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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, 2001
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 September 7, 2001
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Common Stock, no par value 32,351,689
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Item 1. Financial Statements
PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(in thousands)
--------------------------------------------------------
July 31, October 31,
2001 2000
Unaudited Audited
---------- ----------
ASSETS
Utility Plant, at original cost $1,607,295 $1,533,962
Less accumulated depreciation 499,842 462,955
---------- ----------
Utility plant, net 1,107,453 1,071,007
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Other Physical Property (net of accumulated
depreciation of $1,300 in 2001 and $1,187 in 2000) 1,107 976
---------- ----------
Current Assets:
Cash and cash equivalents 4,308 8,747
Restricted cash 17,142 39,796
Receivables (less allowance for doubtful
accounts of $597 in 2001 and $482 in 2000) 42,819 55,145
Gas in storage 52,583 67,709
Deferred cost of gas 14,037 13,228
Deferred income taxes 15,695 --
Refundable income taxes 708 69,118
Prepayments and other 50,971 30,492
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Total current assets 198,263 284,235
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Deferred Charges and Other Assets 101,756 88,785
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Total $1,408,579 $1,445,003
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CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock $ 328,037 $ 314,230
Retained earnings 250,057 213,142
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Total common stock equity 578,094 527,372
Long-term debt 449,000 451,000
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Total capitalization 1,027,094 978,372
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Current Liabilities:
Current maturities of long-term debt and
sinking fund requirements 2,000 32,000
Notes payable 69,500 99,500
Accounts payable 43,782 87,604
Deferred income taxes -- 8,678
General taxes accrued 8,680 11,205
Refunds due customers 43,742 32,889
Other 14,622 25,121
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Total current liabilities 182,326 296,997
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Deferred Credits and Other Liabilities 199,159 169,634
---------- ----------
Total $1,408,579 $1,445,003
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See notes to condensed consolidated financial statements.
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Condensed Statements of Consolidated Income (Unaudited)
(in thousands except per share amounts)
------------------------------------------------------
Three Months Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
------------------------- ---------------------- ------------------------
2001 2000 2001 2000 2001 2000
--------- --------- -------- -------- ---------- --------
Operating Revenues $ 121,779 $ 131,211 $997,364 $682,814 $1,144,927 $777,568
Cost of Gas 78,142 87,740 705,495 407,107 810,434 461,107
--------- --------- -------- -------- ---------- --------
Margin 43,637 43,471 291,869 275,707 334,493 316,461
--------- --------- -------- -------- ---------- --------
Other Operating Expenses:
Operations 28,802 26,779 86,961 81,539 115,364 106,775
Maintenance 4,975 4,367 14,269 12,423 18,906 16,586
Depreciation 13,003 12,318 38,555 36,300 51,149 47,816
General taxes 5,289 4,428 16,441 14,328 20,873 19,277
Income taxes (7,516) (5,495) 41,733 40,701 34,594 35,330
--------- --------- -------- -------- ---------- --------
Total other operating expenses 44,553 42,397 197,959 185,291 240,886 225,784
--------- --------- -------- -------- ---------- --------
Operating Income (916) 1,074 93,910 90,416 93,607 90,677
Other Income, Net (6,353) (2,087) 8,301 8,448 11,767 7,711
--------- --------- -------- -------- ---------- --------
Income Before Utility Interest Charges (7,269) (1,013) 102,211 98,864 105,374 98,388
Utility Interest Charges 9,536 9,233 28,845 27,580 39,261 35,912
--------- --------- -------- -------- ---------- --------
Net Income ($ 16,805) ($ 10,246) $ 73,366 $ 71,284 $ 66,113 $ 62,476
========= ========= ======== ======== ========== ========
Average Shares of Common Stock:
Basic 32,243 31,676 32,119 31,528 32,043 31,446
Diluted 32,243 31,676 32,360 31,707 32,299 31,638
Earnings Per Share of Common Stock:
Basic ($ 0.52) ($ 0.32) $ 2.28 $ 2.26 $ 2.06 $ 1.99
Diluted ($ 0.52) ($ 0.32) $ 2.27 $ 2.25 $ 2.05 $ 1.97
Cash Dividends Per Share
of Common Stock $ 0.385 $ 0.365 $ 1.135 $ 1.075 $ 1.50 $ 1.42
See notes to condensed consolidated financial statements.
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PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Condensed Statements of Consolidated Cash Flows (Unaudited)
(in thousands)
-----------------------------------------------------------
Three Months Nine Months Twelve Months
Ended Ended Ended
July 31 July 31 July 31
--------------------- ---------------------- -----------------------
2001 2000 2001 2000 2001 2000
-------- -------- --------- -------- --------- ---------
Cash Flows from Operating Activities:
Net income ($16,805) ($10,246) $ 73,366 $ 71,284 $ 66,113 $ 62,476
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization 13,215 13,255 39,376 39,160 52,306 51,392
Other, net 17,889 2,741 8,651 2,389 31,320 3,631
Net gain on propane business combination, net
of tax -- -- -- -- (5,063) --
Change in operating assets and liabilities 4,251 (76,995) 32,370 (71,668) 22,571 (110,232)
-------- -------- --------- -------- --------- ---------
Net cash provided by (used in) operating activities 18,550 (71,245) 153,763 41,165 167,247 7,267
-------- -------- --------- -------- --------- ---------
Cash Flows from Investing Activities:
Utility construction expenditures (23,895) (25,118) (64,417) (66,049) (103,697) (94,767)
Investment in propane partnership -- -- -- -- (30,552) --
Proceeds from propane business combination -- -- -- -- 36,748 --
Other (197) (275) (6,888) (870) (6,928) (1,386)
-------- -------- --------- -------- --------- ---------
Net cash used in investing activities (24,092) (25,393) (71,305) (66,919) (104,429) (96,153)
-------- -------- --------- -------- --------- ---------
Cash Flows from Financing Activities:
Increase (decrease) in bank loans, net 35,515 97,000 (30,000) 47,500 (57,500) 68,000
Issuance of long-term debt -- -- -- -- 60,000 90,000
Retirement of long-term debt (32,000) (2,000) (32,000) (2,000) (32,000) (46,000)
Issuance of common stock through dividend
reinvestment and employee stock plans 4,137 3,783 11,555 11,712 15,296 15,575
Dividends paid (12,407) (11,555) (36,452) (33,880) (48,058) (44,642)
-------- -------- --------- -------- --------- ---------
Net cash provided by (used in) financing activities (4,755) 87,228 (86,897) 23,332 (62,262) 82,933
-------- -------- --------- -------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (10,297) (9,410) (4,439) (2,422) 556 (5,953)
Cash and Cash Equivalents at Beginning of Period 14,605 13,162 8,747 6,174 3,752 9,705
-------- -------- --------- -------- --------- ---------
Cash and Cash Equivalents at End of Period $ 4,308 $ 3,752 $ 4,308 $ 3,752 $ 4,308 $ 3,752
======== ======== ========= ======== ========= =========
Cash Paid During the Period for:
Interest $ 17,206 $ 14,878 $ 36,834 $ 31,374 $ 40,431 $ 36,580
Income taxes $ -- $ 34,062 $ 48,745 $ 85,658 $ 48,936 $ 85,899
See notes to condensed consolidated financial statements.
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PIEDMONT NATURAL GAS COMPANY, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements (Unaudited)
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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 2000 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, 2001, and October 31, 2000, and the
results of operations and cash flows for the three months, nine months
and twelve months ended July 31, 2001 and 2000.
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. See Note 7 concerning a change in estimate for one of
our equity investees.
3. Our business is seasonal in nature. The results of operations for the
three-month and nine-month periods ended July 31, 2001, 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)
2001 2000 2001 2000 2001 2000
-------- -------- ------- ------- ------- -------
Net Income $(16,805) $(10,246) $73,366 $71,284 $66,113 $62,476
======== ======== ======= ======= ======= =======
Average shares of common stock
outstanding for basic earnings per share 32,243 31,676 32,119 31,528 32,043 31,446
Contingently issuable shares under
the long-term incentive plan -- -- 241 179 256 192
-------- -------- ------- ------- ------- -------
Average shares of dilutive stock 32,243 31,676 32,360 31,707 32,299 31,638
======== ======== ======= ======= ======= =======
Earnings Per Share:
Basic $ (.52) $ (.32) $ 2.28 $ 2.26 $ 2.06 $ 1.99
Diluted $ (.52) $ (.32) $ 2.27 $ 2.25 $ 2.05 $ 1.97
(a) For the three months ended July 31, 2001 and 2000, the inclusion of 231
and 178 contingently issuable shares, respectively, would be
antidilutive.
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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 limited liability companies of which two wholly owned
subsidiaries of our wholly owned subsidiary, Piedmont Energy Partners,
are members. Operations of our retail energy marketing services segment
are conducted by a limited liability company of which a wholly owned
subsidiary of Piedmont Energy Partners is a member. Our activities
included in Other in the segment tables consist primarily of propane
operations conducted by a master limited partnership of which a wholly
owned subsidiary of Piedmont Energy Partners has an equity interest. All
of our activities other than the utility operations of the parent are
included in other income in the consolidated income statement.
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, 2000.
Continuing operations by segment for the three months and nine months
ended July 31, 2001 and 2000, are presented below:
Domestic Retail
Natural Gas Energy
Distribution Marketing Other Total
---------------------- ------------------- ------------------- ----------------------
(in thousands)
Three Months Ended July 31 2001 2000 2001 2000 2001 2000 2001 2000
- -------------------------- --------- --------- -------- ------- ------- -------- --------- ---------
Revenues from external customers $ 121,779 $ 131,211 $ -- $ -- $ -- $ 3,510 $ 121,779 $ 134,721
Margin 43,637 43,471 -- -- -- 453 43,637 43,924
Operations and maintenance
expenses 33,777 31,146 7 -- 3 2,574 33,787 33,720
Operating income (929) 1,075 (8) (2) 656 (2,856) (281) (1,783)
Other income 1,570 1,932 (10,286) (2,988) (1,764) (87) (10,480) (1,143)
Income before income taxes (16,404) (11,714) (10,334) (2,467) (1,739) (2,919) (28,477) (17,100)
Capital expenditures 25,434 25,860 -- -- -- 247 25,434 26,107
Nine Months Ended July 31
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Revenues from external customers $ 997,364 $ 682,814 $ -- $ -- $ -- $ 29,968 $ 997,364 $ 712,782
Margin 291,869 275,707 -- -- (264) 11,534 291,605 287,241
Operations and maintenance
expenses 101,230 93,964 9 2 566 7,810 101,805 101,776
Operating income 93,887 90,390 (7) (21) (816) 1,472 93,064 91,841
Other income 5,281 5,816 8,152 5,716 1,552 (52) 14,985 11,480
Income before income taxes 112,082 109,350 7,699 6,883 750 1,298 120,531 117,531
Capital expenditures 69,543 68,781 -- -- -- 755 69,543 69,536
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A reconciliation of net income in the consolidated financial statements
for the three months and nine months ended July 31, 2001 and 2000, is
presented below:
Three Months Nine Months
Ended July 31 Ended July 31
------------------------ -----------------------
2001 2000 2001 2000
-------- -------- -------- --------
(in thousands)
Income before income taxes for reportable segments $(26,738) $(14,181) $119,781 $116,233
Income before income taxes for other non-utility activities (1,739) (2,919) 750 1,298
Income taxes (11,672) (6,854) 47,165 46,247
-------- -------- -------- --------
Net income $(16,805) $(10,246) $ 73,366 $ 71,284
======== ======== ======== ========
A reconciliation of consolidated assets in the consolidated financial
statements as of July 31, 2001 and October 31, 2000, is presented below:
2001 2000
----------- -----------
(in thousands)
Domestic natural gas operations $ 1,402,203 $ 1,437,950
Retail energy marketing services 25,008 9,055
Other 26,871 34,959
Eliminations/Adjustments (45,503) (36,961)
----------- -----------
Consolidated assets $ 1,408,579 $ 1,445,003
=========== ===========
6. Derivatives and Hedging Activities
Effective November 1, 2000, we adopted Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities," and SFAS No. 138, "Accounting for Certain Derivative
Instruments and Hedging Activities." Implementation did not have a
material impact on our financial condition or results of operations.
We purchase natural gas for our regulated operations. We purchase gas
primarily 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 ratepayer. Our risk management policies allow us to
use financial instruments for trading purposes and to hedge risks;
however, currently, we do not engage in such activities.
In the nine months ended July 31, 2001, we purchased financial call
options for natural gas for delivery in January 2002 for our Tennessee
gas purchase portfolio. The cost of these options and all gas costs
incurred become a component 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 $1.6 million
for shareholder gains or losses.
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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 ratepayers and shareholders. This amount is subject to the $1.6
million cap and the shareholders' portion is placed in a regulatory asset
to be surcharged or refunded to ratepayers.
Currently, the options are marked to their fair value at the end of each
month. The estimated shareholders' portion of the fair value subject to
sharing is included in other gas revenues.
7. Subsequent Events
On August 27, 2001, SouthStar Energy Services LLC, of which we own a 30%
interest and account for under equity accounting, reported that its net
income was overstated due to the manner in which SouthStar estimated the
amount of lost and unaccounted for gas in computing unbilled revenues. We
previously reported on a Form 8-K filed August 27, 2001, that the
adjustment may relate to prior fiscal years. Subsequently, additional
information became available from SouthStar to indicate that material
amounts did not relate to prior fiscal years. SouthStar has recorded the
adjustment as a change in estimate. Our portion of the adjustment, $5
million net of tax, was recorded as a reduction in other income for the
quarter ended July 31, 2001. 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.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Forward-Looking Statements
This document and other documents filed by us with the Securities and Exchange
Commission (SEC) contain forward-looking statements. In addition, our senior
management may make forward-looking statements orally to analysts, investors,
the media and others. Our discussion contains forward-looking statements
concerning, among others, plans, objectives, proposed capital expenditures and
future events or performance. Our statements reflect our current expectations
and involve a number of risks and uncertainties. Although we believe that our
expectations are based on reasonable assumptions, actual results may differ
materially from those suggested by the forward-looking statements. Important
factors that could cause actual results to differ include:
o Regulatory issues, including those that affect allowed rates
of return, rate structure and financings. In addition to the
impact of our three state regulatory commissions, we purchase
natural gas transportation and storage services from
interstate pipeline companies whose rates and services are
regulated by the Federal Energy Regulatory Commission (FERC).
o Residential, commercial and industrial growth in our service
territories. Our ability to grow our customer base 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.
o Deregulation, unanticipated impacts of restructuring and
increased competition in the energy industry. We face strong
competition from electric companies and energy marketing and
trading companies. As a result of continued deregulation, we
expect this highly competitive environment to continue.
o The potential loss of large-volume industrial customers due to
bypass or the shift by such customers to special competitive
contracts at lower per-unit margins.
o The ability to meet internal performance goals. Regulatory
issues, customer growth, deregulation, economic and capital
market conditions, the price and availability of natural gas
and weather conditions can impact internal performance goals.
o The capital-intensive nature of our business, including
development project delays or changes in project costs.
Weather and business delays, general economic conditions and
the cost of funds to finance our capital projects can
materially increase the cost of a project.
o Changes in the availability and price of natural gas. To meet
customer requirements, we must acquire sufficient gas supplies
and pipeline capacity to ensure delivery to our distribution
system while also ensuring that our supply and capacity
contracts will allow us to remain competitive. We have a
diversified portfolio of local peaking facilities,
transportation and storage contracts with interstate pipelines
and supply contracts with major producers and marketers to
satisfy the supply and deliverability requirements of our
customers. Because these pipelines and producers are subject
to
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risks associated with the drilling and exploration for natural
gas, their risks also increase our exposure to supply and
price availability.
o Changes in demographic patterns and weather conditions.
Weather conditions and other natural phenomena can have a
large impact on our earnings. Severe weather conditions can
impact the pipelines that transport gas to our city gate.
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.
o Changes in environmental requirements and cost of compliance.
o Earnings of our equity investments. We have investments in
unregulated retail energy marketing services, non-utility
interstate LNG operations, intrastate pipeline operations and
propane. These companies have risks that are inherent to their
industries. As an equity investor, we assume the risks of
these companies in proportion to our investment interest.
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," "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 our regulation and supervision 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, including those above, 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
We finance current cash requirements primarily from operating cash flows and
short-term borrowings. Outstanding short-term borrowings under bank lines of
credit ranged from zero to $69.5 million during the quarter ended July 31, 2001,
and from zero to $148.5 million during the nine months ended July 31, 2001. The
level of short-term borrowings can vary significantly over the year due to
changes in the wholesale prices for natural gas that we 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 our customers through their
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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 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. Most of our annual earnings are realized in the winter period,
which is the first five months of our fiscal year. Due to increased wholesale
gas costs, our accounts receivable have been higher than historical levels
during the nine months ended July 31, 2001, as such gas costs are passed through
to customers under purchased gas adjustment (PGA) mechanisms. The balance in
accounts receivable is likely to remain at higher levels since some customers
may be slow to pay their gas bills that were higher than normal due to the
increased wholesale gas costs and colder-than-normal weather this past winter.
We may also incur more short-term debt to pay gas commodity and other bills if
collections from customers are significantly slower. Some customers have been
unable to pay their gas bills, thereby increasing our bad debt expense.
Write-offs of accounts receivable increased $3.1 million, $3.4 million and $3.7
million for the three months, nine months and twelve months ended July 31, 2001,
compared with similar periods ended July 31, 2000.
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, 2001, were $25.2 million, compared with $25.9
million for the same period in 2000. Utility construction expenditures for the
nine months ended July 31, 2001, were $69.3 million, compared with $68.8 million
for the same period in 2000. Utility construction expenditures for the
twelve-month period ended July 31, 2001, were $109.1 million, compared with
$98.1 million for the same period in 2000.
On June 4, 2001, we filed a combined debt and equity shelf registration
statement for $250 million of securities with the Securities and Exchange
Commission. The registration statement was declared effective on August 10.
Unless otherwise specified at the time such securities are offered for sale, the
net proceeds from the sale of the securities will be used for general corporate
purposes, including construction of additional facilities, the repayment of
short-term debt and working capital needs. Pending such use, we may temporarily
invest the net proceeds in investment grade securities.
We intend to issue $60 million of long-term debt in the fourth quarter of the
fiscal year under this shelf. Proceeds from the issuance will be used to reduce
short-term debt. Our pro forma capital structure after this activity would be
long-term debt of 47% and common equity of 53%.
At July 31, 2001, our capitalization consisted of 44% in long-term debt and 56%
in common equity.
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Results of Operations
We will discuss the results of operations for the three months, nine months and
twelve months ended July 31, 2001, compared with similar periods in 2000.
Margin
Margin (operating revenues less cost of gas) for the three months ended July 31,
2001, increased $166,000 compared with the same period in 2000 primarily for the
reasons listed below.
o Rates charged to customers were increased due to general rate
increases in Tennessee effective July 1, 2000, and in North
Carolina effective November 1, 2000.
o Secondary market wholesale transactions increased margin as
compared with the same period in 2000.
o Other revenues increased margin as compared with the same
period in 2000.
o The addition of Gaffney, South Carolina customers in January
2001 increased margin as compared with the same period in
2000.
o Increased customer growth contributed to the margin increase.
These increases in margin were almost fully offset by a net decrease of 5
million dekatherms of delivered volumes of natural gas, which we refer to as
system throughput, for the three months ended July 31, 2001, compared with the
same period in 2000. This decrease in throughput and associated margin was due
primarily to less demand from industrial customers, lower-priced competitive
fuels and mild summer weather that reduced natural gas used for electric
generation.
Margin for the nine months ended July 31, 2001, increased $16.2 million compared
with the same period in 2000 primarily for the reasons listed below.
o System throughput increased 589,000 dekatherms over the same
period in 2000, primarily due to customer growth and 22%
colder weather.
o Rates charged to customers increased due to general rate
increases as noted above.
o Secondary market wholesale transactions increased margin as
compared with the same period in 2000.
o The addition of Gaffney, South Carolina customers in January
2001 increased margin.
o Other revenues, such as late charges and reconnect fees,
increased.
Margin for the current nine-month period reflects weather normalization
adjustment (WNA) refunds of $8.5 million, compared with WNA charges of $19.3
million for the same period in 2000. The WNA is designed to offset the impact of
unusually cold or warm weather on customer billings and operating margin.
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Margin for the twelve months ended July 31, 2001, increased $18 million compared
with the same period in 2000 primarily for the reasons listed below.
o Even though system throughput decreased 884,000 dekatherms
from the same period in 2000, increased customer growth and
19% colder weather contributed to margin. Higher-margin
residential and commercial customers consumed 8 million more
dekatherms and 2.9 million more dekatherms, respectively, than
the same period in 2000.
o Rates charged to customers increased due to general rate
increases as noted above.
o Secondary market wholesale transactions increased margin as
compared with the same period in 2000.
o The addition of Gaffney, South Carolina customers in January
2001 increased margin.
o Other revenues, such as late charges and reconnect fees,
increased.
Margin for the current twelve-month period reflects WNA refunds of $8.5 million,
compared with WNA charges of $19.3 million for the same period in 2000.
Under PGA 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.
Operations and Maintenance Expenses
Operations and maintenance expenses for the three months ended July 31, 2001,
increased $2.6 million compared with the same period in 2000 primarily for the
reasons listed below.
o Increase in transportation costs,
o Increase in outside labor,
o Increase in utilities,
o Increase in rents and leases,
o Increase in the provision for uncollectibles,
o Increase in advertising and
o Increase in office supplies.
Decreases in payroll and employee benefits partially offset these increases for
the three months ended July 31, 2001, compared with the same period in 2000.
Operations and maintenance expenses for the nine months ended July 31, 2001,
increased $7.3 million compared with the same period in 2000 primarily for the
reasons listed below.
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o Increase in payroll,
o Increase in materials,
o Increase in transportation costs,
o Increase in utilities,
o Increase in outside labor,
o Increase in the provision for uncollectibles,
o Increase in regulatory expenses,
o Increase in other corporate expenses and
o Increase in outside consultants fees.
A decrease in employee benefits partially offset these increases for the nine
months ended July 31, 2001, compared with the same period in 2000.
Operations and maintenance expenses for the twelve months ended July 31, 2001,
increased $10.9 million compared with the same period in 2000 primarily for the
reasons listed below.
o Increase in payroll,
o Increase in utilities,
o Increase in rents and leases,
o Increase in the provision for uncollectibles,
o Increase in risk insurance,
o Increase in advertising expense,
o Increase in outside consultants fees and
o Increase in employee benefits.
A decrease in outside labor expense partially offset these increases for the
twelve months ended July 31, 2001, compared with the same period in 2000.
General Taxes
General taxes for the three months, nine months and twelve months ended July 31,
2001, increased $861,000, $2.1 million and $1.6 million, respectively, compared
with the same period in 2000 primarily for the reasons listed below.
o Increase in property taxes and
o Increase in payroll taxes.
A decrease in franchise taxes partially offset these increases in all periods
ended July 31, 2001, compared with the same periods in 2000.
Other Income
Other income for the three months ended July 31, 2001, decreased $4.3 million,
compared with
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the same period in 2000 primarily for the reasons listed below.
o Decrease in earnings from unregulated retail energy marketing
services, primarily due to the adjustment discussed in Note 7
to the financial statements, and
o Decrease in the portion of the allowance for funds used during
construction (AFUDC) attributable to equity funds.
An increase in earnings from propane operations partially offset these decreases
for the three months ended July 31, 2001, compared with the same period in 2000.
Other income for the nine months ended July 31, 2001, decreased $147,000
compared with the same period in 2000 primarily for the reasons listed below.
o Decreases in earnings from jobbing operations and
o Decrease in the portion of the AFUDC attributable to equity
funds.
These decreases were partially offset by the following increases.
o Increase in earnings from unregulated retail energy marketing
services and
o Increase in earnings from non-utility interstate LNG
operations.
Other income for the twelve months ended July 31, 2001, increased $4.1 million
compared with the same period in 2000 primarily for the reasons listed below.
o Increase in earnings from non-utility interstate LNG
operations,
o Increase in earnings from intrastate pipeline operations and
o Gain on sale of propane assets in connection with a business
combination in August 2000.
These increases in other income were partially offset by a decrease in the
portion of the AFUDC attributable to equity funds and a decrease in earnings
from jobbing operations.
Utility Interest Charges
Utility interest charges for the three months ended July 31, 2001, increased
$303,000 compared with the same period in 2000 primarily for the reasons listed
below.
o Increase in interest on long-term debt from higher amounts of
debt outstanding and
o Increase in interest on refunds due customers from larger
balances outstanding in the current period.
These increases were partially offset by the following decreases.
o Decrease in interest on short-term debt due to lower amounts
of debt outstanding at
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lower interest rates and
o Increase in the portion of the AFUDC attributable to borrowed
funds.
Utility interest charges for the nine months and twelve months ended July 31,
2001, increased $1.3 million and $3.3 million, respectively, compared with the
same periods in 2000 primarily for the reasons listed below.
o Increase in interest on long-term debt from higher amounts of
debt outstanding,
o Increase in interest on short-term debt due to higher amounts
of debt outstanding over time at slightly higher interest
rates and
o Increase in interest on refunds due customers from larger
balances outstanding in the current periods.
These increases in utility interest charges were partially offset by an increase
in the portion of the AFUDC attributable to borrowed funds.
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PART II. OTHER INFORMATION
Item 5. Other Information
Expansion Fund
As previously reported, the North Carolina Utilities Commission (NCUC) has
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. The NCUC has authorized us to use $38.5 million of the expansion
funds to extend natural gas service to the counties of Avery, Mitchell and
Yancey, of which $26.6 million has been used as of July 31, 2001. The total cost
of the project is estimated to be $44.2 million. As of July 31, 2001, the North
Carolina State Treasurer held $17.3 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 condensed consolidated balance sheet as of
July 31, 2001.
Greenbrier Pipeline Company, LLC
We have entered into a new equity venture, Greenbrier Pipeline Company, LLC,
with Dominion Resources which is proposing to build a 263-mile interstate
pipeline linking multiple gas supply basins and storage to growing demand in
residential, commercial, industrial and power generation markets in the
Southeast. Through a subsidiary, we will own a 33% equity interest and a
subsidiary of Dominion will own the remaining 67%. The pipeline will originate
in Kanawha County, West Virginia, with connections to Dominion Transmission and
Tennessee Gas Pipeline, and extend through southwest Virginia into Granville
County, North Carolina. The pipeline will cost $497 million, will be project
financed by the owners and will be designed, constructed and operated by
Dominion Transmission. Initial capacity will be 600,000 dekatherms of natural
gas per day. A segment of the pipeline is expected to be in service by the
second quarter of 2005 with the remainder to be completed by the fourth quarter
of 2005. A certificate application will be filed with the Federal Energy
Regulatory Commission in the first quarter of 2002.
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 -
We filed no reports on Form 8-K during the quarter ended July 31, 2001;
however, we have filed the following reports subsequent to quarter end.
On August 2, 2001, we filed a report on Form 8-K reporting that we
issued a press release on July 30, 2001, concerning a lawsuit filed by
an affiliate of AGL Resources against Dynegy Marketing and Trade. The
lawsuit purports to be "a derivative complaint on behalf of
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SouthStar Energy Services LLC." Our subsidiary is a 30% owner of
SouthStar along with affiliates of AGL Resources and Dynegy.
On August 7, 2001, we filed a report on Form 8-K reporting a downward
revision of our earnings estimates for the three months ending July 31,
2001, and for the fiscal years ending October 31, 2001 and 2002.
On August 27, 2001, we filed a report on Form 8-K reporting that we
issued a press release on that date concerning SouthStar Energy
Services LLC, of which we own a 30% interest. SouthStar's management
reported that their net income was overstated due to the manner in
which SouthStar estimated unbilled revenues.
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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 14, 2001 /s/ David J. Dzuricky
------------------ ------------------------------------------------
David J. Dzuricky
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
Date September 14, 2001 /s/ Barry L. Guy
------------------ ------------------------------------------------
Barry L. Guy
Vice President and Controller
(Principal Accounting Officer)
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