1
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 January 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 March 5, 1999
- -------------------------- ----------------------------
Common Stock, no par value 30,924,595
Page 1 of 17 pages
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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)
January 31, October 31,
1999 1998
Unaudited Audited
----------- -----------
ASSETS
Utility Plant, at original cost $ 1,367,212 $ 1,345,925
Less accumulated depreciation 391,518 381,585
----------- -----------
Utility plant, net 975,694 964,340
----------- -----------
Other Physical Property (net of accumulated
depreciation of $17,729 in 1999 and $17,406 in 1998) 26,078 26,300
----------- -----------
Current Assets:
Cash and cash equivalents 8,755 9,720
Restricted cash 31,758 27,484
Receivables (less allowance for doubtful
accounts of $2,225 in 1999 and $2,314 in 1998) 110,533 24,459
Gas in storage 42,317 42,465
Deferred cost of gas 14,585 5,217
Refundable income taxes 13,897 13,897
Other 9,719 19,300
----------- -----------
Total current assets 231,564 142,542
----------- -----------
Deferred Charges and Other Assets 28,412 29,662
----------- -----------
Total $ 1,261,748 $ 1,162,844
=========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock $ 285,084 $ 279,709
Retained earnings 209,109 178,559
----------- -----------
Total common stock equity 494,193 458,268
Long-term debt 371,000 371,000
----------- -----------
Total capitalization 865,193 829,268
----------- -----------
Current Liabilities:
Current maturities of long-term debt and
sinking fund requirements 10,000 10,000
Notes payable 64,000 32,000
Accounts payable 68,389 67,296
Deferred income taxes 22,841 15,367
Taxes accrued 24,647 12,893
Refunds due customers 38,073 28,408
Other 14,873 19,884
----------- -----------
Total current liabilities 242,823 185,848
----------- -----------
Deferred Credits and Other Liabilities 153,732 147,728
----------- -----------
Total $ 1,261,748 $ 1,162,844
=========== ===========
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)
Three Months Twelve Months
Ended Ended
January 31 January 31
----------------------- ----------------------
1999 1998 1999 1998
---- ---- ---- ----
Operating Revenues $ 255,742 $ 313,255 $ 707,763 $ 776,239
Cost of Gas 134,186 190,162 386,445 456,664
--------- --------- --------- ---------
Margin 121,556 123,093 321,318 319,575
--------- --------- --------- ---------
Other Operating Expenses:
Operations 24,678 25,565 104,046 109,279
Maintenance 3,621 3,372 14,957 15,195
Depreciation 10,712 10,491 42,397 39,950
General taxes 9,496 11,489 30,640 32,949
Income taxes 25,543 25,182 37,614 34,617
--------- --------- --------- ---------
Total other operating expenses 74,050 76,099 229,654 231,990
--------- --------- --------- ---------
Operating Income 47,506 46,994 91,664 87,585
Other Income, Net 1,343 2,525 1,153 4,036
--------- --------- --------- ---------
Income Before Utility Interest Charges 48,849 49,519 92,817 91,621
Utility Interest Charges 8,285 8,270 33,189 33,610
--------- --------- --------- ---------
Net Income $ 40,564 $ 41,249 $ 59,628 $ 58,011
========= ========= ========= =========
Average Shares of Common Stock:
Basic 30,822 30,274 30,610 30,041
Diluted 31,054 30,580 30,878 30,332
Earnings Per Share of Common Stock:
Basic $ 1.32 $ 1.36 $ 1.95 $ 1.93
Diluted $ 1.31 $ 1.35 $ 1.93 $ 1.91
Cash Dividends Per Share
of Common Stock $ 0.325 $ 0.305 $ 1.30 $ 1.22
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)
Three Months Twelve Months
Ended Ended
January 31 January 31
----------------------- ------------------------
1999 1998 1999 1998
---- ---- ---- ----
Cash Flows from Operating Activities:
Net income $ 40,564 $ 41,249 $ 59,628 $ 58,011
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 11,713 11,539 46,318 44,150
Other, net 1,883 1,922 2,395 9,633
Change in operating assets and liabilities (58,963) (27,248) (17,218) 10,984
-------- -------- -------- ---------
Net cash provided by (used in) operating activities (4,803) 27,462 91,123 122,778
-------- -------- -------- ---------
Cash Flows from Investing Activities:
Utility construction expenditures (21,478) (16,558) (95,818) (87,677)
Other (345) (310) (1,147) (1,768)
-------- -------- -------- ---------
Net cash used in investing activities (21,823) (16,868) (96,965) (89,445)
-------- -------- -------- ---------
Cash Flows from Financing Activities:
Increase in bank loans, net 32,000 5,000 34,000 4,000
Retirement of long-term debt -- -- (10,000) (10,000)
Issuance of common stock through dividend
reinvestment and employee stock plans 3,675 3,688 15,123 14,608
Dividends paid (10,014) (9,238) (39,780) (36,649)
-------- -------- -------- ---------
Net cash provided by (used in)
financing activities 25,661 (550) (657) (28,041)
-------- -------- -------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents (965) 10,044 (6,499) 5,292
Cash and Cash Equivalents at Beginning
of Period 9,720 5,210 15,254 9,962
-------- -------- -------- ---------
Cash and Cash Equivalents at End of Period $ 8,755 $ 15,254 $ 8,755 $ 15,254
======== ======== ======== =========
Cash Paid During the Period for:
Interest $ 11,343 $ 11,492 $ 33,077 $ 34,136
Income taxes $ 1,733 $ 2,514 $ 46,357 $ 36,612
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 January 31, 1999, and October
31, 1998, and the results of operations and cash flows for the three
months and twelve months ended January 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 period ended January 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:
Three Months Twelve Months
Ended Ended
January 31 January 31
---------- ----------
1999 1998 1999 1998
---- ---- ---- ----
(in thousands except per share amounts)
Net Income $ 40,564 $ 41,249 $ 59,628 $ 58,011
======== ======== ======== ========
Average shares of common stock outstanding for
basic earnings per share 30,822 30,274 30,610 30,041
Contingently issuable shares under the long-term
incentive plan 232 306 268 291
-------- -------- -------- --------
Average shares of dilutive stock 31,054 30,580 30,878 30,332
======== ======== ======== ========
Earnings Per Share:
Basic $ 1.32 $ 1.36 $ 1.95 $ 1.93
Diluted $ 1.31 $ 1.35 $ 1.93 $ 1.91
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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 decreased and accounts receivable and accounts payable
increased from October 31, 1998, to January 31, 1999, due to this seasonality
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and the 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 4% current annual growth in customer base.
Utility construction expenditures for the three months ended January 31, 1999,
were $22.3 million, compared with $17 million for the same period in 1998.
Utility construction expenditures for the twelve-month period ended January 31,
1999, were $98.8 million, compared with $89.2 million for the same period in
1998.
At January 31, 1999, our capitalization consisted of 43% in long-term debt and
57% in common equity.
Results of Operations
We will discuss the results of operations for the three months and twelve
months ended January 31, 1999, compared with the same periods of 1998.
Margin
Margin (operating revenues less cost of gas) for the three months ended January
31, 1999, decreased $1.5 million compared with the same period in 1998
primarily for the reasons listed below.
- Delivered volumes of natural gas, which we refer to as system
throughput, decreased from the same period in 1998 by 6.4
million dekatherms, a 13% decrease.
- Weather was 18% warmer than the same period in 1998, and 19%
warmer than normal.
Decreases in margin for the three-month period were partially offset by the
following increases.
- Volumes from secondary market sales increased over the same
period in 1998 by 4 million dekatherms, a 4% increase.
Secondary market sales include sales for resale, off-system
sales, capacity release and other interstate transactions.
- The warmer weather generated operating revenues of $10.8
million from the weather normalization adjustment (WNA). The
WNA is designed to offset the impact of unusually cold or
warm weather on customer billings and operating margin. The
same period in 1998 reflected decreased operating revenues
from the WNA by $781,000 as the weather was only 2% warmer
than normal.
Margin for the twelve months ended January 31, 1999, increased $1.7 million
compared with the same period in 1998 primarily for the reasons listed below.
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- The state commissions approved rate changes affecting margin.
- Volumes from secondary market sales increased over the same
period in 1998 by 7.5 million dekatherms, a 25% increase.
- Weather was 17% warmer than normal and 13% warmer than the
same period in 1998 and generated $16.5 million in operating
revenues from the WNA. The same period in 1998 reflected
increased operating revenues of $8.1 million from the WNA
from 5% warmer-than-normal weather.
Decreased system throughput offset the margin increase for the twelve months
ended January 31, 1999, compared with the same period in 1998. These sales and
transportation volumes for the current twelve-month period decreased from the
1998 period by 1.3 million dekatherms, a 1% decrease.
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.
Operations and Maintenance Expenses
Operations and maintenance expenses for the three months ended January 31,
1999, compared with the same period in 1998 decreased by $638,000 primarily for
the reasons listed below.
- Decrease in provision for uncollectibles,
- Decrease in advertising expenses and
- Decrease in office supplies expenses.
Increases in payroll and outside labor partially offset these decreases for the
three months ended January 31, 1999, compared with the same period in 1998.
Operations and maintenance expenses for the twelve months ended January 31,
1999, compared with the same period in 1998 decreased by $5.5 million primarily
for the reasons listed below.
- Decrease in payroll,
- Decrease in transportation expenses,
- Decrease in rental payments,
- Decrease in provision for uncollectibles,
- Decrease in risk insurance expenses,
- Decrease in advertising expenses and
- Decrease in outside consultants expenses.
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An increase in outside labor expenses partially offset these decreases for the
twelve months ended January 31, 1999, compared with the same period in 1998.
General Taxes
General taxes for the three months ended January 31, 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,
- Decrease in franchise taxes,
- Decrease in property taxes and
- Decrease in payroll taxes.
General taxes for the twelve months ended January 31, 1999, compared with the
same period in 1998 decreased by $2.3 million primarily for the reasons listed
below.
- Decrease in gross receipts taxes from lower sales to
customers,
- Decrease in franchise taxes and
- Decrease in payroll taxes.
An increase in property taxes partially offset these decreases for the twelve
months ended January 31, 1999, compared with the same period in 1998.
Other Income
Other income for the three months ended January 31, 1999, compared with the
same period in 1998 decreased by $1.2 million. Other income for the twelve
months ended January 31, 1999, compared with the same period in 1998 decreased
by $2.9 million. The primary reasons for these decreases are listed below.
- Decrease in earnings from propane operations due to warmer
weather and
- Decrease in earnings from energy marketing services.
An increase in the allowance for funds used during construction partially
offset these decreases.
Utility Interest Charges
Utility interest charges for the three months ended January 31, 1999, compared
with the same period in 1998 increased by only $15,000 primarily due to an
increase in interest on short-term debt due to higher amounts outstanding at
lower interest rates. A decrease in interest on long-term debt from lower
amounts of debt outstanding partially offset this increase.
Utility interest charges for the twelve months ended January 31, 1999, compared
with the same period in 1998 increased slightly by $421,000. The primary
reasons for the increase are listed below.
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- Increase in interest on short-term debt due to higher amounts
outstanding but at slightly lower interest rates and
- Increase in interest on refunds due customers due to higher
amounts outstanding.
A decrease in interest on long-term debt from lower amounts of debt outstanding
partially offset these increases.
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 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.
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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.
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 implementation of
those strategies will be complete by April 30, 1999. In many cases, the current
availability of hardware or software components from the vendor affects our
ability to implement Year 2000 ready solutions in a more timely manner.
Suppliers and Vendors
We are 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, we received
some level of written response from approximately 80% of the companies. We are
analyzing these responses to determine which, if any, supplier relationships
may require further attention based on our anticipated risks and business
impacts. We will identify alternative vendor sources and develop contingency
plans for any critical vendors considered at risk if necessary. We anticipate
this work effort will be complete by June 30, 1999.
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. Worst case scenarios are as
follows:
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- Electrical Outages
- Telecommunication Outages
- Natural Gas Shortages
- Water Outages
- Vehicle Fuel Shortages
- Staff Shortages
- Postal Service Outages
- Data Center Services Outages
- Emergency Response Impacts
- 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,
- 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 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, we will alter or update our plans as dictated by
business requirements. We follow the guidelines outlined by the General
Accounting Office for Year 2000 Business Continuity and Contingency Planning.
The contingency planning process takes into account facilities, suppliers,
vendors, embedded technologies and critical business processes and their
interdependencies. The 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.
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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 $17.8 million has been incurred as of January
31, 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 the 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.
At January 31, 1999, we have expensed $3.9 million, deferred $1.5 million and
capitalized $12.4 million. We expect that these Year 2000 costs will be funded
by revenue 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.
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PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
We held our Annual Meeting of Shareholders on February 26, 1999, to elect four
directors and to ratify the selection of independent auditors. The record date
for determining the shareholders entitled to receive notice of and to vote at
the meeting was January 14, 1999. We solicited proxies for the meeting
according to section 14(a) of the Securities and Exchange Act of 1934. There
was no solicitation in opposition to management's solicitations.
Shareholders elected all of management's nominees for director as listed in the
proxy statement for terms expiring in 2002 by the following votes:
Shares Shares Shares
Voted Voted NOT
FOR WITHHELD VOTED
------ -------- -----
Muriel W. Helms 25,518,710 257,008 5,045,010
Ned R. McWherter 25,529,337 246,381 5,045,010
Donald S. Russell, Jr. 25,551,215 224,503 5,045,010
John E. Simkins, Jr. 25,518,544 257,174 5,045,010
Directors C. M. Butler III, Sam J. DiGiovanni, John W. Harris and John F.
McNair III continue to hold office until 2000. Directors Jerry W. Amos, John H.
Maxheim and Walter S. Montgomery, Jr., continue to hold office until 2001.
Shareholders approved the selection by the Board of Directors of the firm of
Deloitte & Touche LLP as our independent auditors for the fiscal year ending
October 31, 1999, by the following vote:
Shares Shares Shares Shares
Voted Voted Voted NOT
FOR AGAINST ABSTAINING VOTED
----- ------- ---------- -----
25,552,561 70,475 152,682 5,045,010
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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 January 31, 1999, the North Carolina State
Treasurer held $27.7 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 February 5, the Carolinas
Utilities Customers Association filed a motion for an evidentiary hearing on
the approval of the increased costs, and on February 18, the NCUC scheduled a
hearing for March 16. The outcome of this proceeding cannot be determined at
this time.
Corporate Organization
On February 26, 1999, the Board of Directors elected Ware F. Schiefer President
and Chief Operating Officer. Prior to his election, he was Executive Vice
President. John H. Maxheim, the former President, retains the title of Chairman
of the Board and Chief Executive Officer.
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.
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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.
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(Registrant)
Date March 12, 1999 /s/ David J. Dzuricky
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David J. Dzuricky
Senior Vice President-Finance
(Principal Financial Officer)
Date March 12, 1999 /s/ Barry L. Guy
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Barry L. Guy
Vice President and Controller
(Principal Accounting Officer)
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