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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended July 31, 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.
- --------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
North Carolina 56-0556998
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1915 Rexford Road, Charlotte, North Carolina 28211
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (704) 364-3120
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at September 6, 2002
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Common Stock, no par value 32,957,316
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Page 1 of 28 pages
PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(In thousands)
July 31, October 31,
2002 2001
Unaudited Audited
---------- ----------
ASSETS
Utility Plant, at original cost $1,685,524 $1,626,176
Less accumulated depreciation 550,378 511,477
---------- ----------
Utility plant, net 1,135,146 1,114,699
---------- ----------
Other Physical Property (net of accumulated depreciation of
$1,479 in 2002 and $1,341 in 2001) 1,123 1,163
---------- ----------
Current Assets:
Cash and cash equivalents 7,677 5,610
Restricted cash 4,228 7,064
Receivables (less allowance for doubtful accounts of
$1,004 in 2002 and $592 in 2001) 42,264 25,898
Gas in storage 49,818 70,220
Deferred cost of gas 6,810 16,310
Refundable income taxes 18,722 22,271
Prepayments and other 33,386 27,928
---------- ----------
Total current assets 162,905 175,301
---------- ----------
Investments, Deferred Charges and Other Assets:
Investments in non-utility activities, at equity 84,096 82,287
Unamortized debt expense 3,932 4,130
Other 16,587 16,078
---------- ----------
Total investments, deferred charges and other assets 104,615 102,495
---------- ----------
Total $1,403,789 $1,393,658
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock $ 347,592 $ 332,038
Retained earnings 265,032 229,718
Accumulated other comprehensive income (1,003) (1,377)
---------- ----------
Total common stock equity 611,621 560,379
Long-term debt 462,000 509,000
---------- ----------
Total capitalization 1,073,621 1,069,379
---------- ----------
Current Liabilities:
Current maturities of long-term debt and sinking fund requirements 47,000 2,000
Notes payable -- 32,000
Accounts payable 42,414 41,144
Deferred income taxes 584 2,344
General taxes accrued 11,200 14,544
Refunds due customers 19,747 31,685
Other 16,559 25,510
---------- ----------
Total current liabilities 137,504 149,227
---------- ----------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 160,357 143,211
Unamortized federal investment tax credits 5,730 6,149
Other 26,577 25,692
---------- ----------
Total deferred credits and other liabilities 192,664 175,052
---------- ----------
Total $1,403,789 $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 Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
--------------------- ------------ -------- -----------------------
2002 2001 2002 2001 2002 2001
-------- -------- -------- -------- -------- ----------
Operating Revenues $127,928 $121,779 $710,550 $997,364 $821,041 $1,144,927
Cost of Gas 80,066 78,142 420,918 705,495 485,300 810,434
-------- -------- -------- -------- -------- ----------
Margin 47,862 43,637 289,632 291,869 335,741 334,493
-------- -------- -------- -------- -------- ----------
Other Operating Expenses:
Operations 27,013 28,802 83,644 86,961 111,042 115,364
Maintenance 4,902 4,975 14,559 14,269 19,353 18,906
Depreciation 14,440 13,003 42,789 38,555 56,293 51,149
General taxes 5,541 5,289 17,923 16,441 25,434 20,873
Income taxes (5,662) (7,516) 39,372 41,733 32,718 34,594
-------- -------- -------- -------- -------- ----------
Total other operating expenses 46,234 44,553 198,287 197,959 244,840 240,886
-------- -------- -------- -------- -------- ----------
Operating Income 1,628 (916) 91,345 93,910 90,901 93,607
-------- -------- -------- -------- -------- ----------
Other Income (Expense):
Non-utility activities, at equity (1,975) (10,722) 20,050 14,008 22,328 11,906
Allowance for equity funds used during construction 231 -- 746 -- 1,240 --
Other, net 513 213 629 (275) 1,080 7,542
Income taxes 487 4,156 (8,822) (5,432) (10,186) (7,681)
-------- -------- -------- -------- -------- ----------
Total other income, net of taxes (744) (6,353) 12,603 8,301 14,462 11,767
-------- -------- -------- -------- -------- ----------
Income Before Utility Interest Charges 884 (7,269) 103,948 102,211 105,363 105,374
Utility Interest Charges 9,861 9,536 29,910 28,845 39,206 39,261
-------- -------- -------- -------- -------- ----------
Net Income $ (8,977) $(16,805) $ 74,038 $ 73,366 $ 66,157 $ 66,113
======== ======== ======== ======== ======== ==========
Average Shares of Common Stock:
Basic 32,822 32,243 32,691 32,119 32,610 32,043
Diluted 32,822 32,243 32,863 32,360 32,798 32,299
Earnings Per Share of Common Stock:
Basic $ (0.27) $ (0.52) $ 2.26 $ 2.28 $ 2.03 $ 2.06
Diluted $ (0.27) $ (0.52) $ 2.25 $ 2.27 $ 2.02 $ 2.05
Cash Dividends Per Share of Common Stock $ 0.40 $ 0.385 $ 1.185 $ 1.135 $ 1.57 $ 1.50
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 Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
-------------------- ------------------- ---------------------
2002 2001 2002 2001 2002 2001
------- -------- ------- ------- ------- ---------
Cash Flows from Operating Activities:
Net income $(8,977) $(16,805) $74,038 $73,366 $66,157 $ 66,113
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization 14,648 13,215 43,381 39,376 57,074 52,306
Other, net 15,667 17,889 13,909 8,651 (3,837) 31,320
Net gain on propane business combination, net
of tax -- -- -- -- -- (5,063)
Change in operating assets and liabilities (54,543) 4,251 (9,794) 32,370 8,783 22,571
------- -------- ------- ------- ------- ---------
Net cash provided by (used in) operating activities (33,205) 18,550 121,534 153,763 128,177 167,247
------- -------- ------- ------- ------- ---------
Cash Flows from Investing Activities:
Utility construction expenditures (22,489) (23,895) (60,225) (64,417) (79,344) (103,697)
Investment in propane partnership -- -- -- -- -- (30,552)
Proceeds from propane business combination -- -- -- -- -- 36,748
Other (32) (197) (104) (6,888) (202) (6,928)
------- -------- ------- ------- ------- ---------
Net cash used in investing activities (22,521) (24,092) (60,329) (71,305) (79,546) (104,429)
------- -------- ------- ------- ------- ---------
Cash Flows from Financing Activities:
Increase (decrease) in bank loans, net -- 35,515 (32,000) (30,000) (69,500) (57,500)
Issuance of long-term debt -- -- -- -- 60,000 60,000
Retirement of long-term debt (2,000) (32,000) (2,000) (32,000) (2,000) (32,000)
Issuance of common stock through dividend
reinvestment and employee stock plans 5,048 4,137 13,586 11,555 17,419 15,296
Dividends paid (13,122) (12,407) (38,724) (36,452) (51,181) (48,058)
------- ------- ------- ------- ------- ---------
Net cash used in financing activities (10,074) (4,755) (59,138) (86,897) (45,262) (62,262)
------- -------- ------- ------- ------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (65,800) (10,297) 2,067 (4,439) 3,369 556
Cash and Cash Equivalents at Beginning of Period 73,477 14,605 5,610 8,747 4,308 3,752
------- -------- ------- ------- ------- ---------
Cash and Cash Equivalents at End of Period $ 7,677 $ 4,308 $ 7,677 $ 4,308 $ 7,677 $ 4,308
======= ======== ======= ======= ======= =========
Cash Paid During the Period for:
Interest $16,057 $17,206 $35,989 $36,834 $39,132 $ 40,431
Income taxes $ 12 $ -- $29,969 $48,745 $32,659 $ 48,936
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 Nine Months
Ended July 31 Ended July 31
--------------------- --------------------
2002 2001 2002 2001
------- -------- ------- -------
Net Income $(8,977) $(16,805) $74,038 $73,366
Other Comprehensive Income:
Equity investments hedging activities, net of tax of ($288)
and $139 for the three months and $210 and ($65) for the
nine months in 2002 and 2001, respectively (449) 210 374 (101)
------- -------- ------- -------
Total Comprehensive Income $(9,426) $(16,595) $74,412 $73,265
======= ======== ======= =======
Reconciliation of Accumulated Other Comprehensive Income:
Balance, beginning of period $ (554) $ (311) $(1,377) $ --
Current period reclassification to earnings 77 -- 635 --
Current period change (526) 210 (261) (101)
------- -------- ------- -------
Balance, end of period $(1,003) $ (101) $(1,003) $ (101)
======= ======== ======= =======
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 July 31, 2002, and October 31,
2001, and the results of operations and cash flows for the three
months, nine months and twelve months ended July 31, 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 nine-month periods ended July 31, 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 Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
--------------------- ------------------- -------------------
In thousands, except per share amounts 2002 2001 2002 2001 2002 2001
------- -------- ------- ------- ------- -------
Net Income $(8,977) $(16,805) $74,038 $73,366 $66,157 $66,113
======= ======== ======= ======= ======= =======
Average shares of common stock
outstanding for basic earnings per share 32,822 32,243 32,691 32,119 32,610 32,043
Contingently issuable shares under
the long-term incentive plan (a) -- -- 172 241 188 256
------- -------- ------- ------- ------- -------
Average shares of dilutive stock 32,822 32,243 32,863 32,360 32,798 32,299
======= ======== ======= ======= ======= =======
Earnings Per Share:
Basic $ (.27) $ (.52) $ 2.26 $ 2.28 $ 2.03 $ 2.06
Diluted $ (.27) $ (.52) $ 2.25 $ 2.27 $ 2.02 $ 2.05
(a) For the three months ended July 31, 2002 and 2001, the inclusion of 172
and 231 contingently issuable shares, respectively, would be
antidilutive.
-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, and Piedmont
Greenbrier Pipeline Company, a wholly owned subsidiary of Piedmont
Natural Gas Company. The investments in the ventures of these three
subsidiaries are accounted for under the equity method. Operations of
our retail energy marketing services segment are conducted by Piedmont
Energy Company, a wholly owned subsidiary of Piedmont Energy Partners,
through its investment in a venture accounted for under the equity
method.
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.
Investment in this venture is accounted for under the equity method.
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
are the same as reported in our audited financial statements for the
year ended October 31, 2001.
Continuing operations by segment for the three months and nine months
ended July 31, 2002 and 2001, are presented below:
Domestic Retail
Natural Gas Energy
In thousands Distribution Marketing Other Total
-------------------- ------------------- ------------------ --------------------
Three Months Ended July 31 2002 2001 2002 2001 2002 2001 2002 2001
-------- -------- ------- -------- ------- ------- -------- --------
Revenues from external customers $127,928 $121,779 $ -- $ -- $ -- $ -- $127,928 $121,779
Margin 47,862 43,637 -- -- -- -- 47,862 43,637
Operations and maintenance
Expenses 31,915 33,777 1 7 9 3 31,925 33,787
Operating income 1,638 (929) (18) (8) (23) 656 1,597 (281)
Other income 2,141 1,570 (1,098) (10,286) (2,242) (1,764) 1,199 (10,480)
Income before income taxes (11,742) (16,404) (1,130) (10,334) (2,254) (1,739) (15,126) (28,477)
Capital expenditures* 23,385 25,434 -- -- -- -- 23,385 25,434
Nine Months Ended July 31
Revenues from external customers $710,550 $997,364 $ -- $ -- $ -- $ -- $710,550 $997,364
Margin 289,632 291,869 -- -- -- (264) 289,632 291,605
Operations and maintenance
Expenses 98,204 101,230 100 9 165 566 98,469 101,805
Operating income 91,306 93,887 (125) (7) (211) (816) 90,970 93,064
Other income 5,668 5,281 16,262 8,152 (103) 1,552 21,827 14,985
Income before income taxes 106,443 112,082 16,092 7,699 (303) 750 122,232 120,531
Capital expenditures* 63,160 69,543 -- -- -- -- 63,160 69,543
*Utility only.
-7-
A reconciliation of net income in the consolidated financial statements for the
three months and nine months ended July 31, 2002 and 2001, is presented below:
Three Months Nine Months
Ended July 31 Ended July
------------------------- -------------------------
In thousands 2002 2001 2002 2001
-------- -------- -------- --------
Income before income taxes for reportable segments $(12,872) $(26,738) $122,535 $119,781
Income before income taxes for other non-utility activities (2,254) (1,739) (303) 750
Income taxes (6,149) (11,672) 48,194 47,165
-------- -------- -------- --------
Net income $ (8,977) $(16,805) $ 74,038 $ 73,366
======== ======== ======== ========
A reconciliation of consolidated assets in the consolidated financial statements
as of July 31, 2002 and October 31, 2001, is presented below:
In thousands 2002 2001
---------- ----------
Domestic natural gas operations $1,386,494 $1,384,952
Retail energy marketing services 26,480 24,717
Other 37,825 27,050
Eliminations/Adjustments (47,010) (43,061)
---------- ----------
Consolidated assets $1,403,789 $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 firm service
agreements with local distribution companies, including Piedmont Natural Gas
Company, for 100% of the 270 million cubic feet per day of firm transportation
capacity on the pipeline. Cardinal is dependent on the Williams-Transco pipeline
system to deliver gas into its system for service to its customers. Cardinal's
long-term debt is secured by Cardinal's assets and by each member's equity
investment in Cardinal.
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 liquified natural gas
(LNG) storage 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 firm 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 each member's
equity investment in Pine Needle.
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
-8-
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.
In July 2002, we recorded a loss in value of $1.4 million on our investment in
US Propane due to an other than temporary decline in the value of the general
partnership interest in Heritage Propane. The other than temporary loss was
calculated based on estimated future cash flow projections that reflect actual
and projected customer growth assumptions for Heritage Propane.
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. Under
the agreement, our maximum capital account restoration is $10 million.
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 Inc. SouthStar
sells natural gas 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 implemented full natural gas retail
competition. SouthStar conducts most of its business in Georgia, and the
unregulated retail gas market is highly competitive.
The Operating Policy of SouthStar contains a provision for the disproportionate
sharing of earnings in excess of a threshold per annum, cumulative return of
17%. This threshold is not reached until all prior period losses are recovered.
Earnings below the 17% return threshold are allocated to members based on their
ownership percentages. Earnings above the threshold are allocated at various
percentages based on margin generated in four defined service areas. The
earnings test is based on SouthStar's fiscal year ending December 31, therefore,
the actual impact, if any, of disproportionate sharing is not known until after
December 31. In July 2002, we estimated that a portion of SouthStar's earnings
for calendar year 2002 will be above the threshold, and that disproportionate
sharing will occur for the first time. Accordingly, our portion of the equity
earnings from SouthStar for the three months and nine months ended July 31,
2002, was reduced $270,000 to reflect our estimate that our earnings from
SouthStar will be at a level of approximately 27% of total earnings rather than
our equity ownership percentage of 30% of total earnings.
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 and are accounted
for under the guidelines of Statement of Financial Accounting Standards (SFAS)
No.133, "Accounting for Derivative Instruments and Hedging Activities." 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
-9-
value method under the guidelines of Emerging Issues Task Force Issue No. 99-2,
"Accounting for Weather Derivatives."
Currently, SouthStar has exposure to supply fluctuations due to the financial
condition of Dynegy. Dynegy manages SouthStar's capacity asset agreements and
supplies the majority of its gas. SouthStar is only obligated to purchase gas at
market prices from Dynegy. In the event that Dynegy is unable to manage
SouthStar's capacity or to supply gas, SouthStar would choose an asset manager
to replace Dynegy and purchase gas from other suppliers. Also, Atlanta Gas Light
Company (AGLC), under the terms of its tariffs with the Georgia Public Service
Commission, has required SouthStar's members to guarantee SouthStar's ability to
pay AGLC's bills for local delivery service. Piedmont Energy Partners has
guaranteed its 30% share of SouthStar's obligation by depositing $13.4 million
with AGLC. This deposit was replaced on August 2, 2002, with a letter of credit
with a bank that expires on August 5, 2003.
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 proposes to build
a 280-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 to commence service in 2005. The pipeline will
originate in Kanawha County, West Virginia, and extend through southwest
Virginia to Granville County, North Carolina. This pipeline will broaden our
access to competitive gas supplies and will also serve new electrical generation
in the region. The pipeline is expected to cost $497 million, with $150 million
of the cost expected to be contributed as equity by the owners and the remainder
expected to be provided by project-financed debt. As of July 31, 2002, we have
made capital contributions to Greenbrier totaling $5.5 million. We have signed a
precedent agreement for firm transportation service with Greenbrier.
Construction of the pipeline is subject to a number of conditions, including
approval by the FERC.
Related Party Transactions
We have related party transactions with three of the entities in which we have
equity investments. These transactions are recorded on the utility's books
either as cost of gas, which is subject to gas cost recovery procedures, or as
operating revenues.
The utility records as gas costs the storage costs charged by Pine Needle as
determined by the FERC. These gas costs were $2.7 million and $2.8 million for
the three months ended July 31, 2002 and 2001, respectively, $8.2 million and
$8.5 million for the nine months ended July 31, 2002 and 2001, respectively, and
$11 million and $11.3 million for the twelve months ended July 31, 2002 and
2001, respectively. We owed Pine Needle $895,000 and $920,000 at July 31, 2002
and 2001, respectively.
The utility records as gas costs the transportation costs charged by Cardinal as
determined by the NCUC. These gas costs were $369,000 for the three months ended
July 31, 2002 and 2001, $1.1 million for the nine months ended July 31, 2002 and
2001, and $1.5 million for the twelve months ended July 31, 2002 and 2001. We
owed Cardinal $123,000 at July 31, 2002 and 2001.
The utility sells gas to SouthStar at prevailing market rates. Operating
revenues from these sales totaled $2.9 million and $4.4 million for the three
months ended July 31, 2002 and 2001, respectively, $7.4 million and $9 million
for the nine months ended July 31, 2002 and 2001, respectively, and $10.6
million and $12.1 million for the twelve months ended July 31, 2002 and 2001,
respectively. SouthStar owed us
-10-
$860,000 and $1.2 million at July 31, 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 nine
months ended July 31, 2002.
Summarized unaudited financial information provided to us by Cardinal for its
fiscal quarters and year-to-date periods ended June 30, 2002 and 2001, is
presented below.
Three Months Nine Months
Ended June 30 Ended June 30
------------------------ ------------------------
In thousands 2002 2001 2002 2001
-------- -------- -------- --------
Revenues $ 4,281 $ 4,281 $ 12,843 $ 12,843
Gross profit -- -- -- --
Income before income taxes 2,252 2,461 6,980 7,598
Total assets 103,965 106,213 103,965 106,213
Summarized unaudited financial information provided to us by Pine Needle for its
fiscal quarters and year-to-date periods ended June 30, 2002 and 2001, is
presented below.
Three Months Nine Months
Ended June 30 Ended June 30
------------------------ ------------------------
In thousands 2002 2001 2002 2001
-------- -------- -------- --------
Revenues $ 5,286 $ 5,300 $ 15,307 $ 15,309
Gross profit -- -- -- --
Income before income taxes 2,401 2,562 7,791 8,037
Total assets 115,094 120,194 115,094 120,194
Summarized unaudited financial information for Heritage Propane for its fiscal
quarters and year-to-date periods ended May 31, 2002 and 2001, as presented in
its Form 10-Q quarterly report, is presented below.
Three Months Nine Months
Ended May 31 Ended May 31
------------------------ ------------------------
In thousands 2002 2001 2002 2001
-------- -------- -------- --------
Revenues $142,638 $132,153 $534,376 $624,757
Gross profit 90,335 72,318 324,695 356,277
Income (Loss) before income taxes (4,319) (5,845) 21,032 39,448
Total assets 714,964 676,403 714,964 676,403
Summarized unaudited financial information provided to us by SouthStar for its
fiscal quarters and year-to-date periods ended June 30, 2002 and 2001, is
presented below.
Three Months Nine Months
Ended June 30 Ended June 30
------------------------ ------------------------
In thousands 2002 2001 2002 2001
-------- -------- -------- --------
Revenues $106,344 $133,133 $508,703 $739,014
Gross profit 15,820 17,625 110,877 128,533
Income (Loss) before income taxes 423 (5,612) 58,583 54,379
Total assets 169,704 194,744 169,704 194,744
-11-
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. 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. The costs 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 amounts determined by published market
indices. 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 sales of gas, are subject to an overall annual cap of $1.6
million 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 and are allocated to
customers. 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 collected
from or refunded to customers.
We have purchased financial call options for natural gas for our South
Carolina gas purchase portfolio for delivery in September 2002 through
March 2003. The costs of these options are components of and are
recovered under the guidelines of the South Carolina experimental
hedging program approved by the Public Service Commission of South
Carolina (PSCSC). The primary benefit of this plan is to stabilize gas
costs for South Carolina customers. 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 is diversified over a rolling 24 months with a short-term
focus (one to 12 months) and a long-term focus (13 to 24 months).
Purchases are executed within the parameters of the matrix compared
with NYMEX monthly prices as reviewed on a daily basis. 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 and recoverable from customers.
-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:
- Regulatory issues, including those that affect allowed rates
of return, terms and condition of service, 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.
- 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.
- 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.
- 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.
- 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.
- The capital-intensive nature of our business, including
governmental approvals, 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.
- 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. Natural gas is
an unregulated commodity subject to market supply and demand
and price volatility. We have a diversified portfolio of local
peaking facilities, transportation and storage contracts with
interstate pipelines
-13-
and supply contracts with major producers and marketers to
satisfy the supply and delivery requirements of our customers.
Because these producers, marketers and pipelines are subject
to operating and financial risks associated with exploring,
drilling, producing, gathering, marketing 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.
- 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.
- Changes in environmental requirements and cost of compliance.
- Earnings of our equity joint venture investments. We have
investments in unregulated retail energy marketing services,
interstate LNG storage operations, intrastate and interstate
pipeline operations and unregulated retail propane operations.
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.
Our Business
Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy
and services company primarily engaged in the distribution of natural gas to
approximately 710,000 residential, commercial and industrial customers in North
Carolina, South Carolina and Tennessee. Piedmont is also invested in a number of
non-utility, energy-related businesses, including companies involved in
unregulated retail natural gas and propane marketing and
-14-
interstate and intrastate natural gas storage and transportation. We also retail
residential and commercial gas appliances in Tennessee.
In the Carolinas, our service area is comprised of numerous cities, towns and
communities including Anderson, Greenville, Spartanburg and Gaffney in South
Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point,
Burlington, Hickory and Spruce Pine in North Carolina. In Tennessee, our service
area is the metropolitan area of Nashville.
We have two reportable business segments, domestic natural gas distribution and
retail energy marketing services. For further information on our segments, see
Note 5 to the condensed consolidated financial statements in this Form 10-Q.
Our utility operations are subject to regulation by the NCUC, the PSCSC and the
TRA as to rates, service area, adequacy of service, safety standards, extensions
and abandonment of facilities, accounting and depreciation. We are also subject
to regulation by the NCUC as to the issuance of securities. We are also subject
to or affected by various federal and state regulations.
Financial Condition and Liquidity
We finance current cash requirements primarily from operating cash flows and
short-term borrowings. Outstanding short-term borrowings under our committed
bank lines of credit totaling $150 million ranged from zero to $3.5 million
during the three months ended July 31, 2002, with an average interest rate of
2.17 %, and from zero to $57 million during the nine months ended July 31, 2002,
with an average interest rate of 2.4 %. The maximum annual fee for the committed
lines of credit is $198,000. We have available an additional uncommitted line of
credit of $73 million at no cost.
Our operations are weather sensitive. The primary factor that impacts our cash
flows from operations is weather. Warmer weather can lead to lower margins from
fewer volumes of natural gas 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 and can lead to
conservation by our customers. Either warm or cold weather that is outside the
normal range of temperatures can lead to less operating cash flows, thereby
increasing short-term borrowings to meet current cash requirements.
Approximately 45% of our revenues are derived from residential customers and
approximately 25% are from commercial customers, both of which are
weather-sensitive customer classes. We have a weather normalization adjustment
(WNA) mechanism in all three states that partially offsets the impact of
unusually cold or warm weather from November through March for these
weather-sensitive customers. The mechanism is only effective in a narrow band
relative to normal weather using a 30-year historical period.
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
-15-
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. Approximately
55% of our cash needs are funded through internal operations. In the current
fiscal year, short-term rates have been more favorable than long-term rates by
approximately 4%. Long-term debt is anticipated to be issued in the fourth
quarter of 2003 from the $250 million combined debt and equity shelf
registration statement filed with the SEC in 2001. We do not anticipate making
an equity offering in the retail market so long as our dividend reinvestment and
stock purchase plans continue to generate approximately $17 million annually in
additional equity. Our credit rating is "A2" from Moody's and "A" from Standard
& Poor's. We are well within the debt default provisions established for our
senior notes, medium-term notes, short-term bank lines of credit and accounts
receivable financings.
The financial condition of the pipelines and marketers that supply and deliver
natural gas to our system can increase our exposure to supply and price
fluctuations. The Williams Companies, Inc., whose subsidiary Transcontinental
Gas Pipe Line Corporation (Transco) is the major pipeline which serves our
Carolina service areas and whose subsidiary Williams Energy Services Company
(Wesco) is a wholesale supplier of commodity natural gas service, has
experienced financial difficulties. Wesco currently provides natural gas to us
under several supply contracts. In addition, Dynegy, Inc., whose subsidiary
Dynegy Marketing and Trade (DM&T) is a wholesale supplier of commodity natural
gas service and interstate asset manager, has experienced financial
difficulties. Dynegy currently provides natural gas to us under several supply
contracts and prior to July 2002, managed a portion of our interstate gas
storage assets. We renegotiated our storage asset management agreements to shift
control of storage injections and withdrawals to us from Dynegy. In all cases
with Transco, Wesco and Dynegy, the products and services are received by us
prior to payment or are subject to payment netting agreements. We believe our
risk exposure to the financial condition of these companies is minimal based on
receipt of the products and other services prior to payment, the renegotiation
of our storage asset management agreements and the availability of other
marketers of natural gas who can meet our supply needs of natural gas if Wesco
and DM&T are unable to deliver.
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 July 31, 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 July 31, 2002, were $23.4 million, compared with $25.2
million for the same period in 2001. Utility construction
-16-
expenditures for the nine months ended July 31, 2002, were $63.1 million,
compared with $69.3 million for the same period in 2001. Utility construction
expenditures for the twelve months ended July 31, 2002, were $84 million,
compared with $109.1 million for the same period in 2001. Due to the continued
growth in our service area, significant utility construction expenditures are
expected to continue.
Our expected future contractual obligations at July 31, 2002, for long-term debt
and pipeline and storage capacity and gas supply 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 $509 $ 47 $ 37 $ -- $425
Pipeline and storage
capacity and gas supply* 924 95 255 140 434
*See Margin discussion under Results of Operations.
At July 31, 2002, our capitalization consisted of 43% in long-term debt and 57%
in common equity. Our long-term targeted capitalization ratio is 45% in
long-term debt and 55% in common equity.
Critical Accounting Policies and Estimates
We prepare our consolidated financial statements in conformity with accounting
principles 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 revenues 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, we evaluate estimates and assumptions. As a
result of this evaluation and any new circumstances, we make adjustments in
subsequent periods to reflect more current information if we determine that
modifications in assumptions and estimates are required.
As noted earlier in this Form 10-Q, our domestic natural gas distribution
segment is subject to regulation by certain state and federal authorities. We
have accounting policies that conform to SFAS 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. We then recognize
these deferred regulatory assets and liabilities through the income statement in
the period in which the same amounts are reflected in rates. We have recorded
$18.2 million of regulatory assets and $33.3 million of regulatory liabilities
as of July 31, 2002, including
-17-
deferred income tax liabilities of $12.2 million. In recording these costs as
regulatory assets, we believe the costs are recoverable under existing
rate-making concepts embodied in current rate orders. If, for any reason, we
cease to meet the criteria for application of regulatory accounting treatment
for all or part of our operations, we would eliminate the regulatory assets and
liabilities related to these portions ceasing to meet such criteria from the
balance sheet and include them in the income statement for the period in which
the discontinuance of regulatory accounting treatment occurs. Such an event
could have a material effect on our results of operations in the period this
action was recorded.
Significant Judgments and Estimates
We believe the following 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, see
Note 1 in Item 8 of our 2001 Form 10-K Annual Report.
Allowance for Uncollectible Accounts. We evaluate the collectibility of our
trade accounts receivable based on our recent 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.
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 analyses of historical data and actuarial estimates. We,
along with independent actuaries, review the liabilities at least annually to
ensure that they are appropriate. While we believe these estimates are
reasonable based on the information 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, nine months and
twelve months ended July 31, 2002, compared with similar periods in 2001.
-18-
Margin
Margin (operating revenues less cost of gas) for the three months ended July 31,
2002, increased $4.2 million compared with the same period in 2001 primarily due
to an increase in delivered volumes of natural gas (system throughput) of 2.3
million dekatherms, or 12%, and the effect such increased sales has on the
manner in which we book and recover demand costs. The increase in delivered
volumes was a result of growth in customer base and sales to industrial
customers.
Margin for the nine months ended July 31, 2002, decreased $2.2 million compared
with the same period in 2001 primarily due to a decrease in system throughput of
7.8 million dekatherms, a 7% decrease, as fewer volumes were consumed by
higher-margin residential and commercial customers. This decrease was partially
offset by an increase in fixed facility charges due to the growth in customer
base. Margin for the current nine-month period reflects revenues from customers
of $19.8 million from the WNA due to weather that was 15% 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
refunds to customers of $8.5 million from the WNA due to weather that was 7%
colder than normal.
Margin for the twelve months ended July 31, 2002, increased $1.2 million
compared with the same period in 2001 primarily due to an increase in fixed
facility charges due to the growth in customer base. This increase was partially
offset by a decrease in system throughput of 9.1 million dekatherms, a 7%
decrease, as fewer volumes were consumed by higher-margin residential and
commercial customers due to weather that was 17% warmer than the previous year.
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.
Dekatherms from secondary market transactions increased 25.3 million from the
same period in 2001. The twelve months ended July 31, 2002, reflect a full year
of the general rate increase for North Carolina customers effective November 1,
2000, compared with the twelve months ended July 31, 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- 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 July 31, 2002,
decreased $1.9 million, or 6%, compared with the same period in 2001 primarily
for the reasons listed below.
-19-
- Decrease in the provision for uncollectibles and
- 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.
Operations and maintenance expenses for the nine months ended July 31, 2002,
decreased $3 million, or 3%, compared with the same period in 2001 primarily for
the reasons listed below.
- Decrease in the provision for uncollectibles and
- 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.
Operations and maintenance expenses for the twelve months ended July 31, 2002,
decreased $3.9 million, or 3%, compared with the same period in 2001 primarily
for the reasons listed below.
- Decrease in the provision for uncollectibles,
- Decrease in outside labor as outsourced positions were
replaced by employees and
- 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.
These decreases were partially offset by an increase in payroll due to the shift
from outsourced positions.
Depreciation
Depreciation expense for the three months, nine months and twelve months ended
July 31, 2002, increased over similar prior periods due to the growth of plant
in service. Due to the continued growth in our service area and our commitment
to capital expansion, we anticipate that depreciation expense will continue to
increase.
General Taxes
General taxes for the three months ended July 31, 2002, increased $252,000
compared with the same period in 2001 primarily due to increases in franchise
taxes and payroll taxes.
General taxes for the nine months and twelve months ended July 31, 2002,
increased $1.5 million and $4.6 million, respectively, compared with the same
periods in 2001 primarily due to increases in property taxes, franchise taxes
and use taxes.
-20-
Other Income
Income from equity investee earnings for the three months, nine months and
twelve months ended July 31, 2002, increased $8.7 million, $6 million and $10.4
million, respectively, compared with the same periods in 2001 primarily due to
an increase in earnings from unregulated retail energy marketing services. This
increase was partially offset by a decrease in earnings from propane that were
impacted by warmer weather and the other than temporary loss of $1.4 million
recorded in July 2002 on our investment in the general partnership of propane.
In July 2001, our retail energy marketing services venture recorded a change in
accounting estimate for lost and unaccounted for gas in unbilled revenues. Our
portion of the adjustment for the reduction in other income was $5 million, net
of taxes. The loss per share impact of the adjustment was $(.15) for the three
months and $(.16) for the nine months and twelve months ended July 31, 2001.
Income from the allowance for equity funds used during construction (AFUDC) for
the three months, nine months and twelve months ended July 31, 2002, increased
$231,000, $746,000 and $1.2 million, respectively, compared with the same
periods in 2001. All of the AFUDC was attributable to borrowed funds in the
prior periods.
Other income for the three months and nine months ended July 31, 2002 increased
$300,000 and $904,000, respectively, compared with the same periods in 2001
primarily due to increases in earnings from merchandise and jobbing operations
and increases in interest income. Other income for the twelve months ended July
31, 2002, decreased $6.5 million compared with the same period in 2001. The
previous twelve-month period includes a gain of $5.1 million, net of taxes, 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. This decrease in the
twelve months ended July 31, 2002, was partially offset by increases in earnings
from merchandise and jobbing operations and an increase in interest income.
Utility Interest Charges
Utility interest charges for the three months and nine months ended July 31,
2002, increased $325,000 and $1.1 million, respectively, compared with the same
periods in 2001 primarily for the reasons listed below.
- Increase in interest on long-term debt from higher amounts of
debt outstanding and
- Decrease in the portion of AFUDC attributable to borrowed
funds.
Decreases in interest on short-term debt due to lower balances outstanding at
lower rates and interest on refunds due customers due to lower balances
outstanding during the periods partially offset these increases for the three
and nine months ended July 31, 2002.
-21-
Utility interest charges for the twelve months ended July 31, 2002, decreased
$55,000 compared with the same period in 2001 primarily due to a decrease in
interest on short-term debt from lower amounts of debt outstanding at lower
rates.
This decrease was partially offset by the following increases.
- Increase in interest on long-term debt from higher amounts of
debt outstanding,
- Increase in interest on refunds due customers from larger
balances outstanding and
- Decrease in the portion of AFUDC attributable to borrowed
funds.
Accounting Pronouncements
Effective November 1, 2002, we will adopt SFAS No. 143, "Accounting for Asset
Retirement Obligations" (FAS 143). FAS 143 establishes standards of accounting
for an asset retirement obligation (ARO) arising from the acquisition,
construction, development and operation of a long-lived asset. An ARO exists
when there is a legal obligation to retire a tangible long-lived asset. The fair
value of an ARO is required to be recorded as a liability along with an
offsetting plant asset when the obligation is incurred. Accretion of the
liability due to the passage of time will be an operating expense and the
capitalized cost will be depreciated over the useful life of the long-lived
asset. Rate-regulated entities must recognize a regulatory asset or liability
for differences in the timing of period costs of AROs due to the ability to
recover costs related to retirement of long-lived assets through rates charged
to customers. We are currently evaluating the effects of FAS 143 and have formed
no opinion as to its effect on financial position or results of operations.
Effective November 1, 2002, we will adopt SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (FAS 144). FAS 144 provides one
accounting model to be used for long-lived assets to be disposed of by sale,
whether previously held and used or newly acquired. We are currently evaluating
the effects of FAS 144 and have formed no opinion as to its effect on financial
position or results of operations.
In 2001, the American Institute of Certified Public Accountants issued an
exposure draft of a proposed Statement of Position (SOP), "Accounting for
Certain Costs Related to Property, Plant, and Equipment." This proposed SOP
would create a project timeline framework for capitalizing costs related to
property, plant and equipment construction. The SOP would require that property,
plant and equipment assets be accounted for at the component level and
associated administrative and general costs incurred in connection with capital
projects be expensed in the current period. The final SOP is anticipated to be
issued in the fourth quarter of 2002 and, as currently proposed, would be
effective for us on November 1, 2002.
-22-
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 July 31, 2002, we had no short-term debt outstanding. The weighted average
interest rates on short-term debt for the three months, nine months and twelve
months ended July 31, 2002, were 2.17%, 2.40% and 3.30%, 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 July 31, 2002, about our long-term debt
that is sensitive to changes in interest rates.
Expected Maturity Date
---------------------- Fair Value
There- at July 31,
2002 2003 2004 2005 2006 after Total 2002
---- ----- ------ ---- ----- ------ ----- -----------
Fixed Rate
Long-Term Debt
(in million) $-- $ 47 $ 2 $-- $ 35 $ 425 $ 509 $556
Average Interest Rate -- 6.39% 10.06% -- 9.44% 7.55% 7.59%
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:
- Ratio of total debt to total capitalization, including balance
sheet leverage,
- Ratio of net cash flows to capital expenditures,
- Funds from operations interest coverage,
- Ratio of funds from operations to average total debt and
- Pre-tax interest coverage.
Qualitative factors include, among other things:
- Stability of regulation in each jurisdiction in which we
operate,
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- Risks and controls inherent with the distribution of natural
gas,
- Predictability of cash flows,
- Business strategy and management,
- Industry position and
- Contingencies.
At July 31, 2002, our long-term debt, consisting of medium-term notes and senior
notes, was 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 Form 10-Q.
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PART II. OTHER INFORMATION
Item 5. Other Information
Regulatory Proceedings
On March 28, 2002, we filed an application with the NCUC requesting rates and
charges to increase annual revenues by $28.2 million, an increase of 6.8%. In
addition, we requested changes to cost allocations and rate design and changes
in tariffs and service regulations. On August 5, a stipulation among Piedmont,
the Public Staff of the NCUC and the Carolina Utility Customers Association was
filed with the NCUC. The stipulation resolved all outstanding issues between the
stipulating parties and provided for an annual increase in revenues of $13.9
million. A hearing was held on August 27. At the hearing and based on further
residential rate design changes agreed to by us, the only intervenor who did not
sign the stipulation did not oppose the stipulation. We expect an order from the
NCUC to be effective November 1, 2002. 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 generally defines in
advance the parameters for executing hedging transactions and provides that
costs incurred under the non-discretionary features of the plan will be deemed
to be prudently incurred gas costs. A hearing was held on June 19 to consider
approval of the hedging program. An order from the NCUC is still pending and we
are unable to determine the outcome of this proceeding at this time.
On May 3, 2002, we filed an application with the PSCSC requesting an annual
increase in revenues of $15.3 million, an increase of 10.5%. In addition, we
requested approval of new depreciation rates, changes in cost allocations and
rate design and changes in tariffs and service regulations. Under a settlement
agreement between us and the commission staff, we would be entitled to receive
an annual revenue increase of approximately $8.9 million and to recover our
deferred demand-side-management costs. Not all parties agreed to the settlement.
A hearing was held on September 4 and 5 and we expect an order from the PSCSC to
be effective November 1, 2002. 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 substantially all of the
natural gas distribution assets and certain of the liabilities, including
potential remediation costs of a manufactured gas plant site, of North Carolina
Gas Service (NCGS), a division of NUI Utilities, Inc., for approximately $26
million in cash. The NCUC has previously authorized NUI to use deferral
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accounting, or to create a regulatory asset for future recovery in rates, for
expenditures made in connection with environmental matters. 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 the NCUC. We filed for approval of the NCGS asset
acquisition with the NCUC on May 31, 2002. A hearing was held on August 26. The
acquisition is also subject to approval by the utilities commission in another
state in which NUI operates. We anticipate the approvals and closing of the
purchase before the end of the fiscal year.
Election to Board of Directors
On August 23, 2002, the Board of Directors elected Aubrey B. Harwell, Jr., to
the Board, effective September 1. Mr. Harwell, an attorney, is senior, founding
and managing partner of Neal & Harwell of Nashville, Tennessee.
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 -
On May 15, 2002, we filed a Form 8-K regarding a press release
announcing an agreement to purchase the assets of North Carolina Gas
Service, a natural gas distribution division of NUI Utilities, Inc.,
for approximately $26 million in cash.
Outside of the third quarter reporting period, we filed a Form 8-K on
August 13, 2002, regarding a press release reporting that our Chief
Executive Officer and Chief Financial Officer had voluntarily signed
and filed sworn statements on August 9, 2002, with the Securities and
Exchange Commission certifying the filings made by us with the SEC in
2001 and 2002.
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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.
-----------------------------------------
(Registrant)
Date September 12, 2002 /s/ David J. Dzuricky
------------------ -----------------------------------------
David J. Dzuricky
Senior Vice President and Chief Financial
Officer (Principal Financial Officer)
Date September 12, 2002 /s/ Barry L. Guy
------------------ -----------------------------------------
Barry L. Guy
Vice President and Controller
(Principal Accounting Officer)
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CERTIFICATIONS
I, Ware F. Schiefer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Piedmont
Natural Gas Company, Inc.;
2. Based on my knowledge, this quarterly report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
quarterly report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report.
Date September 12, 2002 /s/ Ware F. Schiefer
------------------ -----------------------------------------
Ware F. Schiefer
Chief Executive Officer
I, David J. Dzuricky, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Piedmont
Natural Gas Company, Inc.;
2. Based on my knowledge, this quarterly report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
quarterly report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly report,
fairly present in all material respects the financial
condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
quarterly report.
Date September 12, 2002 /s/ David J. Dzuricky
------------------ -----------------------------------------
David J. Dzuricky
Senior Vice President and Chief Financial
Officer (Principal Financial Officer)
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