressed
to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention:
Manager - Agreements Administration and notices to BUYER shall be addressed to
it at:
<PAGE> 2
SERVICE AGREEMENT NO. 49776
CONTROL NO. 1995-04-30-0079
SST SERVICE AGREEMENT
PIEDMONT NATURAL GAS CO
1915 REXFORD ROAD
CHARLOTTE, NC 28211
ATTN: CHUCK FLEENOR
until changed by either party by written notice.
Section 5. Superseded Agreements. This Service Agreement supersedes and
cancels, as of the effective date hereof, the following Service Agreements: N/A
PIEDMONT NATURAL GAS CO
By: /s/ C.W. Fleenor
-------------------------------------------
Name: Chuck W. Fleenor
----------------------------------------
Title: Vice President - Gas Supply
----------------------------------------
Date: November 22, 1995
----------------------------------------
COLUMBIA GAS TRANSMISSION CORPORATION
By: /s/ S. M. Warnick
-------------------------------------------
Name: Stephen M. Warnick
----------------------------------------
Title: Vice President
----------------------------------------
Date: November 27, 1995
----------------------------------------
<PAGE> 3
Revision No.
Control No. 1995-04-30-0079
Appendix A To Service Agreement No. 49776
Under Rate Schedule SST
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (BUYER) PIEDMONT NATURAL GAS CO
October through March Transportation Demand 19,169 Dth/day
April through September Transportation Demand 9,584 Dth/day
Primary Receipt Points
<TABLE>
<CAPTION>
Scheduling Scheduling Maximum Daily
Point No. Point Name Quantity (Dth/Day)
---------------------------------------------------------------------------
<S> <C> <C>
STOW STORAGE WITHDRAWALS 19,169
</TABLE>
<PAGE> 4
Revision No.
Control No. 1995-04-30-0079
Appendix A to Service Agreement No. 49776
Under Rate Schedule SST
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (BUYER) PIEDMONT NATURAL GAS CO
Primary Delivery Points
<TABLE>
<CAPTION>
- ------------------ ------------------------------- --------------- -------------------------- -------------------------- ----------
Footnote
Maximum S1/
Maximum Daily Delivery
Delivery Obligation Pressure
Scheduling Scheduling Measuring Measuring (Dth/Day) Obligation
Point No. Point name Point No. Point Name (PSIG)
- ------------------ ------------------------------- --------------- -------------------------- -------------------------- ----------
<S> <C> <C> <C> <C> <C>
833097 TRC BOSWELL TAVERN 833097 TRC BOSWELLS TAVERN 19,169 750
- ------------------ ------------------------------- --------------- -------------------------- -------------------------- ----------
</TABLE>
<PAGE> 5
Revision No.
Control No. 1995-04-30-0079
Appendix A to Service Agreement No. 49776
Under Rate Schedule SST
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (BUYER) PIEDMONT NATURAL GAS CO
- --------------- ----------------------------------------------------------------
S1 / IF A MAXIMUM PRESSURE IS NOT SPECIFICALLY STATED, THEN SELLER'S
OBLIGATION SHALL BE AS STATED IN SECTION 13 (DELIVERY PRESSURE)
OF THE GENERAL TERMS AND CONDITIONS.
- --------------- ----------------------------------------------------------------
GFNT / THIS SERVICE AGREEMENT AND ITS EFFECTIVENESS ARE SUBJECT TO
PRECEDENT AGREEMENT NO. 47762 BETWEEN BUYER AND SELLER DATED
MAY 11, 1995.
UNLESS STATION SPECIFIC MDDOS ARE SPECIFIED IN A SEPARATE FIRM
SERVICE AGREEMENT BETWEEN SELLER AND BUYER, SELLER'S AGGREGATE
MAXIMUM DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY OTHER
SERVICE AGREEMENT BETWEEN SELLER AND BUYER, AT THE STATIONS
LISTED ABOVE SHALL NOT EXCEED THE MDDO QUANTITIES SET FORTH
ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOS IN A
SEPARATE FIRM SERVICE AGREEMENT BETWEEN SELLER AND BUYER SHALL
BE ADDITIVE TO THE INDIVIDUAL STATION MDDOS SET FORTH ABOVE.
- --------------------------------------------------------------------------------
<PAGE> 6
Revision No.
Control No. 1995-04-30-0079
Appendix A to Service Agreement No. 49776
Under Rate Schedule SST
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (BUYER) PIEDMONT NATURAL GAS CO
The Master List of Interconnection (MLI) as defined in Section 1 of the General
Terms and Conditions of Seller's Tariff is incorporated herein by reference for
the purposes of listing valid secondary receipt and delivery points.
Service changes pursuant to this Appendix A shall become effective as of
NOVEMBER 01, 1998, or upon completion of facilities. This Appendix A shall
cancel and supersede the previous Appendix A effective as of N/A, to the
Service Agreement referenced above. With the exception of this Appendix A, all
other terms and conditions of said Service Agreement shall remain in full force
and effect.
PIEDMONT NATURAL GAS CO
By: /s/ C.W. Fleenor
------------------------------------------
Name: C.W. Fleenor
---------------------------------------
Title: Vice President - Gas Supply
---------------------------------------
Date: November 22, 1995
---------------------------------------
COLUMBIA GAS TRANSMISSION CORPORATION
By: /s/ S. M. Warnick
------------------------------------------
Name: Stephen M. Warnick
---------------------------------------
Title: Vice President
---------------------------------------
Date: November 27, 1995
---------------------------------------
<PAGE> 1
EXHIBIT 10.41
SERVICE AGREEMENT
THIS AGREEMENT entered into this 24th day of January, 1997, by and
between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation,
hereinafter referred to as "Seller," first party, and PIEDMONT NATURAL GAS
COMPANY, hereinafter referred to as "Buyer," second party,
WITNESSETH
WHEREAS, by order issued December 2, 1996 in Docket No. CP96-16, the
Federal Regulatory Commission has authorized Seller's Sunbelt Expansion Project
(referred to as "SUNBELT"); and
WHEREAS, SUNBELT will add 150,764 Dt (at Seller's system BTU as of the
date of this Agreement and as provided in Section 23 (b) of the General Terms
and Conditions of Seller's FERC Gas Tariff) per day of incremental firm
transportation capacity by a proposed in-service date of November 1, 1997; and
WHEREAS, Buyer has requested firm transportation service under SUNBELT
and has executed with Seller a Precedent Agreement, dated June 2, 1995, for such
service; and
WHEREAS, Seller is willing to provide the requested firm transportation
for Buyer under SUNBELT pursuant to the terms of this Service Agreement and the
Precedent Agreement.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of
Seller's Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to
Seller gas for transportation and Seller agrees to receive, transport and
redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, a
Transportation Contract Quantity ("TCQ") of 41,400 Dt (at Seller's system BTU as
of the date of this Agreement and as provided in Section 23 (b) of the General
Terms and Conditions of Seller's FERC Gas Tariff) per day.
2. Transportation service rendered hereunder shall not be subject
to curtailment or interruption except as provided in Section 11 of the General
Terms and Conditions of Seller's FERC Gas Tariff.
ARTICLE II
POINT(S) OF RECEIPT
Buyer shall deliver or cause to be delivered gas at the point(s) of
receipt hereunder at a pressure sufficient to allow the gas to enter Seller's
pipeline system at the varying pressures that may exist in such system from time
to time; provided, however, the pressure of the gas delivered or caused to be
delivered by Buyer shall not exceed the maximum operating pressure(s) of
Seller's pipeline system at such point(s) of receipt. In the event the maximum
operating pressure(s) of Seller's pipeline system, at the point(s) of receipt
hereunder, is from time to time increased or decreased, then the maximum
allowable pressure(s) of the gas delivered or caused to be delivered
<PAGE> 2
SERVICE AGREEMENT (CONTINUED)
by Buyer to Seller at the point(s) of receipt shall be correspondingly increased
or decreased upon written notification of Seller to Buyer. The point(s) of
receipt for natural gas received for transportation pursuant to this agreement
shall be:
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas
transported hereunder at the following point(s) of delivery and at a pressure(s)
of :
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of November 1, 1997 and shall
remain in force and effect until 8:00 a.m. Eastern Standard Time November 1,
2017 and thereafter until terminated by Seller or Buyer upon at least two (2)
years written notice; provided, however, this agreement shall terminate
immediately and, subject to the receipt of necessary authorizations, if any,
Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable
judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide
adequate security in accordance with Section 32 of the General Terms and
Conditions of Seller's Volume No.1 Tariff. As set forth in Section 8 of Article
II of Seller's August 7, 1989 revised Stipulation and Agreement in Docket Nos.
RP88-68 et. al., (a) pregranted abandonment under Section 284.221(d) of the
Commission's Regulations shall not apply to any long term conversions from firm
sales service to transportation service under seller's Rate Schedule FT and (b)
Seller shall not exercise its right to terminate this service agreement as it
applies to transportation service resulting from conversions from firm sales
service so long as Buyer is willing to pay rates no less favorable than Seller
is otherwise able to collect from third parties for such service.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer
hereunder in accordance with Seller's Rate Schedule FT and the applicable
provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as
filed with the Federal Energy Regulatory Commission, and as the same may be
legally amended or superseded from time to time. Such Rate Schedule and General
Terms and Conditions are by this reference made a part hereof. In the event
Buyer and Seller mutually agree to a negotiated rate and specified term for
service hereunder, provisions governing such negotiated rate (including
surcharges) and term shall be set forth on Exhibit C to this service agreement.
<PAGE> 3
SERVICE AGREEMENT (CONTINUED)
2. Seller and Buyer agree that the quantity of gas that Buyer
delivers or causes to be delivered to Seller shall include the quantity of gas
retained by Seller for applicable compressor fuel, line loss make-up (and
injection fuel under Seller's Rate Schedule GSS, if applicable) in providing the
transportation service hereunder, which quantity may be changed from time to
time and which will be specified in the currently effective Sheet No.44 of
Volume No.1 of this Tariff which relates to service under this agreement and
which is incorporated herein.
3. In addition to the applicable charges for firm transportation
service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall
reimburse Seller for any and all filing fees incurred as a result of Buyer's
request for service under Seller's Rate Schedule FT, to the extent such fees are
imposed upon Seller by the Federal Energy Regulatory Commission or any successor
governmental authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This Agreement supersedes and cancels as of the effective date
hereof the following contract(s) between the parties hereto:
None
2. No waiver by either party of any one or more defaults by the
other in the performance of any provisions of this agreement shall operate or be
construed as a waiver of any future default or defaults, whether of a like or
different character.
3. The interpretation and performance of this agreement shall be
in accordance with the laws of the State of Texas, without recourse to the law
governing conflict of laws, and to all present and future valid laws with
respect to the subject matter, including present and future orders, rules and
regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit
of the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be
considered as duly delivered when mailed to the other party at the following
address:
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
P.O. Box 1396
Houston, Texas, 77251
Attention: Director - Customer Services & Scheduling
<PAGE> 4
SERVICE AGREEMENT (CONTlNUED)
(b) If to Buyer:
Piedmont Natural Gas Company
1915 Rexford Road, 28211
P.O. Box 33068
Charlotte, NC 28233
Attention: Thomas E. Skains
Such addresses may be changed from time to time by mailing appropriate notice
thereof to the other party by certified or registered mail.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be
signed by their respective officers or representatives thereunto duly
authorized.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Seller)
By: /s/ Frank J. Ferazzi
--------------------
Frank J. Ferazzi
Vice President - Customer Service
PIEDMONT NATURAL GAS COMPANY (Buyer)
By: /s/ Tom E. Skains
-----------------
Tom E. Skains
<PAGE> 5
EXHIBIT A
Point(s) of Receipt
<TABLE>
<CAPTION>
Maximum Daily Quantity
At each Receipt Pt. (Dt/d)(1)
<S> <C>
Suction side of Seller's compressor station 65 at the existing
point of interconnection between Seller's southeast Louisiana 32,199
lateral and Seller's mainline.
Points of interconnection between the facilities of Transco and
Transco's Mobile Bay Lateral near Butler in Choctaw County, 9,201
Alabama.
</TABLE>
(1) These quantities do not include the additional quantities of gas to be
retained by Seller for compressor fuel and line loss make-up. Therefore, Buyer
shall also deliver or cause to be delivered at the receipt points such
additional quantities of gas in kind to be retained by Seller for compressor
fuel and line loss make-up.
<PAGE> 6
EXHIBIT B
<TABLE>
<CAPTION>
Maximum Daily Quantity
Point(s) of Delivery and Pressures(2) at each Delivery Pt. (Dt/d)(3)
- ------------------------------------- ------------------------------
<S> <C>
Grover Meter Station at milepost 1247.08 41,400
on Transco's mainline and existing points
of delivery between Transco and Shipper
located on Transco's mainline upstream of
that point.
</TABLE>
(2) Pressure(s) shall not be less than fifty (50) pounds per square inch
gauge or at such other pressures as may be agreed upon in the day-to-day
operations of Buyer and Seller.
(3) Deliveries to or for the account of Shipper at the delivery point(s)
shall be subject to the limits of the Delivery Point Entitlements ("DPE's") of
the entities receiving the gas at the delivery points, as such DPE's are set
forth in Transco's FERC Gas Tariff as amended from time to time.
<PAGE> 7
EXHIBIT C
Specification of Negotiated Rate and Term
Not Applicable
<PAGE> 1
EXHIBIT 10.42
SERVICE AGREEMENT
APPLICABLE TO TRANSPORTATION OF NATURAL GAS
UNDER RATE SCHEDULE FT
AGREEMENT made as of this May 15, 1996, by and between CNG
TRANSMISSION CORPORATION, a Delaware corporation, hereinafter called "Pipeline,"
and NASHVILLE GAS COMPANY, a division of Piedmont Natural Gas Company, Inc., a
North Carolina company, hereinafter called "Customer."
WHEREAS, on October 4, 1993, Pipeline and Rochester Gas and
Electric Corporation ("RG&E") entered into a Marketing Agreement that was
designed to permit Pipeline to assist RG&E in marketing RG&E's on-system storage
demand and capacity, and related transportation capacity on Pipeline;
WHEREAS, Pipeline and Customer have agreed that Customer will
acquire on a permanent basis a part of the RG&E capacity;
Now, THEREFORE, WITNESSETH: That in consideration of the
mutual covenants herein contained, the parties hereto agree as follows:
ARTICLE I
QUANTITIES
A. Commencing on November 1, 1996 and thereafter during the
months of November through March for the remaining term of this agreement,
Pipeline will transport for Customer, on a firm basis, and Customer may furnish,
or cause to be furnished, to Pipeline natural gas for such transportation, and
Customer will accept, or cause to be accepted, delivery from Pipeline of the
quantities Customer has tendered for transportation.
B. The maximum quantities of gas which Pipeline shall deliver and
which Customer may tender shall be as set forth on Exhibit A, attached hereto.
<PAGE> 2
ARTICLE II
RATE
A. Commencing November 1, 1996, and thereafter during the months
of November through March for the remaining term of the agreement, Customer
shall pay Pipeline for transportation services rendered pursuant to this
Agreement, the maximum rates and charges provided under Rate Schedule FT set
forth in Pipeline's effective FERC Gas Tariff, including applicable surcharges
and the Fuel Retention Percentage.
B. Pipeline shall have the right to propose, file and make
effective with the Federal Energy Regulatory Commission or any other body having
jurisdiction, revisions to any applicable rate schedule, or to propose, file,
and make effective superseding rate schedules for the purpose of changing the
rate, charges, and other provisions thereof effective as to Customer; provided,
however, that (i) Section 2 of Rate Schedule FT "Applicability and Character of
Service," (ii) term (iii) quantities, and (iv) points of receipt and points of
delivery shall not be subject to unilateral change under this Article. Said rate
schedule or superseding rate schedule and any revisions thereof which shall be
filed and made effective shall apply to and become a part of this Service
Agreement. The filing of such changes and revisions to any applicable rate
schedule shall be without prejudice to the right of Customer to contest or
oppose such filing and its effectiveness.
C. Notwithstanding Paragraph II.A., above, Customer's agreement
to pay the maximum rates and charges under Rate Schedule FT is subject to a cap
which limits the overall monthly rate, exclusive of any penalty, to be paid by
Customer for service under this Agreement, to an amount not to exceed an
increase in applicable rates and charges at the rate of three percent (3%) per
annum from November 1,1996
ARTICLE III
TERM OF AGREEMENT
Subject to all the terms and conditions herein, this Agreement
shall be effective as of November 1, 1996, and shall continue in effect for a
primary term through and including March 31, 2003, and thereafter for the same
five-month period in each subsequent year, until either party terminates this
Agreement by giving written notice to the other at least twelve months prior to
the start of a winter season term.
2
<PAGE> 3
ARTICLE IV
POINTS OF RECEIPT AND DELIVERY
The Points of Receipt and Delivery and the maximum quantities
for each point for all gas that may be received for Customer's account for
transportation by Pipeline shall be as set forth on Exhibit A, attached hereto.
ARTICLE V
INCORPORATION BY REFERENCE OF TARIFF PROVISIONS
To the extent not inconsistent with the terms and conditions
of this Agreement, the following provisions of Pipeline's effective FERC Gas
Tariff, and any revisions thereof that may be made effective hereafter are
hereby made applicable to and a part hereof by reference:
1. All of the provisions of Rate Schedule FT, or any effective
superseding rate schedule or otherwise applicable rate schedule; and
2. All of the provisions of the General Terms and Conditions, as
they may be revised or superseded from time to time.
ARTICLE VI
MISCELLANEOUS
A. No change, modification or alteration of this Agreement shall
be or become effective until executed in writing by the parties hereto;
provided, however, that the parties do not intend that this Article VI.A.
requires a further written agreement either prior to the making of any request
or filing permitted under Article II hereof or prior to the effectiveness of
such request or filing after Commission approval, provided further, however,
that nothing in this Agreement shall be deemed to prejudice any position the
parties may take as to whether the request, filing or revision permitted under
Article II must be made under Section 7 or Section 4 of the Natural Gas Act.
B. Any notice, request or demand provided for in this Agreement,
or any notice which either party may desire to give the other, shall be in
writing and sent to the following addresses:
Pipeline: CNG Transmission Corporation
445 West Main Street
Clarksburg, West Virginia 26301
Attention: Vice President, Marketing and Customer Services
3
<PAGE> 4
Customer: Nashville Gas Company,
a division of Piedmont Natural Gas Company, Inc.
1915 Rexford Road
Charlotte, North Carolina 28211
Attention: Director - Federal Regulatory and Supply Planning
or at such other address as either party shall designate by formal written
notice.
C. No presumption shall operate in favor of or against either
party hereto as a result of any responsibility either party may have had for
drafting this Agreement.
D. The subject headings of the provisions of this Agreement are
inserted for the purpose of convenient reference and are not intended to become
a part of or to be considered in any interpretation of such provisions.
IN WITNESS WHEREOF, the parties hereto have caused this
Agreement to be signed by their duly authorized officials as of the day and year
first above written.
CNG TRANSMISSION CORPORATION
(PIPELINE)
By: /s/ Joseph A. Curia
---------------------
Its: Vice President
NASHVILLE GAS COMPANY
A DIVISION OF PIEDMONT NATURAL GAS
COMPANY, INC. (CUSTOMER)
By: /s/ C. W. Fleenor
--------------------
Its: Vice President
--------------------
(Title)
4
<PAGE> 5
EXHIBIT A
TO THE FT SERVICE AGREEMENT
DATED MAY 15, 1996
BETWEEN CNG TRANSMISSION CORPORATION, AND
NASHVILLE GAS COMPANY
A DIVISION OF PIEDMONT NATURAL GAS COMPANY, INC.
A. QUANTITIES
The maximum quantities of gas, after allowance for Pipeline's
effective Fuel Retention Percentage, which Pipeline shall deliver and which
Customer may tender shall be as follows:
1. A Maximum Daily Transportation Quantity (MDTQ) of 7,000 Dt, during the
winter season months of November through March;
2. A Maximum Annual Transportation Quantity (MATQ) of 1,057,000 Dt, during
the winter season months of November through March..
B. POINTS OF RECEIPT
1. The Primary Receipt Point(s) for subsequent transportation to Customer
for all storage withdrawal quantities shall be the points of withdrawal
from Pipeline's storage pool(s).
2. These Point(s) of Receipt shall only be Primary, as defined in
Pipeline's FERC Gas Tariff, to the extent that corresponding
nominations for withdrawal from Pipeline's storage pool(s) is provided
under the "Service Agreement Applicable To The Storage of Natural Gas
Under Rate Schedule GSS (Part 284)" between Pipeline and Customer,
dated May 15, 1996.
3. Pipeline may receive quantities for Customer at any Secondary Receipt
Point pursuant to the provisions of Pipeline's FERC Gas Tariff.
C. POINTS OF DELIVERY
Each of the parties will use due care and diligence to assure that
uniform pressures will be maintained at the Delivery Points as reasonably may be
required to render service hereunder, but Pipeline shall not be required to
deliver gas (or to cause gas to be delivered) at pressures higher than the
maximum pressures specified herein.
<PAGE> 6
EXHIBIT A
MAY 15, 1996 FT AGREEMENT
BETWEEN CNG TRANSMISSION CORPORATION
AND NASHVILLE GAS COMPANY
PAGE 2 OF 2
The Point(s) of Delivery to Customer of all firm storage withdrawal
quantities and transportation quantities hereunder shall be as follows:
1. Up to 7,000 Dt per Day at the interconnection of the
facilities of Pipeline and Texas Eastern Transmission
Corporation ("Texas Eastern") or other pipeline(s) in
Westmoreland County, Pennsylvania, known as the Oakford
Interconnection;
2. Up to 7,000 Dt per Day at the interconnection of the
facilities of Pipeline and Texas Eastern in Warren County,
Ohio, known as the Lebanon Interconnection;
3. After February 15 each year, up to 7,000 Dt per Day at the
interconnection of the facilities of Pipeline and Texas
Eastern or Transcontinental Gas Pipe Line Corporation
("Transco") known as the Leidy Interconnection;
4. Up to 7,000 Dt per Day at the interconnectiqn of the
facilities of Pipeline and Tennessee Gas Pipeline Company
("Tennessee") in Kanawha County, West Virginia, known as the
Cornwell Interconnection, or at the Ellisberg Interconnection;
and other interconnects within Tennessee's Zones 3 and
as CNG's operating conditions permit;
5. Up to 7,000 Dt per day, at: the interconnection of the
facilities of Pipeline and Columbia Gas Transmission
Corporation ("Columbia"), at the Oscar Nelson Interconnect; or
at the Rockport Interconnection; and at other interconnects
with Columbia; all as CNG's operating conditions permit;
6. After February 15 each year, up to 7,000 Dt per Day at the
interconnection of the facilities of Pipeline and Transco
known as the Nokesville Interconnection.
<PAGE> 1
EXHIBIT 12
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges
For Fiscal Years Ended October 31, 1994 through 1998
(in thousands except ratio amounts)
-----------------------------------------------------
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Earnings:
Net income from
continuing operations $ 60,313 $ 54,074 $ 48,562 $ 40,310 $35,506
Income taxes 38,807 34,650 30,928 25,442 21,407
Fixed charges 38,415 39,263 37,009 35,651 29,736
-------- -------- -------- -------- -------
Total Adjusted Earnings $137,535 $127,987 $116,499 $101,403 $86,649
======== ======== ======== ======== =======
Fixed Charges:
Interest $ 36,453 $ 36,949 $ 34,511 $ 33,224 $27,671
Amortization of debt
expense 304 346 345 336 334
One-third of rental expense 1,658 1,968 2,153 2,091 1,731
-------- -------- -------- -------- -------
Total Fixed Charges $ 38,415 $ 39,263 $ 37,009 $ 35,651 $29,736
======== ======== ======== ======== =======
Ratio of Earnings to Fixed
Charges 3.58 3.26 3.15 2.84 2.91
======== ======== ======== ======== =======
</TABLE>
<PAGE> 1
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
Piedmont Natural Gas Company, Inc.:
We consent to the incorporation by reference in Post-Effective Amendment No. 3
to Registration Statement No. 2-67478 on Form S-8, in Post-Effective Amendment
No. 2 to Registration Statement No. 33-3815 on Form S-8, in Registration
Statement No. 333-01855 on Form S-3, in Post-Effective Amendment No. 1 to
Registration Statement No. 33-59369 on Form S-3, in Registration Statement No.
33-61093 on Form S-8, in Registration Statement No. 333-26161 on Form S-3, in
Registration Statement No. 333-34433 on Form S-8, in Registration Statement No.
333-34435 on Form S-8, and in Registration Statement No. 333-35213 on Form S-3
of our report dated December 18, 1998, appearing in the Annual Report on Form
10-K of Piedmont Natural Gas Company, Inc. for the year ended October 31, 1998.
/s/ DELOITTE & TOUCHE LLP
Charlotte, North Carolina
January 26, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
FINANCIAl STATEMENTS OF PIEDMONT NATURAL GAS FOR THE TWELVE MONTH PERIOD ENDED
OCTOBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> OCT-31-1998
<PERIOD-START> NOV-01-1997
<PERIOD-END> OCT-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 964,340
<OTHER-PROPERTY-AND-INVEST> 26,300
<TOTAL-CURRENT-ASSETS> 142,542
<TOTAL-DEFERRED-CHARGES> 29,662
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,162,844
<COMMON> 279,709
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 178,559
<TOTAL-COMMON-STOCKHOLDERS-EQ> 458,268
0
0
<LONG-TERM-DEBT-NET> 371,000
<SHORT-TERM-NOTES> 32,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 10,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 291,576
<TOT-CAPITALIZATION-AND-LIAB> 1,162,844
<GROSS-OPERATING-REVENUE> 765,277
<INCOME-TAX-EXPENSE> 37,249
<OTHER-OPERATING-EXPENSES> 636,871
<TOTAL-OPERATING-EXPENSES> 674,120
<OPERATING-INCOME-LOSS> 91,157
<OTHER-INCOME-NET> 2,343
<INCOME-BEFORE-INTEREST-EXPEN> 93,500
<TOTAL-INTEREST-EXPENSE> 33,187
<NET-INCOME> 60,313
0
<EARNINGS-AVAILABLE-FOR-COMM> 60,313
<COMMON-STOCK-DIVIDENDS> 39,004
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 123,388
<EPS-PRIMARY> 1.98
<EPS-DILUTED> 1.96
</TABLE>
<PAGE> 1
EXHIBIT 99
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
-------------
FORM 11-K
-------------
For Annual Reports of
Employee Stock Purchase, Savings and Similar Plans
Pursuant to Section 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended October 31, 1998
Commission file number 1-6196
A. Full title of the plans and address of the plans, if different from that of
the issuer named below:
Piedmont Natural Gas Company Employee Stock Purchase Plan
Piedmont Natural Gas Company Employee Stock Ownership Plan
B. Name of issuer of the securities held pursuant to the plans and the address
of its principal executive office:
PIEDMONT NATURAL GAS COMPANY, INC.
1915 Rexford Road
Charlotte, North Carolina 28211
<PAGE> 2
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK PURCHASE PLAN
There were no material changes in the provisions of the Piedmont
Natural Gas Company Employee Stock Purchase Plan (ESPP) during the year ended
October 31, 1998. Financial statements are not required under Article 6A of
Regulation S-X since the shares purchased by employees under the ESPP are not
held by a trustee. Participating employees are furnished a statement after each
stock purchase date (June 30 and December 31) showing the number of shares and
the purchase price of any stock purchased for them and the balance remaining to
their credit. At October 31, 1998, 550 employees participated in the ESPP.
1
<PAGE> 3
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK OWNERSHIP PLAN
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
October 31, 1998 and 1997
Assets:
<TABLE>
<CAPTION>
1998 1997
---- ----
<S> <C> <C>
Investment in Common Stock of Piedmont Natural
Gas Company, Inc., at fair value - 217,298
and 231,860 shares (cost $2,781,669 and
$2,662,664) at 1998 and 1997, respectively $7,551,106 $6,492,080
Receivable on sale of stock 117 75,522
Short-term investment fund, at cost which
approximates fair value 1,067 482
Other 49 56
---------- ----------
Net Assets Available for Benefits $7,552,339 $6,568,140
========== ==========
</TABLE>
See notes to financial statements.
2
<PAGE> 4
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK OWNERSHIP PLAN
STATEMENTS OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
For the Years Ended October 31, 1998, 1997 and 1996
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Dividend and interest income $ 288,089 $ 281,528 $ 269,400
Gain (loss) on sale of assets (Note 3) 22,398 44,876 (30,109)
Net appreciation in fair value
of investment in Common Stock 1,486,211 764,046 624,623
Withdrawals by participants (812,499) (413,866) (165,310)
----------- ----------- -----------
Net increase 984,199 676,584 698,604
Net assets available for benefits:
Beginning of year 6,568,140 5,891,556 5,192,952
----------- ----------- -----------
End of year $ 7,552,339 $ 6,568,140 $ 5,891,556
=========== =========== ===========
</TABLE>
See notes to financial statements.
3
<PAGE> 5
PIEDMONT NATURAL GAS COMPANY EMPLOYEE STOCK OWNERSHIP PLAN
NOTES TO FINANCIAL STATEMENTS
1. DESCRIPTION OF THE PLAN
The Piedmont Natural Gas Company (Company) Employee Stock Ownership
Plan (ESOP) was established to enable employees to acquire Common Stock
of the Company. Through 1986, the Company contributed to the ESOP
amounts equal to a tax credit based on aggregate compensation paid or
accrued to all employees under the ESOP. The Tax Reform Act of 1986
eliminated the tax credit allowance, and no Company contributions have
been made since 1987.
The ESOP is administered by an ESOP Administration Committee approved
by the Company's Board of Directors. The Company pays the
administrative expenses of the ESOP. The Trust Client Services
department of Wachovia Bank of North Carolina, N.A., serves as the
trustee and custodian of the ESOP. The ESOP is subject to the
provisions of the Employee Retirement Income Security Act of 1974
(ERISA).
A participant in the ESOP is defined as an active eligible employee
with a balance in his or her ESOP account. An employee is eligible to
participate following the later of the date on which he or she
completes at least 1,000 hours of service during a period of 12
consecutive months or attains age 21. However, employees who reached
eligibility subsequent to the termination of Company contributions are
not considered participants as no contributions have been credited to
them.
Separate accounts are maintained for each participant to reflect the
allocation of contributions and subsequent dividend and investment
income. Any income credited to participants is reinvested in Common
Stock. The ESOP provides for immediate vesting.
Distributions from the ESOP are made either at early retirement (age 55
and 10 years of service), at normal retirement (age 65), at actual
retirement for a participant who remains employed after attaining
normal retirement age, at permanent disability or at death of the
participant. The Administration Committee of the ESOP may, in its sole
discretion, direct an earlier distribution following a participant's
termination of employment.
4
<PAGE> 6
A participant who has reached age 55 and completed ten years of
participation in the ESOP has the right to diversify a portion of his
or her account balance each year during the qualified election period.
The Company may terminate the ESOP at any time and may either cause the
ESOP to continue operations until the ESOP trustee has distributed all
benefits or cause the assets of the ESOP to be liquidated and
distributed.
2. BASIS OF ACCOUNTING
The financial statements are presented on the accrual basis of
accounting.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets,
liabilities, and changes therein, and disclosure of contingent assets
and liabilities. Actual results could differ from those estimates.
The investment in the Company's Common Stock is valued at fair value on
October 31, 1998 and 1997, determined by quoted market prices on the
New York Stock Exchange. Dividend income is accrued on the ex-dividend
date. Purchases and sales of securities are recorded on a trade-date
basis. Realized gains and losses from security transactions are
reported on the average cost method.
3. GAIN (LOSS) ON SALE OF ASSETS
The gain (loss) on sale of assets for the years ended October 31, 1998,
1997 and 1996, is computed as follows:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Gross proceeds $184,200 $448,975 $ 1,397
Historical cost 161,802 404,099 31,506
-------- -------- --------
Gain (loss) $ 22,398 $ 44,876 $(30,109)
======== ======== ========
</TABLE>
5
<PAGE> 7
4. NET ASSETS AVAILABLE FOR BENEFITS
Net assets available for benefits adjusted for the payable to
participants for withdrawals for the years ended October 31, 1998, 1997
and 1996, are as follows:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Net assets available for
benefits at end of year $7,552,339 $6,568,140 $5,891,556
Payable to participants
for withdrawals 114,003 205,919 156,025
---------- ---------- ----------
Net assets available for
benefits adjusted for
payable to participants
for withdrawals $7,438,336 $6,362,221 $5,735,531
========== ========== ==========
</TABLE>
5. TAX STATUS
The ESOP is qualified under Sections 401 and 409 of the Internal
Revenue Code of 1986, as amended (the Tax Code). The Internal Revenue
Service has informed the Company by letter that the ESOP, as designed,
is qualified, and the trust established under the ESOP is exempt from
income taxes under Section 501(a) of the Tax Code. The ESOP has been
amended since receiving the determination letter. However, the ESOP
administrator and tax counsel believe that the ESOP is currently
designed and being operated in compliance with the applicable
requirements of the Code.
The amount of the distribution under the ESOP is taxed to the recipient
as ordinary income, with the taxable amount attributed to Common Stock
distributed to a participant being the lesser of the cost to the trust
or its fair market value on the date of distribution. Any increase in
the value of the Common Stock is not taxed during the period that the
stock is held by the trust nor upon its distribution to the
participant. If stock is sold by a participant after distribution, the
sale is subject to capital gain or loss treatment, depending on the
sales price of the stock.
6
<PAGE> 8
INDEPENDENT AUDITORS' REPORT
Piedmont Natural Gas Company
Employee Stock Ownership Plan:
We have audited the accompanying statements of net assets available for benefits
of the Piedmont Natural Gas Company Employee Stock Ownership Plan (the Plan) as
of October 31, 1998 and 1997, and the related statements of changes in net
assets available for benefits for each of the three years in the period ended
October 31, 1998. These financial statements are the responsibility of the
Plan'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 financial statements referred to above present fairly, in
all material respects, the net assets available for benefits of the Plan as of
October 31, 1998 and 1997, and the changes in net assets available for benefits
for each of the three years in the period ended October 31, 1998 in conformity
with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
- -------------------------
DELOITTE & TOUCHE LLP
Charlotte, North Carolina
January 18, 1999
7
