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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, 2002
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 June 3, 2002
--------------------------- ---------------------------
Common Stock, no par value 32,792,921
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Page 1 of 25 pages
PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
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PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(In thousands)
April 30, October 31,
2002 2001
Unaudited Audited
----------- -----------
ASSETS
------
Utility Plant, at original cost $ 1,662,917 $ 1,626,176
Less accumulated depreciation 536,890 511,477
----------- -----------
Utility plant, net 1,126,027 1,114,699
----------- -----------
Other Physical Property (net of accumulated depreciation of
$1,433 in 2002 and $1,341 in 2001) 1,139 1,163
----------- -----------
Current Assets:
Cash and cash equivalents 73,477 5,610
Restricted cash 4,130 7,064
Receivables (less allowance for doubtful accounts of
$2,634 in 2002 and $592 in 2001) 58,617 25,898
Gas in storage 19,091 70,220
Deferred cost of gas 8,201 16,310
Refundable income taxes 1,212 22,271
Prepayments and other 20,586 27,928
----------- -----------
Total current assets 185,314 175,301
----------- -----------
Investments, Deferred Charges and Other Assets:
Investments in non-utility activities, at equity 101,023 82,287
Unamortized debt expense 4,026 4,130
Other 15,012 16,078
----------- -----------
Total investments, deferred charges and other assets 120,061 102,495
----------- -----------
Total $ 1,432,541 $ 1,393,658
=========== ===========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock equity:
Common stock $ 342,544 $ 332,038
Retained earnings 287,131 229,718
Accumulated other comprehensive income (554) (1,377)
----------- -----------
Total common stock equity 629,121 560,379
Long-term debt 509,000 509,000
----------- -----------
Total capitalization 1,138,121 1,069,379
----------- -----------
Current Liabilities:
Current maturities of long-term debt and sinking fund requirements 2,000 2,000
Notes payable -- 32,000
Accounts payable 51,739 41,144
Deferred income taxes 3,152 2,344
Income taxes accrued 2,044 --
General taxes accrued 7,627 14,544
Refunds due customers 28,135 31,685
Other 23,554 25,510
----------- -----------
Total current liabilities 118,251 149,227
----------- -----------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 143,679 143,211
Unamortized federal investment tax credits 5,869 6,149
Other 26,621 25,692
----------- -----------
Total deferred credits and other liabilities 176,169 175,052
----------- -----------
Total $ 1,432,541 $ 1,393,658
=========== ===========
See notes to condensed consolidated financial statements.
-2-
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Condensed Statements of Consolidated Income (Unaudited)
(In thousands)
Three Months Six Months Twelve Months
Ended Ended Ended
April 30 April 30 April 30
--------------------- --------------------- ---------------------
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Operating Revenues $293,865 $ 408,012 $582,622 $ 875,585 $814,893 $1,154,360
Cost of Gas 175,297 288,382 340,852 627,353 483,376 820,032
-------- --------- -------- --------- -------- ----------
Margin 118,568 119,630 241,770 248,232 331,517 334,328
-------- --------- -------- --------- -------- ----------
Other Operating Expenses:
Operations 27,681 27,915 56,631 58,158 112,831 113,340
Maintenance 4,898 4,975 9,657 9,295 19,426 18,298
Depreciation 14,253 12,803 28,349 25,552 54,857 50,463
General Taxes 7,127 5,546 12,382 11,152 25,183 20,013
Income Taxes 21,497 23,210 45,034 49,249 30,727 36,742
-------- --------- -------- --------- -------- ----------
Total other operating expenses 75,456 74,449 152,053 153,406 243,024 238,856
-------- --------- -------- --------- -------- ----------
Operating Income 43,112 45,181 89,717 94,826 88,493 95,472
-------- --------- -------- --------- -------- ----------
Other Income (Expense), Net of Taxes:
Non-utility activities, at equity 8,371 4,695 12,799 14,944 7,606 12,637
Allowance for equity funds used during construction 164 -- 311 -- 817 --
Other, net 43 (424) 237 (290) 638 3,203
-------- --------- -------- --------- -------- ----------
Total other income, net of taxes 8,578 4,271 13,347 14,654 9,061 15,840
-------- --------- -------- --------- -------- ----------
Income Before Utility Interest Charges 51,690 49,452 103,064 109,480 97,554 111,312
Utility Interest Charges 9,845 9,583 20,049 19,309 39,225 38,640
-------- --------- -------- --------- -------- ----------
Net Income $ 41,845 $ 39,869 $ 83,015 $ 90,171 $ 58,329 $ 72,672
======== ========= ======== ========= ======== ==========
Average Shares of Common Stock:
Basic 32,689 32,126 32,624 32,056 32,464 31,900
Diluted 32,861 32,357 32,796 32,302 32,668 32,174
Earnings Per Share of Common Stock:
Basic $ 1.28 $ 1.24 $ 2.54 $ 2.81 $ 1.80 $ 2.28
Diluted $ 1.27 $ 1.23 $ 2.53 $ 2.79 $ 1.79 $ 2.26
Cash Dividends Per Share of Common Stock $ 0.40 $ 0.385 $ 0.785 $ 0.75 $ 1.555 $ 1.48
See notes to condensed consolidated financial statements.
-3-
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Condensed Statements of Consolidated Cash Flows (Unaudited)
(in thousands)
-----------------------------------------------------------
Three Months Six Months Twelve Months
Ended Ended Ended
April 30 April 30 April 30
-------------------- ----------- -------- ---------------------
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Cash Flows from Operating Activities:
Net income $ 41,845 $ 39,869 $ 83,015 $ 90,171 $ 58,329 $ 72,672
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 14,443 13,079 28,733 26,161 55,748 52,346
Other, net (3,018) 20,719 (1,758) (9,238) (1,615) 16,172
Net gain on propane business combination, net
of tax -- -- -- -- -- (5,063)
Change in operating assets and liabilities 73,436 (19,761) 44,749 28,118 67,470 (58,675)
-------- -------- -------- -------- -------- ---------
Net cash provided by operating activities 126,706 53,906 154,739 135,212 179,932 77,452
-------- -------- -------- -------- -------- ---------
Cash Flows from Investing Activities:
Utility construction expenditures (20,423) (14,035) (37,736) (40,522) (80,750) (104,920)
Investment in propane partnership -- -- -- -- -- (30,552)
Proceeds from propane business combination -- -- -- -- -- 36,748
Other (34) (59) (71) (6,691) (367) (7,005)
-------- -------- -------- -------- -------- ---------
Net cash used in investing activities (20,457) (14,094) (37,807) (47,213) (81,117) (105,729)
-------- -------- -------- -------- -------- ---------
Cash Flows from Financing Activities:
Increase (Decrease) in bank loans, net (33,000) (31,015) (32,000) (65,515) (33,985) 3,985
Issuance of long-term debt -- -- -- -- 60,000 60,000
Retirement of long-term debt -- -- -- -- (32,000) (2,000)
Issuance of common stock through dividend
reinvestment and employee stock plans 4,407 3,871 8,537 7,418 16,508 14,941
Dividends paid (13,071) (12,363) (25,602) (24,044) (50,466) (47,206)
-------- -------- -------- -------- -------- ---------
Net cash provided by (used in) financing activities (41,664) (39,507) (49,065) (82,141) (39,943) 29,720
-------- -------- -------- -------- -------- ---------
Net Increase in Cash and Cash Equivalents 64,585 305 67,867 5,858 58,872 1,443
Cash and Cash Equivalents at Beginning of Period 8,892 14,300 5,610 8,747 14,605 13,162
-------- -------- ------ -------- -------- ---------
Cash and Cash Equivalents at End of Period $ 73,477 $ 14,605 $ 73,477 $ 14,605 $ 73,477 $ 14,605
======== ======== ======== ======== ======== =========
Cash Paid During the Period for:
Interest $ 3,765 $ 2,720 $ 19,932 $ 19,628 $ 40,281 $ 38,103
Income taxes $ 29,290 $ 48,685 $ 29,957 $ 48,745 $ 32,642 $ 81,570
See notes to condensed consolidated financial statements.
-4-
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Statements of Consolidated Comprehensive Income (Unaudited)
(In thousands)
Three Months Six Months
Ended April 30 Ended April 30
------------------ ------------------
2002 2001 2002 2001
---- ---- ---- ----
Net Income $41,845 $39,869 $83,015 $90,171
Other Comprehensive Income:
Equity investments hedging activities, net of tax of ($272)
for the three months and ($498) for the six months in
2002 and ($204) in 2001 431 (311) 823 (311)
------- ------- ------- -------
Total Comprehensive Income $42,276 $39,558 $83,838 $89,860
======= ======= ======= =======
Reconciliation of Accumulated Other Comprehensive Income:
Balance, beginning of period ($985) $ -- ($1,377) $ --
Current period reclassification to earnings 371 -- 557 --
Current period change 60 (311) 266 (311)
------- ------- ------- -------
Balance, end of period ($554) ($311) ($554) ($311)
======= ======= ======= =======
See notes to condensed consolidated financial statements.
-5-
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 2001 Form 10-K 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, 2002, and October 31, 2001, and the
results of operations and cash flows for the three months, six months and
twelve months ended April 30, 2002 and 2001.
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, 2002, 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 Six Months Twelve Months
Ended Ended Ended
April 30 April 30 April 30
In thousands except per share amounts ------------------- ------------------- -------------------
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
Net Income $41,845 $39,869 $83,015 $90,171 $58,329 $72,672
======= ======= ======= ======= ======= =======
Average shares of common stock
outstanding for basic earnings per share 32,689 32,126 32,624 32,056 32,464 31,900
Contingently issuable shares under
the long-term incentive plan 172 231 172 246 204 274
------- ------- ------- ------- ------- -------
Average shares of dilutive stock 32,861 32,357 32,796 32,302 32,668 32,174
======= ======= ======= ======= ======= =======
Earnings Per Share:
Basic $1.28 $1.24 $2.54 $2.81 $1.80 $2.28
Diluted $1.27 $1.23 $2.53 $2.79 $1.79 $2.26
-6-
5. Business Segments
We have two reportable business segments, domestic natural gas
distribution and retail energy marketing services. Operations of our
domestic natural gas distribution segment are conducted by the parent
company and by Piedmont Intrastate Pipeline Company and Piedmont
Interstate Pipeline Company, two wholly owned subsidiaries of our wholly
owned subsidiary, Piedmont Energy Partners. Operations of our retail
energy marketing services segment are conducted by Piedmont Energy
Company, a wholly owned subsidiary of Piedmont Energy Partners, through
its ownership of an equity method investment.
Our activities included in Other in the segment tables consist primarily
of propane operations conducted by Heritage Propane Partners, L.P., a
master limited partnership. Piedmont Propane Company, a wholly owned
subsidiary of Piedmont Energy Partners, has an equity interest in US
Propane, L.P., the general partner and the owner of approximately 31% of
the limited partnership interest of Heritage Propane Partners. All of our
activities other than the utility operations of the parent are included
in other income in the statements of consolidated income.
We evaluate performance based on margin, operations and maintenance
expenses, operating income and income before taxes. The basis of
segmentation and the basis of the measurement of segment profit or loss
have not changed from that reported in our audited financial statements
for the year ended October 31, 2001.
Continuing operations by segment for the three months and six months
ended April 30, 2002 and 2001, are presented below:
Domestic Retail
Natural Gas Energy
In thousands Distribution Marketing Other Total
------------------ ----------------- ----------------- -------------------
Three Months Ended April 30 2002 2001 2002 2001 2002 2001 2002 2001
--------------------------- ---- ---- ---- ---- ---- ---- ---- ----
Revenues from external customers $293,865 $408,012 $ -- $ -- $ -- $ -- $293,865 $408,012
Margin 118,568 119,630 -- -- -- (264) 118,568 119,366
Operations and maintenance expenses 32,580 32,890 53 -- 140 589 32,773 33,479
Operating income 43,112 45,181 (54) (1) (156) (857) 42,902 44,323
Other income 1,674 1,956 11,143 4,883 1,651 1,221 14,468 8,060
Income before income taxes 56,439 60,773 11,148 4,732 1,494 368 69,081 65,873
Capital expenditures 21,492 15,323 -- -- -- -- 21,492 15,323
Six Months Ended April 30
-------------------------
Revenues from external customers $582,622 $875,585 $ -- $ -- $ -- $ -- $582,622 $875,585
Margin 241,770 248,232 -- -- -- (264) 241,770 247,968
Operations and maintenance expenses 66,288 67,453 99 1 156 564 66,543 68,018
Operating income 89,668 94,816 (107) 1 (189) (833) 89,372 93,984
Other income 3,527 3,711 17,360 18,439 2,140 3,316 23,027 25,466
Income before income taxes 118,185 128,486 17,221 18,032 1,952 2,490 137,358 149,008
Capital expenditures 39,776 44,109 -- -- -- -- 39,776 44,109
-7-
A reconciliation of net income in the condensed consolidated financial
statements for the three months and six months ended April 30, 2002 and 2001, is
presented below:
Three Months Six Months
Ended April 30 Ended April 30
------------------- ---------------------
In thousands 2002 2001 2002 2001
---- ---- ---- ----
Income before income taxes for reportable segments $67,587 $65,505 $135,406 $146,518
Income before income taxes for other non-utility activities 1,494 368 1,952 2,490
Income taxes 27,236 26,004 54,343 58,837
------- ------- -------- --------
Net income $41,845 $39,869 $ 83,015 $ 90,171
======= ======= ======== ========
A reconciliation of consolidated assets in the condensed consolidated financial
statements as of April 30, 2002 and October 31, 2001, is presented below:
In thousands 2002 2001
---- ----
Total assets for reportable segments $1,432,367 $1,409,669
Other assets 68,334 27,050
Eliminations/Adjustments (44,146) (43,061)
---------- ----------
Consolidated assets $1,456,555 $1,393,658
========== ==========
Risks of Equity Investments
Piedmont Intrastate Pipeline Company is a 16.45% member of Cardinal Pipeline
Company, L.L.C. The other members are subsidiaries of The Williams Companies,
Inc., SCANA Corporation and Progress Energy, Inc. Cardinal owns and operates a
104-mile intrastate natural gas pipeline in North Carolina and is regulated by
the North Carolina Utilities Commission (NCUC). Cardinal has long-term service
agreements with local distribution companies for 100% of the 270 million cubic
feet per day of firm transportation capacity on the pipeline. Cardinal is
dependent on the interstate pipeline company serving North Carolina to deliver
gas into its system for service to these companies. Cardinal's long-term debt is
secured by Cardinal's assets and by the equity membership interests of
Cardinal's members.
Piedmont Interstate Pipeline Company is a 35% member of Pine Needle LNG Company,
L.L.C. The other members are subsidiaries of The Williams Companies, Inc., SCANA
Corporation, Progress Energy, Inc., and Amerada Hess Corporation and the
Municipal Gas Authority of Georgia. Pine Needle owns a liquefied natural gas
peaking demand facility in North Carolina and is regulated by the Federal Energy
Regulatory Commission (FERC). Storage capacity of the facility is four billion
cubic feet with vaporization capability of 400 million cubic feet per day and is
fully subscribed under long-term service agreements with customers. We subscribe
to slightly more than one-half of this capacity to provide gas for peak-use
periods when demand is the highest. Pine Needle enters into interest-rate swap
agreements to modify the interest characteristics of its long-term debt. Pine
Needle's long-term debt is secured by Pine Needle's assets and by the equity
membership interests of Pine Needle's members.
Piedmont Propane Company owns 20.69% of the membership interest in US Propane,
L.P. The other partners are subsidiaries of TECO Energy, Inc., AGL Resources,
Inc., and Atmos Energy Corporation. US Propane owns all of the general
partnership interest and approximately 31% of the limited partnership interest
in Heritage Propane Partners, L.P., a marketer of propane through a nationwide
retail distribution
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network. Heritage competes with electricity, natural gas and fuel oil, as well
as with other companies in the retail propane distribution business. The propane
business, like natural gas, is seasonal, with weather conditions significantly
affecting the demand for propane. Heritage purchases propane at numerous supply
points for delivery to Heritage primarily via railroad tank cars and common
carrier transport. Heritage's profitability is sensitive to changes in the
wholesale prices of propane. Heritage utilizes hedging transactions to provide
price protection against significant fluctuations in prices. Heritage also buys
and sells financial instruments for trading purposes through a wholly owned
subsidiary. Financial instruments used in connection with this liquids trading
activity are marked to market.
The limited partnership agreement of US Propane requires that in the event of
liquidation, all limited partners would be required to restore capital account
deficiencies, including any unsatisfied obligations of the partnership. Our
maximum capital account restoration would be $9,980,000. Currently, our capital
account is positive. We believe that liquidation is not probable or likely to
occur and have not recorded this liability.
Piedmont Energy Company has a 30% interest in SouthStar Energy Services LLC. The
other members are subsidiaries of AGL Resources, Inc., and Dynegy Holdings, Inc.
SouthStar offers a combination of unregulated energy products and services to
industrial, commercial and residential customers in the southeastern United
States. SouthStar was formed and began marketing energy services in Georgia in
1998 when that state became the first in the Southeast to fully open to natural
gas retail competition. After three years of deregulation, the Governor of
Georgia appointed a task force to reevaluate the deregulation of the Georgia
natural gas market. As a result of the task force report, additional natural gas
deregulation legislation was passed by the Georgia House and Senate on March 19,
2002. Among other things, the legislation establishes a consumer bill of rights
and a "last resort" gas supplier for the poor and those unable to purchase gas
from marketers due to poor credit histories. Non-profit electric membership
corporations are also allowed to set up gas marketing affiliates. In May 2002,
three companies, including SouthStar, submitted proposals with the Georgia
Public Service Commission (GPSC) to be chosen as the "last resort" gas supplier.
Only one company will be designated as the "last resort" service provider by the
GPSC. A decision by the GPSC is required by July 1, 2002, although an earlier
decision is expected.
SouthStar manages commodity price and weather risks through hedging activities
using derivative financial instruments, physical commodity contracts and
option-based weather derivative contracts. Financial contracts in the form of
futures, options and swaps are used to hedge the price volatility of natural
gas. These derivative transactions qualify as cash flow hedges. Weather
derivative contracts are used to preserve margins in the event of
warmer-than-normal weather during the winter period. Such contracts are
accounted for using the intrinsic value method under the guidelines of EITF 99-2
"Accounting for Weather Derivatives." Based upon the cumulative heating degree
days in November 2001 through March 2002, SouthStar received $3,767,000 under
the contracts in April.
Piedmont Greenbrier Pipeline Company, LLC, is a wholly owned subsidiary with a
33% equity interest in Greenbrier Pipeline Company, LLC (Greenbrier). The other
member is a subsidiary of Dominion Resources, Inc. Greenbrier is proposing to
build a 263-mile interstate pipeline linking multiple gas supply basins and
storage to the growing demand of markets in the Southeast, with initial capacity
of 600,000 dekatherms of natural gas per day. The pipeline will originate in
Kanawha County, West Virginia, and extend through southwest Virginia to
Granville County, North Carolina. The pipeline is expected to cost $497 million,
with approximately $150 million of the cost expected to be contributed as equity
by the
-9-
owners and the remainder expected to be provided by project financed debt. As of
April 30, 2002, we have made capital contributions to Greenbrier totaling
$4,599,000.
Related Party Transactions
We have related party transactions with three of the entities in which we have
minority equity investments. These transactions are recorded on the utility's
books either as gas costs, which are subject to gas cost recovery procedures, or
as gas sales.
The utility records as gas costs the fixed storage costs charged by Pine Needle
as determined by the FERC. These gas costs were $2,761,000 and $2,872,000 for
the three months ended April 30, 2002 and 2001, respectively, $5,521,000 and
$5,745,000 for the six months ended April 30, 2002 and 2001, respectively, and
$11,043,000 and $11,246,000 for the twelve months ended April 30, 2002 and 2001,
respectively. We owed Pine Needle $920,000 and $957,000 at April 30, 2002 and
2001, respectively.
The utility records as gas costs the fixed transportation costs charged by
Cardinal as determined by the NCUC. These gas costs were $369,000 for the three
months ended April 30, 2002 and 2001, $737,000 for the six months ended April
30, 2002 and 2001, and $1,475,000 for the twelve months ended April 30, 2002 and
2001. We owed Cardinal $123,000 at April 30, 2002 and 2001.
The utility sells gas to SouthStar at prevailing market rates. Operating
revenues from these sales totaled $2,779,000 and $3,043,000 for the three months
ended April 30, 2002 and 2001, respectively, $4,491,000 and $4,685,000 for the
six months ended April 30, 2002 and 2001, respectively, and $11,998,000 and
$7,721,000 for the twelve months ended April 30, 2002 and 2001, respectively.
SouthStar owed us $1,314,000 and $2,541,000 at April 30, 2002 and 2001,
respectively.
The members of SouthStar have entered into a capital contributions agreement
that requires each member to contribute additional capital for SouthStar to pay
invoices for goods or services provided from any member or its affiliates
whenever funds are not available to pay these invoices. The capital
contributions to pay affiliated invoices are repaid as funds become available,
but are subordinate to SouthStar's revolving line of credit with a bank. There
was no activity related to this agreement during the three months and six months
ended April 30, 2002.
Summarized unaudited financial information provided to us by Cardinal for their
fiscal quarters ended March 31, 2002 and 2001, is presented below.
Three Months Six Months
Ended March 31 Ended March 31
-------------------- --------------------
In thousands 2002 2001 2002 2001
---- ---- ---- ----
Revenues $ 4,281 $ 4,281 $ 8,562 $ 8,562
Gross profit -- -- -- --
Income before income taxes 2,349 2,491 4,727 5,137
Total assets 104,967 106,952 104,967 106,952
Summarized unaudited financial information provided to us by Pine Needle for
their fiscal quarters ended March 31, 2002 and 2001, is presented below.
-10-
Three Months Six Months
Ended March 31 Ended March 31
-------------------- --------------------
In thousands 2002 2001 2002 2001
---- ---- ---- ----
Revenues $ 4,949 $ 4,958 $ 10,021 $ 10,008
Gross profit -- -- -- --
Income before income taxes 2,664 2,724 5,390 5,474
Total assets 112,104 116,738 112,104 116,738
Summarized unaudited financial information for Heritage Propane Partners, L.P.,
for their fiscal quarters ended February 28, 2002 and 2001, as presented in
their Form 10-Q quarterly report, is presented below.
Three Months Six Months
Ended February 28 Ended February 28
-------------------- --------------------
In thousands 2002 2001 2002 2001
---- ---- ---- ----
Revenues $229,635 $326,760 $391,738 $492,605
Gross profit 132,492 188,054 254,360 283,960
Income before income taxes 30,130 43,330 25,351 45,293
Total assets 779,640 718,575 779,640 718,575
Summarized unaudited financial information provided to us by SouthStar for their
fiscal quarters ended March 31, 2002 and 2001, is presented below.
Three Months Six Months
Ended March 31 Ended March 31
-------------------- --------------------
In thousands 2002 2001 2002 2001
---- ---- ---- ----
Revenues $230,288 $336,731 $402,359 $605,881
Gross profit 59,828 52,505 95,057 110,908
Income before income taxes 37,438 32,365 58,160 59,991
Total assets 167,811 264,843 167,811 264,843
6. Derivatives and Hedging Activities
We purchase natural gas for our regulated operations for resale under
tariffs approved by the state commissions having jurisdiction over the
service territory where the customer is located. We recover the cost of
gas purchased for regulated operations through purchased gas adjustment
mechanisms. We structure the pricing and performance of gas supply
contracts to maximize flexibility and minimize cost and risk for the
customer. Our risk management policies allow us to use financial
instruments for trading purposes and to hedge risks, but not for
speculative trading. These policies were developed by management. An
energy risk management committee of multi-department representation
monitors risks in accordance with these policies.
We have purchased financial call options for natural gas for our
Tennessee gas purchase portfolio for delivery in December 2002, January
2003 and February 2003. Previously purchased options were sold April 1,
2002, and proceeds were used to purchase options that are currently
held. The cost of these options and all gas costs incurred are
components of and are recovered under the guidelines of the Tennessee
Incentive Plan. This plan establishes an incentive-sharing mechanism
based on differences in the actual cost of gas purchased and benchmark
rates. These differences, after applying a monthly 1% positive or
negative deadband, together with income from marketing transportation
and capacity in the secondary market and income (margin) from secondary
market
-11-
sales of gas, are subject to an overall annual cap of $1,600,000 for
shareholder gains or losses. The net gains or losses on gas procurement
costs within the deadband (99%-101% of the benchmark) are not subject
to sharing under the Incentive Plan. Any net gains or losses on gas
procurement costs outside the deadband are combined with capacity
management benefits and shared between customers and shareholders. This
amount is subject to the overall annual cap and is placed in a
regulatory asset to be surcharged or refunded to customers.
During April 2002, we purchased financial call options for natural gas
for our South Carolina gas purchase portfolio for delivery in June 2002
through October 2002. The costs of these options are a component of and
are recovered under the guidelines of the South Carolina experimental
hedging program approved by the Public Service Commission of South
Carolina (PSCSC) on March 26, 2002. The primary benefit of this plan is
to stabilize gas costs for South Carolina ratepayers. This plan
operates off of pricing indices that are tied to future projected gas
prices as traded on a national exchange and is limited to 60% of the
annual normalized sales volumes. The hedging program uses a matrix of
historic, inflation-adjusted gas prices over the past four years plus
the current season with a heavier weighting on current data as the
basis for determining the purchase of financial instruments. The supply
cost portfolio will be diversified over a rolling 24 months with a
short-term focus (1 to 12 months) and a long-term focus (13 to 24
months). Purchases will be executed within the parameters of the matrix
as compared to daily NYMEX monthly prices. There is limited subjective
discretion in making purchases with little or no risk of speculation in
the market. The PSCSC, in its order approving the plan, stated that the
actions we take in accordance with the plan will be deemed to be
prudent.
-12-
Item 2. Management's Discussion and Analysis of Financial Condition and Results
--------------------------------------------------------------------------------
of Operations
-------------
Forward-Looking Statements
--------------------------
This document and other documents we file with the Securities and Exchange
Commission (SEC) contain forward-looking statements. In addition, our senior
management and other authorized spokespersons may make forward-looking
statements orally to analysts, investors, the media and others. Our discussion
contains forward-looking statements concerning, among others, plans, objectives,
proposed capital expenditures and future events or performance. 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, actual results may differ materially from those suggested by the
forward-looking statements. Important factors that could cause actual results to
differ include:
o Regulatory issues, including those that affect allowed rates
of return, rate structures and financings. In addition to the
impact of our three state regulatory commissions, we purchase
natural gas transportation and storage services from
interstate and intrastate pipeline companies whose rates and
services are regulated by the FERC and the NCUC, respectively.
o Residential, commercial and industrial growth in our service
territories. The ability to grow our customer base and the
pace of that growth are impacted by general business and
economic conditions such as interest rates, inflation,
fluctuations in the capital markets and the overall strength
of the economy in our local markets and the United States.
o Deregulation, unanticipated impacts of restructuring and
increased competition in the energy industry. We face
competition from electric companies and energy marketing and
trading companies. As a result of continued deregulation, we
expect this highly competitive environment to continue.
o The potential loss of large-volume industrial customers to
alternate fuels or to bypass or the shift by such customers to
special competitive contracts at lower per-unit margins.
o The ability to meet internal performance goals. Regulatory
issues, customer growth, deregulation, economic and capital
market conditions, the price and availability of natural gas
and weather conditions can impact our performance goals.
o The capital-intensive nature of our business, including
development project delays or changes in project costs.
Weather, general economic conditions and the cost of funds to
finance our capital projects can materially alter the cost of
a project.
o Changes in the availability and price of natural gas. To meet
customer requirements, we must acquire sufficient gas supplies
and pipeline capacity to ensure delivery to our distribution
system while also ensuring that our supply and capacity
contracts will allow us to remain competitive. We have a
diversified portfolio of local peaking facilities,
transportation and storage contracts with interstate pipelines
and supply contracts with major producers and marketers to
satisfy the supply and delivery requirements of our customers.
Because these producers and pipelines are subject to
-13-
risks associated with exploring, drilling, producing,
gathering and transporting natural gas, their risks also
increase our exposure to supply and price fluctuations. We
engage in hedging activity in order to minimize price
volatility for our customers.
o Changes in weather conditions. Weather conditions and other
natural phenomena can have a large impact on our earnings.
Severe weather conditions can impact our suppliers and the
pipelines that deliver gas to our distribution system.
Extended mild or severe weather, either during the winter
period or the summer period, can have a significant impact on
the demand for and the price of natural gas.
o Changes in environmental requirements and cost of compliance.
o Earnings of our equity investments. We have investments in
unregulated retail energy marketing services, interstate
liquefied natural gas (LNG) operations, intrastate pipeline
operations and propane. These companies have risks that are
inherent to their industries and, as an equity investor, we
assume such risks.
All of these factors are difficult to predict and many are beyond our control.
Accordingly, while we believe these forward-looking statements to be reasonable,
there can be no assurance that they will approximate actual experience or that
the expectations derived from them will be realized. When used in our documents
or oral presentations, the words "anticipate," "believe," "intend," "plan,"
"estimate," "expect," "objective," "projection," "budget," "forecast," "goal" or
similar words or future or conditional verbs such as "will," "would," "should,"
"could" or "may" are intended to identify forward-looking statements.
Factors relating to regulation and management are also described or incorporated
in our Annual Report on Form 10-K, as well as information included in, or
incorporated by reference from, future filings with the SEC. Some of the factors
that may cause actual results to differ have been described above. Others may be
described elsewhere in this report. There also may be other factors besides
those described or incorporated in this report or in the Form 10-K that could
cause actual conditions, events or results to differ from those in the
forward-looking statements.
Forward-looking statements reflect our current expectations only as of the date
they are made. We assume no duty to update these statements should expectations
change or actual results differ from current expectations.
Financial Condition and Liquidity
---------------------------------
We finance current cash requirements primarily from operating cash flows and
short-term borrowings. Outstanding short-term borrowings under our bank lines of
credit totaling $150 million ranged from zero to $30 million during the three
months ended April 30, 2002, with an average interest rate of 2.22%, and from
zero to $57 million during the six months ended April 30, 2002, with an average
interest rate of 3.47%. Our operations are weather sensitive. Warmer weather can
lead to lower margins from fewer volumes of natural gas being sold or
transported. Colder weather that increases the volumes of natural gas sold to
weather-sensitive customers can result in the inability of some of our customers
to pay their bills. Either warm or cold weather that is outside the normal range
of temperatures can lead to less operating cash flow, thereby
-14-
increasing short-term borrowings to meet current cash requirements. The level of
short-term borrowings can vary significantly due to changes in the wholesale
prices of natural gas that are charged by suppliers and to increased gas
supplies required to meet our customers' needs during cold weather. Short-term
debt increases when wholesale prices for natural gas increase because we must
pay suppliers for the gas before we can recover our costs from customers through
their monthly bills. In addition to 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.
The natural gas business is seasonal in nature resulting primarily in
fluctuations in balances in accounts receivable from customers, inventories of
stored natural gas and accounts payable to suppliers in addition to short-term
borrowings discussed above. 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 payable and accounts receivable
increased from October 31, 2001, to April 30, 2002, due to this seasonality 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. The capital expansion program supports our approximately 4%
current annual growth in customer base. Utility construction expenditures for
the three months ended April 30, 2002, were $21.5 million, compared with $15.3
million for the same period in 2001. Utility construction expenditures for the
six months ended April 30, 2002, were $39.7 million, compared with $44 million
for the same period in 2001. Utility construction expenditures for the twelve
months ended April 30, 2002, were $85.9 million, compared with $109.8 million
for the same period in 2001.
Our expected future contractual obligations at April 30, 2002, are as follows:
In millions Payments Due by Period
----------------------------------------------------
Less than 1-3 4-5 After
Contractual Obligations Total 1 Year Years Years 5 Years
----------------------- ----- ------ ----- ----- -------
Long-term debt $511 $ 2 $ 49 $ 35 $425
Pipeline and storage 938 95 256 141 446
capacity and gas supply*
*100% recoverable due to rate mechanism.
At April 30, 2002, our capitalization consisted of 45% in long-term debt and 55%
in common equity.
Critical Accounting Policies and Estimates
------------------------------------------
We have prepared our consolidated financial statements in conformity with
accounting principles
-15-
generally accepted in the United States of America. The preparation of financial
statements requires us to make estimates and assumptions that affect the
reported amounts of assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses during the periods
reported. Actual results may change significantly from the use of our current
estimates. We base our estimates on historical experience, where applicable, and
other relevant factors that we believe are reasonable under the circumstances.
On an ongoing basis, management evaluates estimates and assumptions. As a result
of this evaluation and any new circumstances, adjustments are made in subsequent
periods to reflect more current information if management determines that
modifications in assumptions and estimates are required.
We believe the following critical accounting policies affect the more
significant judgments and estimates used in the preparation of our consolidated
financial statements. For a complete discussion of significant accounting
policies, refer to Note 1 in Item 8 of our 2001 Form 10-K.
Regulation. We are subject to regulation by certain state and federal
authorities. We have accounting policies that conform to Statement of Financial
Accounting Standards No. 71, "Accounting for the Effect of Certain Types of
Regulation" and are in accordance with accounting requirements and ratemaking
practices prescribed by the regulatory authorities. The application of these
accounting policies allows us to defer expenses and income on the balance sheet
as regulatory assets and liabilities when it is probable that those expenses and
income will be allowed in the rate setting process in a period different from
the period in which they would have been reflected in the income statement by an
unregulated company. These deferred regulatory assets and liabilities are then
flowed through the income statement in the period in which the same amounts are
reflected in rates. If, for any reason, we cease to meet the criteria for
application of regulatory accounting treatment for all or part of our
operations, the regulatory assets and liabilities related to these portions
ceasing to meet such criteria would be eliminated from the balance sheet and
included in the income statement for the period in which the discontinuance of
regulatory accounting treatment occurs.
Allowance for Uncollectible Accounts. We evaluate the collectibility of our
trade accounts receivable based on our recent past loss history and an overall
assessment of past due trade accounts receivable amounts outstanding.
Employee Benefits. We have a defined-benefit pension plan for the benefit of
substantially all full-time regular employees. Several statistical and other
factors, which attempt to anticipate future events, are used in calculating the
expense and liability related to the plan. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as determined by us, within certain guidelines. In
addition, our actuarial consultants also use subjective factors such as
withdrawal and mortality rates to estimate the projected benefit obligation. The
actuarial assumptions used may differ materially from actual results due to
changing market and economic conditions, higher or lower withdrawal rates or
longer or shorter life spans of participants. These differences may result in a
significant impact on the amount of pension expense recorded in future periods.
-16-
Self Insurance. We are self-insured for certain losses related to general
liability, group medical benefits and workers' compensation. We maintain stop
loss coverage with third party insurers to limit our total exposure. Our
liabilities represent estimates of the ultimate cost of claims incurred as of
the balance sheet date. The estimated liabilities are not discounted and are
established based upon analysis of historical data and actuarial estimates. The
liabilities are reviewed by management and third party actuaries at least
annually to ensure that they are appropriate. While we believe these estimates
are reasonable based on the information currently available, if actual trends,
including the severity or frequency of claims or fluctuations in premiums,
differ from our estimates, our financial results could be impacted.
Results of Operations
---------------------
We will discuss the results of operations for the three months, six months and
twelve months ended April 30, 2002, compared with similar periods in 2001.
Margin
Margin (operating revenues less cost of gas) for the three months ended April
30, 2002, decreased $1.1 million compared with the same period in 2001 primarily
due to 1.2 million fewer dekatherms consumed by higher-margin residential and
commercial customers even though delivered volumes of natural gas, which we
refer to as system throughput, increased 1.6 million dekatherms from the same
period in 2001.
Margin for the current three-month period reflects revenues from customers of
$7.4 million from the weather normalization adjustment (WNA) due to weather that
was 7% warmer than normal. The WNA is designed to offset the impact of unusually
cold or warm weather on customer billings and operating margin. The same period
in 2001 reflected increased margin of $5.9 million from the WNA due to weather
that was 5% warmer than normal.
Margin for the six months ended April 30, 2002, decreased $6.5 million compared
with the same period in 2001 primarily due to a decrease in system throughput of
10.1 million dekatherms as fewer volumes were consumed by higher-margin
residential and commercial customers. Margin for the current six-month period
reflects WNA revenues of $19.8 million, compared with WNA refunds of $8.5
million for the same period in 2001.
Margin for the twelve months ended April 30, 2002, decreased $2.8 million
compared with the same period in 2001 primarily due to a decrease in system
throughput of 16.4 million dekatherms as fewer volumes were consumed by all
customer classes due to weather that was 18% warmer. Margin for the current
twelve-month period reflects WNA revenues of $19.8 million, compared with WNA
refunds of $8.5 million for the same period in 2001.
Under gas cost recovery mechanisms, we revise rates periodically without formal
rate proceedings to reflect changes in the wholesale cost of gas. Charges to
cost of gas are based on the amount recoverable under approved rate schedules.
The net amounts of any over- or under-
-17-
recoveries of gas costs are added to or deducted from cost of gas and included
in refunds due customers in the consolidated financial statements. In North
Carolina and South Carolina, recovery of gas costs is subject to annual gas cost
recovery proceedings to determine the prudency of our gas purchases. We have
been found prudent in all such past proceedings; however, there can be no
guarantee that we will be found prudent in future proceedings.
Operations and Maintenance Expenses
Operations and maintenance expenses for the three months ended April 30, 2002,
decreased $311,000 compared with the same period in 2001, less than 1%,
primarily for the reasons listed below.
o Decrease in transportation clearing expenses due to lower fuel
costs and depreciation on vehicles.
o Decrease in outside labor as outsourced positions were
replaced by employees.
These decreases were partially offset by an increase in payroll due to the shift
from outsourced positions and an increase in rents and leases.
Operations and maintenance expenses for the six months ended April 30, 2002,
decreased $1.2 million compared with the same period in 2001, less than 2%,
primarily for the reasons listed below.
o Decrease in outside labor as outsourced positions were
replaced by employees.
o Decrease in the provision for uncollectibles.
These decreases were partially offset by an increase in payroll due to the shift
from outsourced positions.
Operations and maintenance expenses for the twelve months ended April 30, 2002,
increased $619,000 compared with the same period in 2001, less than 1%,
primarily for the reasons listed below.
o Increase in the provision for uncollectibles.
o Increase in risk insurance due primarily to general liability
coverage and workers' compensation.
o Increase in advertising expenses.
These increases were partially offset by the following decreases.
o Decrease in outside labor as outsourced positions were
replaced by employees.
o Decrease in employee benefits due primarily to a decrease in
pension expense as administrative fees are now paid from
benefit plan assets rather than by the sponsor and a decrease
in the cost of postretirement healthcare and life insurance
benefits.
-18-
Depreciation
Depreciation expense for the three months, six months and twelve months ended
April 30, 2002, increased over similar prior periods due to the growth of plant
in service.
General Taxes
General taxes for the three months ended April 30, 2002, increased $1.6 million
compared with the same period in 2001 primarily due to an increase in property
taxes.
General taxes for the six months and twelve months ended April 30, 2002,
increased $1.2 million and $5.2 million, respectively, compared with the same
periods in 2001 primarily due to increases in property taxes, franchise taxes
and use taxes.
Other Income
Income from equity investee earnings for the three months ended April 30, 2002,
increased $3.7 million compared with the same period in 2001 primarily due to an
increase in earnings from unregulated retail energy marketing services.
Income from equity investee earnings for the six months and twelve months ended
April 30, 2002, decreased $2.1 million and $5 million, respectively, compared
with the same periods in 2001 primarily due to decreases in earnings from
unregulated retail energy marketing services and from propane, both of which
were impacted by warmer weather.
Other income for the twelve months ended April 30, 2002, decreased $2.6 million
compared with the same period in 2001. The previous twelve-month period includes
a gain from the contribution of substantially all of our propane assets in
exchange for an interest in Heritage Propane Partners in August 2000, partially
offset by losses from the propane operations prior to the contribution.
Utility Interest Charges
Utility interest charges for the three months ended April 30, 2002, increased
$262,000 compared with the same period in 2001 primarily due to an increase in
interest on long-term debt from higher amounts of debt outstanding and a
decrease in the portion of the allowance for funds used during construction
(AFUDC) attributable to borrowed funds.
Utility interest charges for the six months and twelve months ended April 30,
2002, increased $740,000 and $585,000, respectively, compared with the same
periods in 2001 primarily for the reasons listed below.
o Increase in interest on long-term debt from higher amounts of
debt outstanding.
o Increase in interest on refunds due customers from larger
balances outstanding.
o Decrease in the portion of AFUDC attributable to borrowed
funds.
-19-
Decreases in interest on short-term debt due to lower balances outstanding at
lower rates partially offset these increases for the three, six and twelve
months ended April 30, 2002.
-20-
Item 3. Quantitative and Qualitative Disclosures about Market Risk
-------------------------------------------------------------------
All financial instruments discussed below are held for purposes other than
trading. We are potentially exposed to market risk due to changes in interest
rates and the cost of gas. Exposure to interest rate changes relates to both
short- and long-term debt. Exposure to gas cost variations relates to the supply
of and demand for natural gas.
Interest Rate Risk
------------------
We have short-term borrowing arrangements to provide working capital and general
corporate funds. The level of borrowings under such arrangements varies from
period to period, depending upon many factors including our investments in
capital projects. Future short-term interest expense and payments will be
impacted by both short-term interest rates and borrowing levels.
At April 30, 2002, we had no short-term debt outstanding. The weighted average
interest rates on short-term debt for the three months and six months ended
April 30, 2002, were 2.22% and 3.47%, respectively. We primarily borrow highly
liquid debt instruments of a short-term nature. The carrying amount of such debt
approximates fair value.
The table below provides information at April 30, 2002, about our long-term debt
that is sensitive to changes in interest rates.
Expected Maturity Date
----------------------
Fair Value
There- at April 30,
2002 2003 2004 2005 2006 after Total 2002
---- ---- ---- ---- ---- ----- ----- ------------
Fixed Rate
Long-Term Debt
(in millions) $2 $47 $2 -- $35 $425 $511 $544
Average Interest
Rate 10.06% 6.39% 10.06% -- 9.44% 7.55% 7.60%
Credit Rating
-------------
Credit ratings impact our ability to obtain short-term and long-term financing
and the cost of such financings. In determining our credit ratings, the rating
agencies consider various factors. The more significant quantitative factors
include, among other things:
o Ratio of total debt to total capitalization, including balance
sheet leverage.
o Ratio of net cash flows to capital expenditures.
o Funds from operations interest coverage.
o Ratio of funds from operations to average total debt.
o Pre-tax interest coverage.
-21-
Qualitative factors include, among other things, stability of regulation in each
jurisdiction of our operations, risks and controls inherent with the
distribution of natural gas, predictability of cash flows, business strategy and
management, industry position and contingencies.
At April 30, 2002, our long-term debt consisting of medium-term notes and senior
notes were rated A2 by Moody's and A by Standard and Poor's.
Commodity Price Risk
--------------------
In the normal course of business, we utilize contracts of various duration for
the forward sales and purchases of natural gas. We manage our gas supply costs
through a portfolio of short- and long-term procurement contracts with several
suppliers. Due to cost-based rate regulation in our utility operations, we have
limited exposure to changes in commodity prices as substantially all changes in
purchased gas costs are passed on to customers under gas cost recovery
mechanisms.
Additional information concerning market risk is set forth in "Financial
Condition and Liquidity" in Item 2 of this report on page 14.
-22-
PART II. OTHER INFORMATION
Item 5. Other Information
--------------------------
Regulatory Proceedings
----------------------
On March 28, 2002, we filed an application with the North Carolina Utilities
Commission (NCUC) requesting rates and charges to increase annual revenues by
$28.2 million, an increase of 6.8%. In addition, we are requesting changes to
cost allocations and rate design and changes in tariffs and service regulations.
We expect any allowed rate increase to be effective November 1, 2002. A hearing
has been set to begin on August 27. We are unable to determine the outcome of
this proceeding at this time.
As previously reported, the NCUC, on February 26, 2002, issued an order in a
generic proceeding that hedging of gas costs is permissible. The NCUC concluded
that prudently incurred costs in connection with hedging should be treated as
gas costs and would be subject to the annual gas cost prudency review based on
the information available at the time of the hedge, not at the time of the
prudency review. Each local distribution company may develop its own plan. On
April 10, we requested the NCUC to reconsider its decision to make costs
incurred in connection with hedging subject to an after-the-fact review for
prudence. We also filed an experimental natural gas hedging program for
reconsideration and pre-approval. The proposed program defines in advance the
parameters for executing hedging transactions and provides that costs incurred
under the plan will be deemed to be prudently incurred gas costs. A hearing has
been scheduled for June 19 to consider approval of the hedging program as filed.
We are unable to determine the outcome of this proceeding at this time.
As previously reported, we filed a petition with the Public Service Commission
of South Carolina (PSCSC) requesting permission to engage in certain gas cost
hedging activities for the purpose of cost stabilization. We requested advance
prudency determination and full recovery under gas cost recovery mechanisms for
all costs to be incurred in connection with the implementation and
administration of the hedging program. On March 26, 2002, the PSCSC issued an
order approving this experimental hedging program, including the advance
prudency determination.
On May 3, 2002, we filed an application with the PSCSC requesting an annual
increase in rates of $15.3 million in revenues, an increase of 10.5%. In
addition, we are requesting approval of new depreciation rates, changes in cost
allocations and rate design and changes in tariffs and service regulations. This
is the first general rate filing in South Carolina in seven years. Hearings have
been set for September 4 and 5. We are unable to determine the outcome of this
proceeding at this time.
Asset Purchase
--------------
On May 15, 2002, we announced an agreement to purchase the natural gas
distribution assets of North Carolina Gas Service (NCGS), a division of NUI
Utilities, Inc., for approximately $26 million in cash. NCGS serves
approximately 14,000 customers in Rockingham and Stokes Counties, North
Carolina. Completion of the acquisition is contingent upon approval from several
regulatory bodies, including
-23-
the NCUC. We filed for approval of the NCGS asset acquisition with the NCUC on
May 31, 2002. We anticipate the approvals and closing of the purchase before the
end of the calendar year.
Item 6. Exhibits and Reports on Form 8-K
-----------------------------------------
(a) Exhibits -
12 Computation of Ratio of Earnings to Fixed Charges.
(b) Reports on Form 8-K -
None.
-24-
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 12, 2002 /s/ David J. Dzuricky
--------------- ---------------------------------------
David J. Dzuricky
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date June 12, 2002 /s/ Barry L. Guy
--------------- ---------------------------------------
Barry L. Guy
Vice President and Controller
(Principal Accounting Officer)
-25-