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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended July 31, 1999
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 1-6196
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Piedmont Natural Gas Company, Inc.
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(Exact name of registrant as specified in its charter)
North Carolina 56-0556998
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1915 Rexford Road, Charlotte, North Carolina 28211
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 704-364-3120
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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 the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at September 2, 1999
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Common Stock, no par value 31,181,309
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(in thousands)
---------------------------------------------------
<TABLE>
<CAPTION>
July 31, October 31,
1999 1998
Unaudited Audited
---------- ----------
<S> <C> <C>
ASSETS
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Utility Plant, at original cost $1,416,493 $1,345,925
Less accumulated depreciation 412,233 381,585
---------- ----------
Utility plant, net 1,004,260 964,340
---------- ----------
Other Physical Property (net of accumulated
depreciation of $18,885 in 1999 and $17,406 in 1998) 25,764 26,300
---------- ----------
Current Assets:
Cash and cash equivalents 9,705 9,720
Restricted cash 39,711 27,484
Receivables (less allowance for doubtful
accounts of $1,849 in 1999 and $2,314 in 1998) 45,516 24,459
Gas in storage 37,499 42,465
Deferred cost of gas 2,693 5,217
Refundable income taxes 0 13,897
Other 16,970 19,300
---------- ----------
Total current assets 152,094 142,542
---------- ----------
Deferred Charges and Other Assets 43,350 29,662
---------- ----------
Total $1,225,468 $1,162,844
========== ==========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock equity:
Common stock $ 293,286 $ 279,709
Retained earnings 214,168 178,559
---------- ----------
Total common stock equity 507,454 458,268
Long-term debt 333,000 371,000
---------- ----------
Total capitalization 840,454 829,268
---------- ----------
Current Liabilities:
Current maturities of long-term debt and
sinking fund requirements 46,000 10,000
Notes payable 59,000 32,000
Accounts payable 46,482 67,296
Deferred income taxes 19,328 15,367
Taxes accrued 7,132 12,893
Refunds due customers 36,715 28,408
Other 13,970 19,884
---------- ----------
Total current liabilities 228,627 185,848
---------- ----------
Deferred Credits and Other Liabilities 156,387 147,728
---------- ----------
Total $1,225,468 $1,162,844
========== ==========
</TABLE>
See notes to condensed consolidated financial statements.
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PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Condensed Statements of Consolidated Income (Unaudited)
(in thousands except per share amounts)
-------------------------------------------------------
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
---------------------- ----------------------- -----------------------
1999 1998 1999 1998 1999 1998
------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $96,728 $103,026 $591,717 $677,758 $679,235 $777,440
Cost of Gas 52,303 57,527 311,962 395,185 359,198 454,646
------- -------- -------- -------- -------- --------
Margin 44,425 45,499 279,755 282,573 320,037 322,794
------- -------- -------- -------- -------- --------
Other Operating Expenses:
Operations 25,520 25,713 76,027 77,236 103,724 107,680
Maintenance 3,846 3,702 11,399 10,463 15,643 14,366
Depreciation 11,100 10,490 32,615 31,472 43,318 41,529
General taxes 6,276 6,166 24,517 26,467 30,684 32,362
Income taxes (4,177) (3,655) 43,630 43,933 36,958 36,593
------- -------- -------- -------- -------- --------
Total other operating expenses 42,565 42,416 188,188 189,571 230,327 232,530
------- -------- -------- -------- -------- --------
Operating Income 1,860 3,083 91,567 93,002 89,710 90,264
Other Income, Net (2,036) (917) (243) 2,560 (483) 3,769
------- -------- -------- -------- -------- --------
Income Before Utility Interest Charges (176) 2,166 91,324 95,562 89,227 94,033
Utility Interest Charges 8,040 8,419 24,309 25,103 32,357 33,308
------- -------- -------- -------- -------- --------
Net Income ($8,216) ($ 6,253) $ 67,015 $ 70,459 $ 56,870 $ 60,725
======= ======== ======== ======== ======== ========
Average Shares of Common Stock:
Basic 31,076 30,535 30,948 30,408 30,876 30,333
Diluted 31,076 30,535 31,178 30,695 31,118 30,635
Earnings Per Share of Common Stock:
Basic ($ 0.26) ($ 0.20) $ 2.17 $ 2.32 $ 1.84 $ 2.00
Diluted ($ 0.26) ($ 0.20) $ 2.15 $ 2.30 $ 1.83 $ 1.98
Cash Dividends Per Share
of Common Stock $0.345 $ 0.325 $ 1.015 $ 0.955 $ 1.34 $ 1.26
</TABLE>
See notes to condensed consolidated financial statements.
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PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Condensed Statements of Consolidated Cash Flows (Unaudited)
(in thousands)
-----------------------------------------------------------
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
-------------------- -------------------- ---------------------
1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Cash Flows from Operating Activities:
Net income ($ 8,216) ($ 6,253) $ 67,015 $ 70,459 $ 56,870 $ 60,725
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization 12,077 11,550 35,685 34,639 47,255 45,681
Other, net 134 (486) 20 1,524 929 3,216
Change in operating assets and liabilities (40,892) (17,237) (36,844) 8,779 (31,148) (8,999)
-------- -------- -------- -------- --------- --------
Net cash provided by (used in) operating activities (36,897) (12,426) 65,876 115,401 73,906 100,623
-------- -------- -------- -------- --------- --------
Cash Flows from Investing Activities:
Utility construction expenditures (25,011) (24,113) (70,234) (57,908) (103,266) (79,714)
Other (322) (166) (1,127) (502) (1,737) (1,036)
-------- -------- -------- -------- --------- --------
Net cash used in investing activities (25,333) (24,279) (71,361) (58,410) (105,003) (80,750)
-------- -------- -------- -------- --------- --------
Cash Flows from Financing Activities:
Increase (Decrease) in bank loans, net 59,000 -- 27,000 (25,000) 59,000 --
Retirement of long-term debt (2,000) (2,000) (2,000) (2,000) (10,000) (10,000)
Issuance of common stock through dividend
reinvestment and employee stock plans 4,111 4,002 11,877 11,500 15,513 14,848
Dividends paid (10,719) (9,920) (31,407) (29,042) (41,370) (38,225)
-------- -------- -------- -------- --------- --------
Net cash provided by (used in) financing activities 50,392 (7,918) 5,470 (44,542) 23,143 (33,377)
-------- -------- -------- -------- --------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (11,838) (44,623) (15) 12,449 (7,954) (13,504)
Cash and Cash Equivalents at Beginning of Period 21,543 62,282 9,720 5,210 17,659 31,163
-------- -------- -------- -------- --------- --------
Cash and Cash Equivalents at End of Period $ 9,705 $ 17,659 $ 9,705 $ 17,659 $ 9,705 $ 17,659
======== ======== ======== ======== ========= ========
Cash Paid During the Period for:
Interest $ 11,314 $ 11,426 $ 27,441 $ 28,041 $ 32,625 $ 33,781
Income taxes $ 199 $ 299 $ 38,259 $ 46,875 $ 38,525 $ 47,051
</TABLE>
See notes to condensed consolidated financial statements.
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PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. Independent auditors have not audited the condensed consolidated
financial statements. These financial statements should be read in
conjunction with the Notes to Consolidated Financial Statements included
in our 1998 Annual Report.
2. In our opinion, the unaudited condensed consolidated financial statements
include all normal recurring adjustments necessary for a fair statement
of financial position at July 31, 1999, and October 31, 1998, and the
results of operations and cash flows for the three months, nine months
and twelve months ended July 31, 1999 and 1998.
We make estimates and assumptions when preparing financial statements.
Those estimates and assumptions affect the reported amounts of assets and
liabilities and the 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 our estimates.
3. Our business is seasonal in nature. The results of operations for the
three-month and nine-month periods ended July 31, 1999, do not
necessarily reflect the results to be expected for the full year.
4. Basic earnings per share are computed by dividing net income by the
weighted average number of shares of common stock outstanding for the
period. Diluted earnings per share reflect the potential dilution that
could occur when common stock equivalents are added to common shares
outstanding. Shares that may be issued under the long-term incentive plan
are our only common stock equivalents. A reconciliation of basic and
diluted earnings per share is shown below:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
---------------------- --------------------- ---------------------
(in thousands except per share amounts)
1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Net Income $ (8,216) $ (6,253) $ 67,015 $ 70,459 $ 56,870 $ 60,725
======== ======== ======== ======== ======== ========
Average shares of common stock
outstanding for basic earnings per share 31,076 30,535 30,948 30,408 30,876 30,333
Contingently issuable shares under
the long-term incentive plan (a) -- -- 230 287 242 302
-------- -------- -------- -------- -------- --------
Average shares of dilutive stock 31,076 30,535 31,178 30,695 31,118 30,635
======== ======== ======== ======== ======== ========
Earnings Per Share:
Basic $ (.26) $ (.20) $ 2.17 $ 2.32 $ 1.84 $ 2.00
Diluted $ (.26) $ (.20) $ 2.15 $ 2.30 $ 1.83 $ 1.98
</TABLE>
(a) For the three months ended July 31, 1999 and 1998, the inclusion of 229 and
280 contingently issuable shares, respectively, would be antidilutive.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Forward-Looking Statements
Our discussion contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. Statements concerning plans,
objectives, proposed capital expenditures and future events or performance are
some of the items included in forward-looking statements. Our statements reflect
our current expectations and involve a number of risks and uncertainties.
Although we believe that our expectations are based on reasonable assumptions,
we can give no assurances that these expectations will be achieved. 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,
-- the ability to meet internal performance goals,
-- the capital intensive nature of our 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
-- unexpected problems related to our internal Year 2000
initiative as well as potential adverse consequences related
to third-party Year 2000 compliance.
Financial Condition
We finance current cash requirements primarily from operating cash flows and
short-term borrowings. Various banks provide lines of credit totaling $75
million for these direct short-term borrowings. We sell common stock and
long-term debt to cover cash requirements when market and other conditions favor
such long-term financing. Our dividend reinvestment and stock purchase plan is
also a source of capital.
Our natural gas business is seasonal in nature causing fluctuations in balances
in accounts receivable from customers, inventories of stored natural gas and
accounts payable to suppliers. From April 1 to October 31, we build up natural
gas inventories by injecting gas into storage for sale in the colder months.
Inventory of stored gas and accounts payable decreased and accounts receivable
increased from October 31, 1998, to July 31, 1999, due to this seasonality and
the
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demand for gas during the winter season. Most of our annual earnings are
realized in the winter period, which is the first five months of our fiscal
year.
We have a substantial capital expansion program for construction of distribution
facilities, purchase of equipment and other general improvements funded through
sources noted above. The capital expansion program supports our approximately 5%
current annual growth in customer base. Utility construction expenditures for
the three months ended July 31, 1999, were $25.9 million, compared with $24.5
million for the same period in 1998. Utility construction expenditures for the
nine months ended July 31, 1999, were $72.7 million, compared with $59.2 million
for the same period in 1998. Utility construction expenditures for the
twelve-month period ended July 31, 1999, were $107 million, compared with $81.2
million for the same period in 1998.
We have given notice of intent to prepay on September 15, 1999, our 10.02% and
10.11% Senior Notes due in 2003 and 2004, respectively, in the amount of $36
million, plus accrued interest plus an early payment premium of $1.1 million. To
fund this prepayment, we have the option of issuing medium-term notes under a
shelf registration statement for $150 million of debt securities that was filed
with the Securities and Exchange Commission in 1997 or drawing on existing lines
of credit. The amount and timing of any debt to be issued will depend on several
factors, including capital requirements and financial market conditions.
At July 31, 1999, our capitalization consisted of 40% in long-term debt and 60%
in common equity.
Results of Operations
We will discuss the results of operations for the three months, nine months and
twelve months ended July 31, 1999, compared with similar periods in 1998.
Margin
Margin (operating revenues less cost of gas) for the three months ended July 31,
1999, decreased $1.1 million compared with the same period in 1998 primarily for
the reasons listed below.
-- Margin was reduced in North Carolina, effective for bills
rendered after August 1, 1999 (which included volumes
delivered in July), due to the elimination of the gross
receipts tax which was previously included in rates billed to
customers. Gross receipts tax expense in the same amount was
also included in general taxes. For a further explanation of
the tax change, see Item 5 in Part II of this report.
-- Margin was reduced in South Carolina, effective November 1,
1998, as ordered by the Public Service Commission of South
Carolina (PSCSC), to eliminate the recovery of demand side
management (DSM) costs included in rates.
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-- Adjustments required by regulatory authorities resulted in
margin decreases from the same period in 1998.
An increase of 130,000 dekatherms in delivered volumes of natural gas, which we
refer to as system throughput, partially offset these decreases from the same
period in 1998.
Margin for the nine months ended July 31, 1999, decreased $2.8 million compared
with the same period in 1998 primarily for the reasons listed below.
-- Margin was reduced due to elimination of the gross receipts
tax as noted above.
-- Delivered volumes of natural gas decreased from the same
period in 1998 by 6.2 million dekatherms, a 5% decrease, due
primarily to weather which was 10% warmer than the same period
in 1998.
-- We changed rates in South Carolina to eliminate the recovery
of DSM costs as noted above.
Weather which was 14% warmer than normal generated operating revenues of $19.7
million from the weather normalization adjustment (WNA) for a partial offset of
these decreases in margin for the nine-month period. The same period in 1998
reflected operating revenues of $5 million from the WNA from 5%
warmer-than-normal weather.
Margin for the twelve months ended July 31, 1999, decreased $2.8 million
compared with the same period in 1998 primarily for the reasons listed below.
-- Margin was reduced due to the elimination of the gross
receipts tax as noted above.
-- Delivered volumes of natural gas decreased from the same
period in 1998 by 3.6 million dekatherms, a 3% decrease, due
primarily to weather which was 11% warmer than the same period
in 1998.
-- We changed rates in South Carolina to eliminate the recovery
of DSM costs as noted above.
Weather which was 16% warmer than normal generated operating revenues of $19.7
million from the WNA for a partial offset of these decreases in margin for the
twelve-month period. The same period in 1998 reflected operating revenues of $5
million from the WNA from 5% warmer-than-normal weather.
Our rate schedules include provisions permitting the recovery of prudently
incurred gas costs. Regulatory commissions in North Carolina and South Carolina
require annual prudence reviews covering a historical twelve-month period;
however, such review is not required in Tennessee.
We revise rates in all three states periodically without formal rate proceedings
to reflect changes in the cost of gas. Charges to cost of gas are based on the
amount recoverable under approved rate schedules. The net of any over- or
under-recoveries of gas costs are added to or deducted from cost of gas and
included in refunds due customers in the financial statements.
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Operations and Maintenance Expenses
Operations and maintenance expenses for the three months ended July 31, 1999,
compared with the same period in 1998 decreased by $49,000 primarily for the
reasons listed below.
-- Decrease in office supplies expense,
-- Decrease in risk insurance expense and
-- Decrease in employee benefits expense.
An increase in outside labor expense partially offset these decreases for the
three months ended July 31, 1999, compared with the same period in 1998.
Operations and maintenance expenses for the nine months ended July 31, 1999,
compared with the same period in 1998 decreased by $273,000 primarily for the
reasons listed below.
-- Decrease in the provision for uncollectibles,
-- Decrease in risk insurance expense,
-- Decrease in advertising expense and
-- Decrease in employee benefits expense.
An increase in outside labor expense partially offset these decreases for the
nine months ended July 31, 1999, compared with the same period in 1998.
Operations and maintenance expenses for the twelve months ended July 31, 1999,
compared with the same period in 1998 decreased by $2.7 million primarily for
the reasons listed below.
-- Decrease in payroll expense,
-- Decrease in the provision for uncollectibles and
-- Decrease in advertising expense.
An increase in outside labor expense partially offset these decreases for the
twelve months ended July 31, 1999, compared with the same period in 1998.
General Taxes
General taxes for the three months ended July 31, 1999, compared with the same
period in 1998 increased slightly by $110,000 primarily for the reasons listed
below.
-- Increase in franchise taxes and
-- Increase in payroll taxes.
A decrease in gross receipts tax expense partially offset these increases for
the three months ended July 31, 1999, compared with the same period in 1998
primarily due to the elimination of the tax as noted above. For a further
explanation of the tax change, see Item 5 in Part II of this report.
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General taxes for the nine months ended July 31, 1999, compared with the same
period in 1998 decreased by $1.9 million primarily for the reasons listed below.
-- Decrease in gross receipts tax expense as noted above,
-- Decrease in property taxes and
-- Decrease in payroll taxes.
An increase in franchise taxes partially offset these decreases for the nine
months ended July 31, 1999, compared with the same period in 1998.
General taxes for the twelve months ended July 31, 1999, compared with the same
period in 1998 decreased by $1.7 million primarily for the reasons listed below.
-- Decrease in gross receipts tax expense as noted above and
-- Decrease in payroll taxes.
Increases in property taxes and franchise taxes partially offset these decreases
for the twelve months ended July 31, 1999, compared with the same period in
1998.
Other Income
Other income for the three months ended July 31, 1999, compared with the same
period in 1998 decreased by $1.1 million. The primary reasons for these
decreases are listed below.
-- Decrease in earnings from unregulated retail energy marketing
services and
-- Decrease in interest income.
These decreases in other income for the three-month period were partially offset
by the following increases.
-- Increase in earnings from jobbing operations,
-- Increase in earnings from non-utility LNG operations and
-- Increase in the allowance for funds used during construction.
Other income for the nine months and twelve months ended July 31, 1999, compared
with the same periods in 1998 decreased by $2.8 million and $4.3 million,
respectively. The primary reasons for these decreases are listed below.
-- Decrease in earnings from propane operations due to warmer
weather,
-- Decrease in earnings from unregulated retail energy marketing
services and
-- Decrease in interest income.
These decreases in other income for the nine-month and twelve-month periods were
partially offset by the following increases.
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-- Increase in earnings from merchandise operations,
-- Increase in earnings from non-utility LNG operations and
-- Increase in the allowance for funds used during construction.
Decreases in earnings from unregulated retail energy marketing services result
from start-up costs incurred by our retail marketing joint venture, SouthStar
Energy Services LLC (SouthStar), associated with its entry into the unregulated
retail gas market in Georgia. Due to its marketing efforts, SouthStar will be
serving over 450,000 new gas customers in Georgia as of October 1, 1999.
Utility Interest Charges
Utility interest charges for the three months and nine months ended July 31,
1999, compared with the same periods in 1998 decreased by $379,000 and $794,000,
respectively. The primary reasons for these decreases are listed below.
-- Decrease in interest on long-term debt from lower amounts of
debt outstanding and
-- Decrease in interest on refunds due customers.
Increases in interest on short-term debt due to higher amounts outstanding but
at slightly lower interest rates partially offset these decreases for the
three-month and nine-month periods ended July 31, 1999, compared with the same
periods in 1998.
Utility interest charges for the twelve months ended July 31, 1999, compared
with the same period in 1998 decreased by $951,000 primarily due to a decrease
in interest on long-term debt from lower amounts of debt outstanding. Increases
in interest on refunds due customers due to higher amounts outstanding and in
interest on short-term debt at higher amounts outstanding but at slightly lower
interest rates partially offset this decrease.
Year 2000
Overview
In 1996, we formed a Year 2000 Project Team and selected a consulting firm to
help us. Since that time, we have undertaken a comprehensive company-wide
project to inventory, assess, remediate and test hardware, software and embedded
systems intended to make them Year 2000 ready. In December 1997, we formed a
Year 2000 Sub-Committee composed of senior-level executives to monitor Year 2000
efforts and assure that our core systems would be Year 2000 ready prior to the
turn of the century.
In support of Year 2000 efforts, we also formed a Test Management Group who
established specific testing processes and procedures that are being used with
both Information Technology (IT) and non-IT systems. The testing methodology
includes the use of various testing techniques such as regression, system,
parallel, interface and stress testing. Test plans include additional
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testing scenarios to demonstrate Year 2000 readiness. The Test Management Group
reviews the results of these tests to ensure that a particular system's
functional and Year 2000 readiness testing matches the testing methodology.
Although extensive testing is completed prior to system implementations, we are
performing additional testing during 1999. During the third calendar quarter of
1999, we are conducting a final Year 2000 company-wide review to verify that all
issues have been adequately addressed.
Readiness of Systems, Applications and Embedded Devices
We have 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, we developed a Year 2000 Master Plan 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, we classified each system, application or
device as either mission critical, support intensive or low impact based on
certain factors that describe its relative importance to the business. The Year
2000 Sub-Committee reviewed and approved these classifications and strategies.
The four criteria used to classify a system, application or device as mission
critical are as follows, listed in order of importance:
-- provide for public or employee safety,
-- provide for gas supply or service to customers,
-- provide the ability to comply with regulatory or legal
requirements and
-- provide a sustained level of business and income.
Support-intensive systems 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."
We completed the implementation of Year 2000 ready solutions for our
mission-critical applications by December 31, 1998. Examples of these
applications are SCADA (real-time system pressure and flow monitoring), Customer
Information, Telemetering, Materials Management, Gas Management, Accounts
Payable, General Ledger and Asset Management. Many of our support-intensive and
low-impact applications were also Year 2000 ready by the end of December 1998.
We have one remaining application to implement and it is scheduled to be
completed by September 30, 1999.
We completed the inventory and assessment of embedded systems and found that
approximately 4% of the devices had a Year 2000 impact. We developed a
remediation strategy for each of the impacted devices and have completed the
upgrades of all of those systems.
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Suppliers and Vendors
During our efforts, it became clearly evident that we are dependent on a variety
of vendors and suppliers to provide essential equipment, materials and services.
In many ways, our ability to continue normal business operations is dependent on
the timely delivery of these goods and services. We have committed significant
resources to contacting our critical suppliers and assessing their readiness. In
cases where suppliers are non-responsive or demonstrate a significant risk of
being non-compliant, we have identified alternative sources. In other cases, we
are planning to increase our inventory levels of specific critical items. Our
intent is to avoid or minimize the impact of any disruptions associated with the
inability of a given supplier to respond to our business needs.
Risks
The Year 2000 Sub-Committee reviewed and approved ten specific "worst case"
scenarios. We designated plan owners for each scenario and they developed
contingency plans to address each of the items. Our worst case scenarios are as
follows:
-- electrical outages
-- telecommunications outages
-- natural gas shortages
-- water outages
-- vehicle fuel shortages
-- staff shortages
-- postal service outages
-- data center services outages
-- emergency response impacts and
-- financial institution impacts.
To mitigate risks, minimize potential impacts and provide safe uninterrupted
service to customers, we currently have in place the following:
-- a territory-wide radio system to overcome telecommunications
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.
Contingency Planning
We have completed the development of contingency plans in the areas of
facilities, applications, suppliers, embedded technologies and worst case
scenarios. We followed a standard template that was developed based on
guidelines outlined by the General Accounting Office for Year 2000 Business
Continuity and Contingency Planning. The contingency planning process assumed
that there will be multiple concurrent failures of systems, thus requiring an
additional
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level of planning to compensate for any assumptions that are made within a
particular contingency plan. During the third calendar quarter of 1999, we are
testing selected contingency plans based on potential risks. Further drills will
be conducted nearer the end of 1999 to reinforce the processes and procedures
outlined in the plans.
In an effort to reduce our risk from staff shortages, we established a new
policy regarding the vacation schedules of personnel before and after January 1,
2000. The policy states that employee vacations will be suspended during the
last two weeks of December 1999 and the month of January 2000. The policy
provides for certain exceptions and reserves the right for management to
determine final work or vacation schedules based on the needs of our business
and customers.
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.
Financial Impact
We estimate our total costs for Year 2000 readiness, including inventory,
assessment, replacements, upgrades, repairs and testing, to be between $23.5
million and $24.5 million, of which $23.1 million had been incurred as of July
31, 1999. Total operating costs are estimated to be between $4 million and $4.5
million. By order of the North Carolina Utilities Commission, we defer and
amortize over a three-year period the portion of the operating costs
attributable to North Carolina (57% based on utility plant in service). Of the
total estimated costs, we will capitalize costs of $19.5 million to $20 million
to replace certain existing applications with new systems that are Year 2000
operational and provide additional business management information and
functionality. We have not had to defer or cancel any planned IT projects due to
Year 2000 issues.
At July 31, 1999, we have expensed $2.7 million, deferred $1.5 million and
capitalized $18.9 million. Year 2000 costs are being funded by internally
generated cash and borrowings under existing credit agreements. The projected
Year 2000 costs for fiscal 1999 comprise approximately 33% of the IT budget.
We expect that all necessary systems will be Year 2000 ready by September 30,
1999. As progress is made, we continually revise the master plan to address
potential risks associated with Year 2000 issues. We do not expect the total
capital and operating costs associated with Year 2000 readiness, including
assessment, replacement and remediation, 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 of our knowledge and belief.
-14-
<PAGE> 15
PART II. OTHER INFORMATION
Item 5. Other Information
Excise Tax on Gas Consumption
Effective July 1, 1999, for bills rendered after August 1, 1999, we began
charging a new excise tax on piped natural gas used in North Carolina which
replaced the sales and use tax and gross receipts tax that were previously
applicable to piped natural gas. The excise tax is calculated using a declining
block rate structure applied to the number of therms delivered each month. The
intent of the excise tax is not to increase or decrease taxes, but to replace
the combination of the sales and use tax and gross receipts tax.
The gross receipts tax was included in our gas rates billed to customers and
therefore was in our operating revenues. Gross receipts tax expense in the same
amount was also included in general taxes. The sales and use tax was not
included in rates but was collected as a surcharge and remitted to the state
with no impact on the income statement. The excise tax will follow the previous
sales and use tax treatment and will not be included in our revenues or
expenses. This change will impact the comparability of revenues and thus margin
(revenues less cost of gas) and general taxes for all periods prior to the
change.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits -
12 Computation of Ratio of Earnings to Fixed Charges.
27 Financial Data Schedule (for Securities and Exchange
Commission use only).
(b) Reports on Form 8-K -
None.
-15-
<PAGE> 16
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Piedmont Natural Gas Company, Inc.
(Registrant)
Date September 7, 1999 /s/ David J. Dzuricky
------------------ ----------------------------------
David J. Dzuricky
Senior Vice President-Finance
(Principal Financial Officer)
Date September 7, 1999 /s/ Barry L. Guy
------------------ ----------------------------------
Barry L. Guy
Vice President and Controller
(Principal Accounting Officer)
-16-
<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
and Twelve Months Ended July 31, 1999
(in thousands except ratio amounts)
<TABLE>
<CAPTION>
July 31,
1999 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income from continuing
operations $ 56,870 $ 60,313 $ 54,074 $ 48,562 $ 40,310 $ 35,506
Income taxes 36,672 38,807 34,650 30,928 25,442 21,407
Fixed charges 37,559 38,415 39,263 37,009 35,651 29,736
-------- -------- -------- -------- -------- --------
Total Adjusted Earnings $131,101 $137,535 $127,987 $116,499 $101,403 $ 86,649
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest $ 35,749 $ 36,453 $ 36,949 $ 34,511 $ 33,224 $ 27,671
Amortization of debt expense 304 304 346 345 336 334
One-third of rental expense 1,506 1,658 1,968 2,153 2,091 1,731
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 37,559 $ 38,415 $ 39,263 $ 37,009 $ 35,651 $ 29,736
======== ======== ======== ======== ======== ========
Ratio of Earnings to Fixed Charges 3.49 3.58 3.26 3.15 2.84 2.91
==== ==== ==== ==== ==== ====
</TABLE>
-17-
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> OCT-31-1999
<PERIOD-START> NOV-01-1998
<PERIOD-END> JUL-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,004,260
<OTHER-PROPERTY-AND-INVEST> 25,764
<TOTAL-CURRENT-ASSETS> 152,094
<TOTAL-DEFERRED-CHARGES> 43,350
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,225,468
<COMMON> 293,286
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 214,168
<TOTAL-COMMON-STOCKHOLDERS-EQ> 507,454
0
0
<LONG-TERM-DEBT-NET> 333,000
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 59,000
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 46,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 280,014
<TOT-CAPITALIZATION-AND-LIAB> 1,225,468
<GROSS-OPERATING-REVENUE> 591,717
<INCOME-TAX-EXPENSE> 43,630
<OTHER-OPERATING-EXPENSES> 456,520
<TOTAL-OPERATING-EXPENSES> 500,150
<OPERATING-INCOME-LOSS> 91,567
<OTHER-INCOME-NET> (243)
<INCOME-BEFORE-INTEREST-EXPEN> 91,324
<TOTAL-INTEREST-EXPENSE> 24,309
<NET-INCOME> 67,015
0
<EARNINGS-AVAILABLE-FOR-COMM> 67,015
<COMMON-STOCK-DIVIDENDS> 31,407
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 65,876
<EPS-BASIC> 2.17
<EPS-DILUTED> 2.15
</TABLE>
