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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 January 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.
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(Exact name of registrant as specified in its charter)
North Carolina 56-0556998
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1915 Rexford Road, Charlotte, North Carolina 28211
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (704) 364-3120
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at March 5, 2002
- ------------------------------ ----------------------------------
Common Stock, no par value 32,666,965
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Page 1 of 22 pages
PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(In thousands)
January 31, October 31,
2002 2001
Unaudited Audited
------------ ------------
ASSETS
Utility Plant, at original cost $ 1,643,527 $ 1,626,176
Less accumulated depreciation 524,693 511,477
------------ ------------
Utility plant, net 1,118,834 1,114,699
------------ ------------
Other Physical Property (net of accumulated depreciation of
$1,387 in 2002 and $1,341 in 2001) 1,153 1,163
------------ ------------
Current Assets:
Cash and cash equivalents 8,892 5,610
Restricted cash 5,632 7,064
Receivables (less allowance for doubtful accounts of
$2,304 in 2002 and $592 in 2001) 99,240 25,898
Gas in storage 74,365 70,220
Deferred cost of gas 26,033 16,310
Deferred income taxes 12,540 --
Refundable income taxes 1,212 22,271
Prepayments and other 5,326 27,928
------------ ------------
Total current assets 233,240 175,301
------------ ------------
Investments, Deferred Charges and Other Assets:
Investments in non-utility activities, at equity 88,539 82,287
Unamortized debt expense 4,116 4,130
Other 15,613 16,078
------------ ------------
Total investments, deferred charges and other assets 108,268 102,495
------------ ------------
Total $ 1,461,495 $ 1,393,658
============ ============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock $ 338,137 $ 332,038
Retained earnings 258,357 229,718
Accumulated other comprehensive income (985) (1,377)
------------ ------------
Total common stock equity 595,509 560,379
Long-term debt 509,000 509,000
------------ ------------
Total capitalization 1,104,509 1,069,379
------------ ------------
Current Liabilities:
Current maturities of long-term debt and sinking fund requirements 2,000 2,000
Notes payable 33,000 32,000
Accounts payable 60,183 41,144
Deferred income taxes -- 2,344
Income taxes accrued 18,138 --
General taxes accrued 7,235 14,544
Refunds due customers 42,473 31,685
Other 17,571 25,510
------------ ------------
Total current liabilities 180,600 149,227
------------ ------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 145,532 143,211
Unamortized federal investment tax credits 6,009 6,149
Other 24,845 25,692
------------ ------------
Total deferred credits and other liabilities 176,386 175,052
------------ ------------
Total $ 1,461,495 $ 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 except per share amounts)
Three Months Twelve Months
Ended Ended
January 31 January 31
------------------------ --------------------------
2002 2001 2002 2001
--------- --------- --------- ----------
Operating Revenues $ 288,757 $ 467,573 $ 929,040 $1,029,302
Cost of Gas 165,555 338,971 596,462 699,441
--------- --------- --------- ----------
Margin 123,202 128,602 332,578 329,861
--------- --------- --------- ----------
Other Operating Expenses:
Operations 28,950 30,244 113,064 113,438
Maintenance 4,759 4,319 19,503 17,427
Depreciation 14,096 12,749 53,407 49,798
General Taxes 5,255 5,606 23,601 19,338
Income Taxes 23,537 26,039 32,312 36,122
--------- --------- --------- ----------
Total other operating expenses 76,597 78,957 241,887 236,123
--------- --------- --------- ----------
Operating Income 46,605 49,645 90,691 93,738
--------- --------- --------- ----------
Other Income (Expense), net of tax:
Non-utility activities, at equity 4,592 10,249 4,185 9,806
Allowance for equity funds used during construction 148 -- 853 --
Other, net 29 134 (85) 4,467
--------- --------- --------- ----------
Total other income (expense), net of tax 4,769 10,383 4,953 14,273
--------- --------- --------- ----------
Income Before Utility Interest Charges 51,374 60,028 95,644 108,011
Utility Interest Charges 10,204 9,726 39,291 37,773
--------- --------- --------- ----------
Net Income $ 41,170 $ 50,302 $ 56,353 $ 70,238
========= ========= ========= ==========
Average Shares of Common Stock:
Basic 32,560 31,989 32,327 31,753
Diluted 32,729 32,249 32,543 32,045
Earnings Per Share of Common Stock:
Basic $ 1.26 $ 1.57 $ 1.74 $ 2.21
Diluted $ 1.26 $ 1.56 $ 1.73 $ 2.19
Cash Dividends Per Share of Common Stock $ 0.385 $ 0.365 $ 1.54 $ 1.46
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 Twelve Months
Ended Ended
January 31 January 31
------------------------- -------------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Cash Flows from Operating Activities:
Net income $ 41,170 $ 50,302 $ 56,353 $ 70,238
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 14,290 13,082 54,277 52,411
Other, net 1,260 (29,957) 22,123 (5,616)
Net gain on propane business combination, net
of tax -- -- -- (5,063)
Change in operating assets and liabilities (28,687) 47,879 (25,621) 11,459
--------- --------- --------- ---------
Net cash provided by operating activities 28,033 81,306 107,132 123,429
--------- --------- --------- ---------
Cash Flows from Investing Activities:
Utility construction expenditures (17,312) (26,487) (74,361) (109,006)
Investment in propane partnership -- -- -- (30,552)
Proceeds from propane business combination -- -- -- 36,748
Other (38) (6,632) (392) (7,258)
--------- --------- --------- ---------
Net cash used in investing activities (17,350) (33,119) (74,753) (110,068)
--------- --------- --------- ---------
Cash Flows from Financing Activities:
Increase (decrease) in bank loans, net 1,000 (34,500) (32,000) (36,500)
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 4,130 3,547 15,972 15,264
Dividends paid (12,531) (11,681) (49,759) (46,345)
--------- --------- --------- ---------
Net cash used in financing activities (7,401) (42,634) (37,787) (9,581)
--------- --------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 3,282 5,553 (5,408) 3,780
Cash and Cash Equivalents at Beginning
of Period 5,610 8,747 14,300 10,520
--------- --------- --------- ---------
Cash and Cash Equivalents at End of Period $ 8,892 $ 14,300 $ 8,892 $ 14,300
========= ========= ========= =========
Cash Paid During the Period for:
Interest $ 16,167 $ 16,908 $ 39,236 $ 38,361
Income taxes $ 667 $ 60 $ 52,037 $ 85,841
See notes to condensed consolidated financial statements.
-4-
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Statement of Consolidated Comprehensive Income (Unaudited)
(In thousands)
Three Months
Ended January 31
---------------------------
2002 2001
-------- --------
Net Income $ 41,170 $ 50,302
Other Comprehensive Income:
Equity investments hedging activities, net of tax of ($630) (985) --
-------- --------
Total Comprehensive Income $ 40,185 $ 50,302
======== ========
Reconciliation of Accumulated Other Comprehensive Income:
Balance, beginning of period $ (1,377) $ --
Current period reclassification to earnings (101) --
Current period change 493 --
-------- --------
Balance, end of period $ (985) $ --
======== ========
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 Annual Report.
2. In our opinion, the unaudited condensed consolidated financial
statements include all normal recurring adjustments necessary for a
fair statement of financial position at January 31, 2002, and October
31, 2001, and the results of operations and cash flows for the three
months and twelve months ended January 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 period ended January 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 Twelve Months
Ended Ended
January 31 January 31
---------------------- ----------------------
In thousands except per share amounts 2002 2001 2002 2001
------- ------- ------- -------
Net Income $41,170 $50,302 $56,353 $70,238
======= ======= ======= =======
Average shares of common stock
outstanding for basic earings per share 32,560 31,989 32,327 31,753
Contingently issuable shares under the
long-term incentive plan 169 260 216 292
------- ------- ------- -------
Average shares of dilutive stock 32,729 32,249 32,543 32,045
======= ======= ======= =======
Earnings Per Share:
Basic $ 1.26 $ 1.57 $ 1.74 $ 2.21
Diluted $ 1.26 $ 1.56 $ 1.73 $ 2.19
-6-
5. Business Segments and Non-Utility Activities
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.
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 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 ended January 31,
2002 and 2001, are presented below:
Domestic Retail
Natural Gas Energy
In thousands Distribution Marketing Other Total
------------ ---------- -------- --------
2002
Revenues from external customers $288,757 $ -- $ -- $288,757
Margin 123,202 -- -- 123,202
Operations and maintenance
expenses 33,709 46 16 33,771
Operating income 46,556 (53) (33) 46,470
Other income 1,853 6,217 489 8,559
Income before income taxes 61,745 6,074 458 68,277
Capital expenditures 18,283 -- -- 18,283
2001
Revenues from external customers $467,573 $ -- $ -- $467,573
Margin 128,602 -- -- 128,602
Operations and maintenance
expenses 34,563 2 (26) 34,539
Operating income 49,635 2 24 49,661
Other income 1,755 13,556 2,094 17,405
Income before income taxes 67,712 13,301 2,121 83,134
Capital expenditures 28,786 -- -- 28,786
-7-
A reconciliation of net income in the condensed consolidated financial
statements for the three months ended January 31, 2002 and 2001, is
presented below:
In thousands 2002 2001
------- -------
Income before income taxes for reportable segments $67,819 $81,013
Income before income taxes for other non-utility activities 458 2,121
Income taxes 27,107 32,832
------- -------
Net income $41,170 $50,302
======= =======
A reconciliation of consolidated assets in the condensed consolidated
financial statements as of January 31, 2002 and October 31, 2001, is
presented below:
In thousands 2002 2001
----------- -----------
Total assets for reportable segments $ 1,481,851 $ 1,409,669
Other assets 25,939 27,050
Eliminations (46,295) (43,061)
----------- -----------
Consolidated assets $ 1,461,495 $ 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 network.
Heritage competes with electricity, natural gas and fuel oil,
-8-
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 price
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 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, proposed legislation to
revamp Georgia's natural gas deregulation is scheduled to be voted on
by the Georgia House and Senate on March 19. Among other things, the
proposed legislation would establish a consumer bill of rights and a
"last resort" regulated gas supplier for the poor and those unable to
purchase gas from unregulated marketers due to poor credit histories.
Non-profit electric membership corporations would also be allowed to
set up gas marketing affiliates. We are unable to determine the outcome
of the proposed legislation and the impact on SouthStar's operations at
this time.
SouthStar manages commodity price 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 the fair value of the open positions are recorded
on the balance sheet with the unrealized gain or loss in other
comprehensive income. 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
and December 2001, SouthStar would have the right to receive the
maximum value under the contract and has recorded a receivable of
$5,500,000 at December 31, 2001. The contracts extend through March
2002.
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
-9-
Kanawha County, West Virginia, and extend through southwest Virginia to
Granville County, North Carolina. The $497 million pipeline is expected
to be project financed by the owners. As of January 31, 2002, we have
made capital contributions of $2,893,000.
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 cost charged by Pine
Needle as determined by the FERC. These accrued gas costs were
$2,761,000 and $2,872,000 for the three months ended January 31, 2002
and 2001, respectively, and $11,155,000 and $10,913,000 for the twelve
months ended January 31, 2002 and 2001, respectively. We owed Pine
Needle $920,000 and $957,000 at January 31, 2002 and 2001,
respectively.
The utility records as gas costs the fixed transportation costs charged
by Cardinal as determined by the NCUC. These accrued gas costs were
$369,000 for the three months ended January 31, 2002 and 2001, and
$1,475,000 for the twelve months ended January 31, 2002 and 2001. We
owed Cardinal $123,000 at January 31, 2002 and 2001.
The utility sells gas to SouthStar at prevailing market rates.
Operating revenues from these sales totaled $1,712,000 and $1,642,000
for the three months ended January 31, 2002 and 2001, respectively, and
$12,262,000 and $7,932,000 for the twelve months ended January 31, 2002
and 2001, respectively. SouthStar owed us $380,000 and zero at January
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
entity affiliated as a member 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 quarter ended January 31, 2002.
Summarized unaudited financial information presented to us by Cardinal
for their fiscal quarters ended December 31, 2001 and 2000, is
presented below.
In thousands 2001 2000
-------- --------
Revenues $ 4,281 $ 4,281
Gross profit -- --
Income before income taxes 2,378 2,646
Total assets 105,676 116,864
Summarized unaudited financial information presented to us by Pine
Needle for their fiscal quarters ended December 31, 2001 and 2000, is
presented below.
-10-
In thousands 2001 2000
-------- --------
Revenues $ 5,072 $ 5,050
Gross profit -- --
Income before income taxes 2,727 2,751
Total assets 110,762 120,126
Summarized unaudited financial information for Heritage for their
fiscal quarters ended November 30, 2001 and 2000 as presented in their
10-Q filing with the SEC, is presented below.
In thousands 2001 2000
-------- --------
Revenues $162,103 $165,845
Gross profit 101,868 95,906
Income (loss) before income taxes (4,779) 1,963
Total assets 792,536 665,145
Summarized unaudited financial information presented to us by SouthStar
for their fiscal quarters ended December 31, 2001 and 2000, is
presented below.
In thousands 2001 2000
-------- --------
Revenues $163,958 $269,150
Gross profit 35,229 58,403
Income before income taxes 20,717 27,626
Total assets 156,513 277,169
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.
We have purchased financial call options for natural gas for our
Tennessee gas purchase portfolio for delivery in November 2002,
December 2002, January 2003 and February 2003. The cost of these
options and all gas costs incurred are a component 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 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.
-11-
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, rate structure 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 is 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
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. 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
-12-
risks associated with exploring, drilling, producing,
gathering and transporting natural gas, their risks also
increase our exposure to supply and price fluctuations. We
will likely be engaging in hedging activity in the future 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 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 investments. We have investments in
unregulated retail energy marketing services, non-utility
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. During the quarter ended January 31, 2002, outstanding
short-term borrowings under bank lines of credit totaling $150 million ranged
from $10 million to $57 million, with an average interest rate of 2.43%. 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 increasing short-term borrowings to meet
current cash requirements. The level of short-term borrowings can vary
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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. 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 increased from October 31, 2001,
to January 31, 2002. Accounts payable and accounts receivable increased from
October 31, 2001, to January 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 January 31, 2002, were $18.2 million, compared with $28.8
million for the same period in 2001. Utility construction expenditures for the
twelve-month period ended January 31, 2002, were $79.7 million, compared with
$116.8 million for the same period in 2001.
At January 31, 2002, our capitalization consisted of 46% in long-term debt and
54% in common equity.
Results of Operations
We will discuss the results of operations for the three months and twelve months
ended January 31, 2002, compared with similar periods in 2001.
Margin
Margin (operating revenues less cost of gas) for the three months ended January
31, 2002, decreased $5.4 million compared with the same period in 2001 primarily
due to a decrease in delivered volumes of natural gas, which we refer to as
system throughput, of 11.7 million dekatherms from the same period in 2001,
primarily due to 33% warmer weather.
Margin for the current three-month period includes $12.5 million from the
weather normalization adjustment (WNA) due to weather that was 23% 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 $14.4 million from the WNA due to weather that
was 16% colder than normal.
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Margin for the twelve months ended January 31, 2002, increased $2.7 million
compared with the same period in 2001 primarily for the reasons listed below.
- Rates charged to customers increased due to general rate
increases in Tennessee effective July 1, 2000, and in North
Carolina effective November 1, 2000.
- Other revenues increased, largely due to revenues from late
payments and miscellaneous service work.
- Margin includes $18.4 million from the WNA, compared with WNA
refunds of $7.7 million for the same period in 2001. Weather
was 13% warmer than normal during the twelve-month period.
System throughput decreased 21.4 million dekatherms for the twelve months ended
January 31, 2002, compared with the same period in 2001, primarily due to
weather that was 15% warmer than the same period in 2001.
Under gas cost recovery mechanisms in all three states, 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 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 condensed consolidated financial statements. In North Carolina and South
Carolina, recovery of gas costs is subject to a finding made in 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 January 31, 2002,
decreased $854,000 compared with the same period in 2001 primarily for the
reasons listed below.
- Decrease in utilities expense due primarily to the decreased
volume of telephone calls to our customer information centers
and new contracts being signed with major vendors.
- Decrease in the provision for uncollectibles.
An increase in advertising expenses partially offset these decreases for the
three months ended January 31, 2002, compared with the same period in 2001.
Operations and maintenance expenses for the twelve months ended January 31,
2002, increased $1.7 million compared with the same period in 2001 primarily for
the reasons listed below.
- Increase in bank charges for activity fees and for fees
associated with higher committed bank lines.
- Increase in the provision for uncollectibles.
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- Increase in risk insurance expense due primarily to workers'
compensation.
- Increase in advertising expenses.
These increases were partially offset by the following decreases.
- Decrease in payroll expense due to a decrease in long-term
incentive plan accruals.
- Decrease in employee benefits expense due primarily to a
decrease in pension expense and the shift of the payment of
administrative fees from benefit plan assets rather than by
the sponsor and to a decrease in the cost of postretirement
health care and life insurance benefits.
General Taxes
General taxes for the three months ended January 31, 2002, decreased $351,000
compared with the same period in 2001 primarily due to a decrease in property
taxes.
General taxes for the twelve months ended January 31, 2002, increased $4.3
million compared with the same period in 2001 primarily due to an increase in
property taxes.
Other Income
Income from equity investee earnings for the three months and twelve months
ended January 31, 2002, decreased $5.7 million and $5.6 million, respectively,
compared with the same periods in 2001 primarily due to decreases in earnings
from unregulated retail energy marketing services and propane due to warmer
weather.
Other income for the twelve months ended January 31, 2002, decreased $4.6
million compared with the same period in 2001 primarily due to a gain of $5.1
million in August 2000 from the contribution of substantially all of our propane
assets in exchange for an interest in Heritage Propane Partners.
Utility Interest Charges
Utility interest charges for the three months ended January 31, 2002, increased
$478,000 compared with the same period in 2001 primarily due to a decrease in
the portion of the allowance for funds used during construction (AFUDC)
attributable to borrowed funds, partially offset by a decrease in interest on
short-term debt due to lower balances outstanding at lower interest rates.
Utility interest charges for the twelve months ended January 31, 2002, increased
$1.5 million compared with the same period in 2001 primarily for the reasons
listed below.
- Increase in interest on long-term debt from higher amounts of
debt outstanding.
- Increase in interest on refunds due customers from larger
balances outstanding.
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These increases were partially offset by the following decreases.
- Decrease in the portion of the AFUDC attributable to borrowed
funds.
- Decrease in interest on short-term debt due to lower balances
outstanding at lower interest rates.
-17-
Item 3. Quantitative and Qualitative Disclosures about Market Risk
All financial instruments discussed below are held by us 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 January 31, 2002, we had $33 million of short-term debt outstanding with a
weighted average interest rate of 2.22%. We borrow primarily highly liquid debt
instruments of a short-term nature and the carrying amount of such debt
approximates fair value.
The table below provides information about our long-term debt at January 31,
2002, that is sensitive to changes in interest rates.
Expected Maturity Date
---------------------- Fair Value
There- at January 31,
2002 2003 2004 2005 2006 after Total 2002
----- ---- ----- ---- ---- ------ ----- ---------------
Fixed Rate
Long-term Debt
(in millions) $ 2 $ 47 $ 2 -- $ 35 $425 $511 $541
Average Interest
Rate 10.06% 6.39% 10.06% -- 9.44% 7.55% 7.60%
Commodity Price Risk
In the normal course of business, we utilize contracts of various duration for
the forward sales and purchase of natural gas. We manage our gas supply costs
through a portfolio of short- and long-term procurement contracts with various
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 13.
-18-
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
We held our Annual Meeting of Shareholders on February 22, 2002, to elect six
directors and to ratify the selection of independent auditors. The record date
for determining the shareholders entitled to receive notice of and to vote at
the meeting was January 10, 2002. We solicited proxies for the meeting according
to section 14(a) of the Securities and Exchange Act of 1934. There was no
solicitation in opposition to management's solicitations.
Shareholders elected all of management's nominees for director as listed in the
proxy statement by the following votes:
Shares Shares Shares
Voted Voted NOT
FOR WITHHELD VOTED
---------- --------- ---------
For term expiring in 2003:
Ned R. McWherter 27,370,371 321,462 4,861,628
For term expiring in 2004:
Thomas E. Skains 27,399,346 292,487 4,861,628
For terms expiring in 2005:
Malcolm E. Everett III 27,377,916 313,917 4,861,628
Muriel W. Helms 27,392,511 299,322 4,861,628
Donald S. Russell 24,624,121 3,067,712 4,861,628
John E. Simkins 27,380,814 311,019 4,861,628
Directors C. M. Butler III, John W. Harris and Ware F. Schiefer will continue in
office until 2003. Directors Jerry W. Amos, D. Hayes Clement and John H. Maxheim
will continue in office until 2004.
Shareholders approved the selection by the Board of Directors of the firm of
Deloitte & Touche LLP as independent auditors for the fiscal year ending October
31, 2002, by the following vote:
Shares Shares Shares Shares
Voted Voted Voted NOT
FOR AGAINST ABSTAINING VOTED
---------- ------- ---------- ---------
27,376,100 185,378 130,355 4,861,628
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Item 5. Other Information
Expansion Fund
As previously reported, the NCUC established an expansion fund consisting of
supplier refunds due customers to be used to extend natural gas service into
unserved areas of the state. The NCUC decides the use of these funds as we file
individual project applications for unserved areas. Through October 31, 2001, we
received $38.5 million from the expansion fund to extend natural gas service to
the counties of Avery, Mitchell and Yancey. At January 31, 2002, the North
Carolina State Treasurer held $5.7 million in our expansion fund account. This
amount along with other supplier refunds, including interest earned to date, is
included in restricted cash in the consolidated balance sheet at January 31,
2002.
On January 8, 2002, we filed a petition with the NCUC requesting permission to
deposit supplier refunds currently held by us and future pipeline supplier
refunds in the appropriate gas costs deferred accounts for refund to customers.
On February 21, the NCUC concluded that the petition should be allowed. The
demand-related portion of the supplier refunds will go into the all-customer
deferred account and the commodity-related portion will go into the sales-only
deferred account.
Regulatory Proceedings
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 by us in connection with the implementation and
administration of the hedging program. A hearing on this matter is set for March
21. We are unable to determine the outcome of this proceeding at this time.
In a generic proceeding, the NCUC, on February 26, 2002, issued an order 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. We are unable to determine
whether we will develop and implement a hedging plan acceptable for use in our
North Carolina operations at this time.
We have filed notices of intention to file a general rate application and a
petition for a general rate increase with the NCUC and the PSCSC. The amounts of
the requested rate increases and other issues in the applications have not yet
been determined.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits -
3.1 By-Laws of the Company, as amended, dated February 22, 2002.
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12 Computation of Ratio of Earnings to Fixed Charges.
(b) Reports on Form 8-K -
On December 21, 2001, we filed a report on Form 8-K reporting that we
issued a press release on December 13, 2001, to announce that the Board
of Directors had elected Thomas E. Skains President and Chief Operating
Officer effective at the Annual Meeting of Shareholders on February 22,
2002. Mr. Skains was also nominated to stand for election to the Board
at the Annual Meeting.
Subsequent to the quarter end, on February 15, 2002, we filed a report
on Form 8-K reporting that we issued a press release on February 14,
2002, stating that the earnings for the first quarter ended January 31,
2002, were expected to be in the range of $1.25 to $1.30 per share
diluted and between $1.90 and $2.00 per share for the fiscal year
ending October 31, 2002. Our prior earnings guidance was between $2.10
and $2.20 per share for the fiscal year.
Subsequent to the quarter end, on February 28, 2002, we filed a report
on Form 8-K reporting that Franklin H. Yoho would be joining Piedmont
as Senior Vice President - Marketing and Supply Services effective
March 18, 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 March 13, 2002 /s/ David J. Dzuricky
--------------- -------------------------------------------------
David J. Dzuricky
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
Date March 13, 2002 /s/ Barry L. Guy
--------------- -------------------------------------------------
Barry L.Guy
Vice President and Controller
(Principal Accounting Officer)
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Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended January 31, 2002
Exhibits
3.1 By-Laws of the Company, as amended, dated February 22, 2002.
12 Computation of Ratio of Earnings to Fixed Charges.