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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 April 30, 1999
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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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 June 3, 1999
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Common Stock, no par value 31,053,437
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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>
April 30, October 31,
1999 1998
Unaudited Audited
---------- ----------
ASSETS
<S> <C> <C>
Utility Plant, at original cost $1,391,764 $1,345,925
Less accumulated depreciation 402,237 381,585
---------- ----------
Utility plant, net 989,527 964,340
---------- ----------
Other Physical Property (net of accumulated
depreciation of $18,285 in 1999 and $17,406 in 1998) 25,932 26,300
---------- ----------
Current Assets:
Cash and cash equivalents 21,543 9,720
Restricted cash 36,924 27,484
Receivables (less allowance for doubtful
accounts of $2,412 in 1999 and $2,314 in 1998) 54,744 24,459
Gas in storage 22,296 42,465
Deferred cost of gas 7,325 5,217
Refundable income taxes 593 13,897
Other 6,643 19,300
---------- ----------
Total current assets 150,068 142,542
---------- ----------
Deferred Charges and Other Assets 26,313 29,662
---------- ----------
Total $1,191,840 $1,162,844
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock $ 289,175 $ 279,709
Retained earnings 233,102 178,559
---------- ----------
Total common stock equity 522,277 458,268
Long-term debt 371,000 371,000
---------- ----------
Total capitalization 893,277 829,268
---------- ----------
Current Liabilities:
Current maturities of long-term debt and
sinking fund requirements 10,000 10,000
Notes payable -- 32,000
Accounts payable 47,089 67,296
Deferred income taxes 16,986 15,367
Taxes accrued 3,365 12,893
Refunds due customers 48,856 28,408
Other 18,114 19,884
---------- ----------
Total current liabilities 144,410 185,848
---------- ----------
Deferred Credits and Other Liabilities 154,153 147,728
---------- ----------
Total $1,191,840 $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 Six Months Twelve Months
Ended Ended Ended
April 30 April 30 April 30
---------------------- ---------------------- ----------------------
1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $239,247 $261,477 $494,989 $574,732 $685,534 $778,411
Cost of Gas 125,473 147,496 259,659 337,658 364,422 453,974
-------- -------- -------- -------- -------- --------
Margin 113,774 113,981 235,330 237,074 321,112 324,437
-------- -------- -------- -------- -------- --------
Other Operating Expenses:
Operations 25,829 25,958 50,507 51,523 103,917 109,005
Maintenance 3,932 3,389 7,553 6,761 15,500 14,421
Depreciation 10,803 10,491 21,515 20,981 42,710 40,777
General taxes 8,745 8,811 18,241 20,301 30,574 32,531
Income taxes 22,264 22,406 47,806 47,588 37,476 36,823
-------- -------- -------- -------- -------- --------
Total other operating expenses 71,573 71,055 145,622 147,154 230,177 233,557
-------- -------- -------- -------- -------- --------
Operating Income 42,201 42,926 89,708 89,920 90,935 90,880
Other Income, Net 449 951 1,791 3,476 643 3,864
-------- -------- -------- -------- -------- --------
Income Before Utility Interest Charges 42,650 43,877 91,499 93,396 91,578 94,744
Utility Interest Charges 7,983 8,414 16,268 16,684 32,746 33,543
-------- -------- -------- -------- -------- --------
Net Income $ 34,667 $ 35,463 $ 75,231 $ 76,712 $ 58,832 $ 61,201
======== ======== ======== ======== ======== ========
Average Shares of Common Stock:
Basic 30,946 30,414 30,883 30,343 30,740 30,189
Diluted 31,175 30,696 31,113 30,637 30,995 30,465
Earnings Per Share of Common Stock:
Basic $ 1.12 $ 1.17 $ 2.44 $ 2.53 $ 1.91 $ 2.03
Diluted $ 1.11 $ 1.16 $ 2.42 $ 2.50 $ 1.90 $ 2.01
Cash Dividends Per Share
of Common Stock $ 0.345 $ 0.325 $ 0.67 $ 0.63 $ 1.32 $ 1.24
</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 Six Months Twelve Months
Ended Ended Ended
April 30 April 30 April 30
-------- -------- --------
1999 1998 1999 1998 1999 1998
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Cash Flows from Operating Activities:
Net income $ 34,667 $ 35,463 $ 75,231 $ 76,712 $ 58,832 $ 61,201
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 11,895 11,549 23,608 23,089 46,697 44,950
Other, net (1,997) 88 (114) 2,010 309 6,876
Change in operating assets and liabilities 63,011 53,265 4,048 26,016 (7,504) 5,275
--------- --------- --------- --------- --------- ---------
Net cash provided by operating activities 107,576 100,365 102,773 127,827 98,334 118,302
--------- --------- --------- --------- --------- ---------
Cash Flows from Investing Activities:
Utility construction expenditures (23,745) (17,237) (45,223) (33,795) (102,326) (81,891)
Other (460) (26) (805) (336) (1,581) (1,520)
--------- --------- --------- --------- --------- ---------
Net cash used in investing activities (24,205) (17,263) (46,028) (34,131) (103,907) (83,411)
--------- --------- --------- --------- --------- ---------
Cash Flows from Financing Activities:
Decrease in bank loans, net (64,000) (30,000) (32,000) (25,000) -- --
Retirement of long-term debt -- -- -- -- (10,000) (10,000)
Issuance of common stock through dividend
reinvestment and employee stock plans 4,091 3,809 7,766 7,497 15,405 14,701
Dividends paid (10,674) (9,883) (20,688) (19,121) (40,571) (37,441)
--------- --------- --------- --------- --------- ---------
Net cash used in financing activities (70,583) (36,074) (44,922) (36,624) (35,166) (32,740)
--------- --------- --------- --------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 12,788 47,028 11,823 57,072 (40,739) 2,151
Cash and Cash Equivalents at Beginning of Period 8,755 15,254 9,720 5,210 62,282 60,131
--------- --------- --------- --------- --------- ---------
Cash and Cash Equivalents at End of Period $ 21,543 $ 62,282 $ 21,543 $ 62,282 $ 21,543 $ 62,282
========= ========= ========= ========= ========= =========
Cash Paid During the Period for:
Interest $ 4,783 $ 5,123 $ 16,126 $ 16,615 $ 32,737 $ 33,821
Income taxes $ 36,327 $ 44,061 $ 38,060 $ 46,576 $ 38,623 $ 46,933
</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 April 30, 1999, and October 31, 1998, and the
results of operations and cash flows for the three months, six months and
twelve months ended April 30, 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 six-month periods ended April 30, 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 Six Months Twelve Months
Ended Ended Ended
April 30 April 30 April 30
-------------------- -------------------- --------------------
(in thousands except per share amounts)
1999 1998 1999 1998 1999 1998
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Net Income $34,667 $35,463 $75,231 $76,712 $58,832 $61,201
======= ======= ======= ======= ======= =======
Average shares of common stock
outstanding for basic earnings per share 30,946 30,414 30,883 30,343 30,740 30,189
Contingently issuable shares under
the long-term incentive plan 229 282 230 294 255 276
------- ------- ------- ------- ------- -------
Average shares of dilutive stock 31,175 30,696 31,113 30,637 30,995 30,465
======= ======= ======= ======= ======= =======
Earnings Per Share:
Basic $ 1.12 $ 1.17 $ 2.44 $ 2.53 $ 1.91 $ 2.03
Diluted $ 1.11 $ 1.16 $ 2.42 $ 2.50 $ 1.90 $ 2.01
</TABLE>
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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,
- 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 through operating cash flows, the issuance
of new common stock through dividend reinvestment and employee stock purchase
plans 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 or other conditions
require such long-term financing.
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 April 30, 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 and short-term debt. The capital expansion program supports
our approximately 5% current annual growth in customer base. Utility
construction expenditures for the three months ended April 30, 1999, were $24.5
million, compared with $17.7 million for the same period in 1998. Utility
construction expenditures for the six months ended April 30, 1999, were $46.8
million, compared with $34.8 million for the same period in 1998. Utility
construction expenditures for the twelve-month period ended April 30, 1999, were
$105.6 million, compared with $83.4 million for the same period in 1998.
At April 30, 1999, our capitalization consisted of 42% in long-term debt and 58%
in common equity.
Results of Operations
We will discuss the results of operations for the three months, six months and
twelve months ended April 30, 1999, compared with the same periods in 1998.
Margin
Margin (operating revenues less cost of gas) for the three months ended April
30, 1999, decreased $207,000 compared with the same period in 1998 primarily for
the reasons listed below.
- 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.
- Adjustments required by regulatory authorities resulted in
margin decreases from the same period in 1998.
Decreases in margin for the three-month period were partially offset by the
following increases.
- Weather was 3% colder than the same period in 1998.
- Delivered volumes of natural gas, which we refer to as system
throughput, increased over the same period in 1998 by 151,000
dekatherms.
- Volumes from secondary market sales increased over the same
period in 1998 by 749,000 dekatherms, a 6% increase. Secondary
market sales include sales for resale, off-system sales,
capacity release and other interstate transactions.
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- Weather was 5% warmer than normal. The warmer-than-normal
weather generated operating revenues of $8.9 million from the
weather normalization adjustment (WNA). The WNA is designed to
offset the impact of unusually cold or warm weather, compared
with normal, on customer billings and operating margin. The
same period in 1998 reflected increased operating revenues of
$5.8 million from the WNA.
Margin for the six months ended April 30, 1999, decreased $1.7 million compared
with the same period in 1998 primarily for the reasons listed below.
- Delivered volumes of natural gas decreased from the same
period in 1998 by 6.3 million dekatherms, a 7% decrease.
- We changed rates in South Carolina to eliminate the recovery
of DSM costs as noted above.
Decreases in margin for the six-month period were partially offset by the
following increases.
- Volumes from secondary market sales increased over the same
period in 1998 by 4.8 million dekatherms, a 22% increase.
- Weather was 10% warmer than the same period in 1998, and 14%
warmer than normal. The warmer-than-normal weather generated
operating revenues of $19.7 million from the WNA. The same
period in 1998 reflected increased operating revenues of $5
million from the WNA.
Margin for the twelve months ended April 30, 1999, decreased $3.3 million
compared with the same period in 1998 primarily for the reasons listed below.
- Delivered volumes of natural gas decreased from the same
period in 1998 by 3.9 million dekatherms, a 3% decrease.
- We changed rates in South Carolina to eliminate the recovery
of DSM costs as noted above.
Decreases in margin for the twelve-month period were partially offset by the
following increases.
- Volumes from secondary market sales increased over the same
period in 1998 by 6.5 million dekatherms, a 21% increase.
- Weather was 16% warmer than normal and 14% warmer than the
same period in 1998 and generated $19.7 million in operating
revenues from the WNA. The same period in 1998 reflected
increased operating revenues of $5 million from the WNA from
3% 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.
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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.
Operations and Maintenance Expenses
Operations and maintenance expenses for the three months ended April 30, 1999,
compared with the same period in 1998 increased by $414,000 primarily for the
reasons listed below.
- Increase in outside labor,
- Increase in consultants fees and
- Increase in office supplies expenses.
Decreases in payroll, advertising expenses and employee benefits partially
offset these increases for the three months ended April 30, 1999, compared with
the same period in 1998.
Operations and maintenance expenses for the six months ended April 30, 1999,
compared with the same period in 1998 decreased by $224,000 primarily for the
reasons listed below.
- Decrease in provision for uncollectibles,
- Decrease in advertising expenses and
- Decrease in employee benefits.
An increase in outside labor partially offset these decreases for the six months
ended April 30, 1999, compared with the same period in 1998.
Operations and maintenance expenses for the twelve months ended April 30, 1999,
compared with the same period in 1998 decreased by $4 million primarily for the
reasons listed below.
- Decrease in payroll,
- Decrease in transportation expenses,
- Decrease in provision for uncollectibles,
- Decrease in risk insurance expenses and
- Decrease in advertising expenses.
Increases in outside labor expenses and materials and office supplies expenses
partially offset these decreases for the twelve months ended April 30, 1999,
compared with the same period in 1998.
General Taxes
General taxes for the three months ended April 30, 1999, compared with the same
period in 1998 decreased slightly by $66,000 primarily for the reasons listed
below.
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- Decrease in gross receipts taxes from lower sales to customers
of volumes on which gross receipts taxes are charged and
- Decrease in payroll taxes.
An increase in franchise tax payments partially offset these decreases for the
three months ended April 30, 1999, compared with the same period in 1998.
General taxes for the six months ended April 30, 1999, compared with the same
period in 1998 decreased by $2.1 million primarily for the reasons listed below.
- Decrease in gross receipts taxes from lower sales to customers
and
- Decrease in payroll taxes.
General taxes for the twelve months ended April 30, 1999, compared with the same
period in 1998 decreased by $2 million primarily for the reasons listed below.
- Decrease in gross receipts taxes from lower sales to customers
and
- Decrease in payroll taxes.
Increases in property taxes and franchise taxes partially offset these decreases
for the twelve months ended April 30, 1999, compared with the same period in
1998.
Other Income
Other income for the three months ended April 30, 1999, compared with the same
period in 1998 decreased by $502,000. The primary reasons for these decreases
are listed below.
- Decrease in earnings from jobbing operations,
- Decrease in earnings from energy marketing services and
- Decrease in interest income.
These decreases in other income were partially offset by the following
increases.
- Increase in earnings from propane operations,
- Increase in earnings from merchandise operations and
- Increase in the allowance for funds used during construction.
Other income for the six months ended April 30, 1999, compared with the same
period in 1998 decreased by $1.7 million. Other income for the twelve months
ended April 30, 1999, compared with the same period in 1998 decreased by $3.2
million. The primary reasons for these decreases are listed below.
- Decrease in earnings from propane operations due to warmer
weather,
- Decrease in earnings from energy marketing services,
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- Decrease in earnings from jobbing operations and
- Decrease in interest income.
Increases in earnings from merchandise operations and in the allowance for funds
used during construction partially offset these decreases in other income for
the six-month and twelve-month periods ended April 30, 1999, compared with the
same periods in 1998.
Utility Interest Charges
Utility interest charges for the three months ended April 30, 1999, compared
with the same period in 1998 decreased by $431,000. Utility interest charges for
the six months ended April 30, 1999, compared with the same period in 1998
decreased by $416,000. The primary reasons for these decreases are listed below.
- Decrease in interest in long-term debt from lower amounts of
debt outstanding and
- Decrease in interest incurred on refunds due customers.
An increase in interest on short-term debt due to higher amounts outstanding but
at slightly lower interest rates partially offset these increases in utility
interest charges for the three-month and six-month periods ended April 30, 1999,
compared with the same periods in 1998.
Utility interest charges for the twelve months ended April 30, 1999, compared
with the same period in 1998 decreased by $797,000 primarily due to a decrease
in interest in 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 that has
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
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such as regression, system, parallel, interface and stress testing. Test plans
include additional 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 being completed prior to the system
implementations, we will perform additional testing during 1999. During the
third calendar quarter of 1999, we intend to conduct 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 expect all remaining applications to be complete by September 30, 1999.
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We completed the inventory and assessment of embedded systems and found that
approximately 4% of the devices have a Year 2000 impact. We developed a
remediation strategy for each of the impacted devices and have completed the
upgrades on 93% of the impacted systems. In a few cases, the current
availability of hardware or software components or scheduling conflicts with
vendors have affected our ability to implement a Year 2000 ready solution by our
target date of April 30, 1999. The upgrades to these remaining devices should be
completed by June 30, 1999.
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 are identifying alternative sources. In other cases, we
are planning to increase our inventory levels of specific critical items. We
anticipate this work effort will be complete by June 30, 1999. 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 are developing
contingency plans to address each of the items. We anticipate the development of
these plans will be complete by June 30, 1999. Worst case scenarios are as
follows:
- electrical outages
- telecommunication 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.
We currently have in place the following that can be used 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,
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- 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 are currently developing contingency plans in the areas of facilities,
applications, suppliers, embedded technologies and worst case scenarios. We are
following 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 assumes that there will be multiple
concurrent failures of systems, thus requiring an additional level of planning
to compensate for any assumptions that are made within a particular contingency
plan. We anticipate the development of contingency plans will be complete by
June 30, 1999. During the third calendar quarter of 1999, we intend to test
selected contingency plans based on potential risks.
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.
Although we have not yet completed the contingency planning process, 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
million and $25 million, of which $20.8 million has been incurred as of April
30, 1999. Total operating costs are estimated to be between $4 million and $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 million to $20 million to
replace certain existing applications with new systems that will be Year 2000
operational and provide additional business management information and
functionality. Until we have completed further analysis of Year 2000 impacts on
our 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. We have not had to defer or cancel any planned IT projects due to
Year 2000 issues.
-14-
<PAGE> 15
At April 30, 1999, we have expensed $2.5 million, deferred $1.5 million and
capitalized $16.8 million. We expect that these Year 2000 costs will be funded
by revenues generated from operations or through 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 late September
1999. As progress is made, we continually revise the master plan to address the
risks of Year 2000 issues, including contingency plans as appropriate to address
worst case scenarios. 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.
-15-
<PAGE> 16
PART II. OTHER INFORMATION
Item 5. Other Information
Expansion Funds
As previously reported, the North Carolina Utilities Commission (NCUC) ordered
the establishment of an expansion fund for us and approved initial funding with
supplier refunds due customers to enable the expansion of natural gas service
into unserved areas of the state. At April 30, 1999, the North Carolina State
Treasurer held $28.1 million in our 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 NCUC decides the use of
these funds as we file individual project applications for unserved areas.
In June 1998, we 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. In that petition, we also requested authority to use $26.3 million
in expansion fund money to pay a portion of the estimated cost of the project of
$31.9 million. In November 1998, the NCUC issued an order approving our
requests.
On January 26, 1999, we filed an affidavit with the NCUC proposing an alternate
route of the pipeline to these counties at the direction of the National Forest
Service at an additional cost of $1.5 million. On May 20, the NCUC approved the
transfer of an additional $1.5 million in supplier refunds to our expansion fund
held by the state. This provides funding of $27.8 million for the project, now
estimated to cost $33.4 million.
Tennessee Incentive Plan
As previously reported, the Tennessee Regulatory Authority (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 us. 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 our application to automatically renew the
performance incentive plan each year. On March 11, 1999, the TRA issued its
written order authorizing the continuance of the incentive plan each July 1
until we notify the TRA of termination 90 days before the end of a plan year or
until the plan is modified, amended or terminated by the TRA. An independent
review of the incentive plan is eliminated by the order.
Pine Needle LNG Company, L.L.C. (Pine Needle)
On May 1, 1999, the liquified natural gas (LNG) peak-demand facility located in
North Carolina began operations. We own 35% of the project through a subsidiary,
Piedmont Interstate Pipeline Company. Storage capacity is four billion cubic
feet with vaporization capability of 400 million cubic feet per day.
-16-
<PAGE> 17
We have subscribed to one-half of this capacity to provide gas for peak-use
periods in winter when demand is the highest. As previously reported, Pine
Needle financed the construction of the facility through construction loans,
with permanent financing at the end of the construction period. On May 3, we
made an equity contribution of $18.7 million to Pine Needle to cover our portion
of the permanent financing.
Corporate Organization
On June 4, 1999, the Board of Directors elected Ware F. Schiefer, President and
Chief Operating Officer, to the Company's Board of Directors.
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.
-17-
<PAGE> 18
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 June 10, 1999 /s/ David J. Dzuricky
---------------------------------------
David J. Dzuricky
Senior Vice President-Finance
(Principal Financial Officer)
Date June 10, 1999 /s/ Barry L. Guy
---------------------------------------
Barry L. Guy
Vice President and Controller
(Principal Accounting Officer)
-18-
<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 April 30, 1999
(in thousands except ratio amounts)
<TABLE>
<CAPTION>
April 30,
1999 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income from continuing
operations $ 58,832 $ 60,313 $ 54,074 $ 48,562 $ 40,310 $35,506
Income taxes 37,922 38,807 34,650 30,928 25,442 21,407
Fixed charges 37,683 38,415 39,263 37,009 35,651 29,736
-------- -------- -------- -------- -------- -------
Total Adjusted Earnings $134,437 $137,535 $127,987 $116,499 $101,403 $86,649
======== ======== ======== ======== ======== =======
Fixed Charges:
Interest $ 36,039 $ 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 1,340 1,658 1,968 2,153 2,091 1,731
-------- -------- -------- -------- -------- -------
Total Fixed Charges $ 37,683 $ 38,415 $ 39,263 $ 37,009 $ 35,651 $29,736
======== ======== ======== ======== ======== =======
Ratio of Earnings to Fixed Charges 3.57 3.58 3.26 3.15 2.84 2.91
======== ======== ======== ======== ======== =======
</TABLE>
-19-
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
FINANCIAL STATEMENTS OF PIEDMONT NATURAL GAS FOR THE SIX MONTHS
ENDED APRIL 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> OCT-31-1999
<PERIOD-START> NOV-01-1998
<PERIOD-END> APR-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 989,527
<OTHER-PROPERTY-AND-INVEST> 25,932
<TOTAL-CURRENT-ASSETS> 150,068
<TOTAL-DEFERRED-CHARGES> 26,313
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,191,840
<COMMON> 289,175
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 233,102
<TOTAL-COMMON-STOCKHOLDERS-EQ> 522,277
0
0
<LONG-TERM-DEBT-NET> 371,000
<SHORT-TERM-NOTES> 0
<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> 288,563
<TOT-CAPITALIZATION-AND-LIAB> 1,191,840
<GROSS-OPERATING-REVENUE> 494,989
<INCOME-TAX-EXPENSE> 47,806
<OTHER-OPERATING-EXPENSES> 357,475
<TOTAL-OPERATING-EXPENSES> 405,281
<OPERATING-INCOME-LOSS> 89,708
<OTHER-INCOME-NET> 1,791
<INCOME-BEFORE-INTEREST-EXPEN> 91,499
<TOTAL-INTEREST-EXPENSE> 16,268
<NET-INCOME> 75,231
0
<EARNINGS-AVAILABLE-FOR-COMM> 75,231
<COMMON-STOCK-DIVIDENDS> 20,688
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 102,773
<EPS-BASIC> 2.44
<EPS-DILUTED> 2.42
</TABLE>
