Piedmont Natural Gas (PNY) 10-Q 2006 Q0 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended January 31, 2006

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from                                        to                                        

Commission file number1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

North Carolina	56-0556998
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

4720 Piedmont Row Drive, Charlotte, North Carolina	28210
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code(704) 364-3120

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 þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check One):

Large Accelerated Filer  þ           Accelerated Filer  o           Non-accelerated Filer  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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 3, 2006
Common Stock, no par value	76,337,750

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
(In thousands)

	January 31,			October 31,
	2006			2005
ASSETS
Utility Plant, at original cost	$	2,657,415		$	2,611,577
Less accumulated depreciation		687,764			672,502
Utility plant, net		1,969,651			1,939,075
Other Physical Property (net of accumulated depreciation of $1,931 in 2006 and $1,888 in 2005)		732			731
Current Assets:
Cash and cash equivalents		29,597			7,065
Restricted cash		5			13,108
Receivables (less allowance for doubtful accounts of $4,153 in 2006 and $1,188 in 2005)		319,348			107,535
Income taxes receivable		—			21,570
Other receivables		4,319			12,102
Unbilled utility revenues		156,195			48,414
Gas in storage		188,751			151,865
Gas purchase options, at fair value		7,482			22,843
Amounts due from customers		27,924			52,161
Prepayments		13,598			62,821
Other		4,763			5,427
Total current assets		751,982			504,911
Investments, Deferred Charges and Other Assets:
Equity method investments in non-utility activities		79,030			71,520
Goodwill		47,383			47,383
Unamortized debt expense		4,713			4,822
Other		32,315			34,048
Total investments, deferred charges and other assets		163,441			157,773
Total	$	2,885,806		$	2,602,490
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Common stock, no par value, 100,000 shares authorized; outstanding, 76,677 in 2006 and 76,698 in 2005	$	562,243		$	562,880
Retained earnings		377,964			323,565
Accumulated other comprehensive income (loss)		(345	)		(2,253	)
Total stockholders’ equity		939,862			884,192
Long-term debt		625,000			625,000
Total capitalization		1,564,862			1,509,192
Current Liabilities:
Current maturities of long-term debt		35,000			35,000
Notes payable		350,000			158,500
Trade accounts payable		211,538			182,847
Other accounts payable		29,396			45,325
Income taxes accrued		16,492			6,201
Deferred income taxes		34,342			23,128
General taxes accrued		7,618			16,450
Amounts due to customers		19,786			17,124
Other		47,387			43,989
Total current liabilities		751,559			528,564
Deferred Credits and Other Liabilities:
Deferred income taxes		216,269			213,050
Unamortized federal investment tax credits		3,817			3,951
Regulatory cost of removal obligations		294,384			288,989
Other		54,915			58,744
Total deferred credits and other liabilities		569,385			564,734
Total	$	2,885,806		$	2,602,490

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
(In thousands except per share amounts)

	Three Months Ended
	January 31
	2006			2005
Operating Revenues	$	921,347		$	680,556
Cost of Gas		711,975			477,936
Margin		209,372			202,620
Operating Expenses:
Operations and maintenance		53,222			50,253
Depreciation		21,887			20,748
General taxes		8,710			8,441
Income taxes		44,392			44,259
Total operating expenses		128,211			123,701
Operating Income		81,161			78,919
Other Income (Expense):
Income from equity method investments		5,751			5,813
Allowance for equity funds used during construction		—			257
Non-operating income		19			415
Non-operating expense		(67	)		(104	)
Income taxes		(2,225	)		(2,317	)
Total other income (expense)		3,478			4,064
Utility Interest Charges		12,642			11,805
Income Before Minority Interest in Income of Consolidated Subsidiary		71,997			71,178
Less Minority Interest in Income (Loss) of Consolidated Subsidiary		—			(99	)
Net Income	$	71,997		$	71,277
Average Shares of Common Stock:
Basic		76,685			76,710
Diluted		76,928			76,925
Earnings Per Share of Common Stock:
Basic	$	0.94		$	0.93
Diluted	$	0.94		$	0.93
Cash Dividends Per Share of Common Stock	$	0.230		$	0.215

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
(In thousands)

	Three Months Ended
	January 31
	2006			2005
				(As Restated -
				See Note 13)
Cash Flows from Operating Activities:
Net income	$	71,997		$	71,277
Adjustments to reconcile net income to net cash used in operating activities:
Depreciation and amortization		22,885			22,064
Amortization of investment tax credits		(134	)		(138	)
Allowance for doubtful accounts		2,965			4,497
Allowance for funds used during construction		(634	)		(710	)
Earnings from equity method investments		(5,751	)		(5,813	)
Distributions of earnings from equity method investments		1,277			1,423
Deferred income taxes		13,219			45,745
Change in assets and liabilities		(224,663	)		(155,913	)
Net cash used in operating activities		(118,839	)		(17,568	)
Cash Flows from Investing Activities:
Utility construction expenditures		(51,102	)		(37,054	)
Reimbursements from bond fund		8,034			11,751
Contributions to equity method investments		—			(270	)
Decrease (increase) in restricted cash		13,103			(58	)
Other		(227	)		(386	)
Net cash used in investing activities		(30,192	)		(26,017	)
Cash Flows from Financing Activities:
Increase in notes payable		191,500			80,000
Issuance of common stock through dividend reinvestment and employee stock plans		4,916			6,396
Repurchases of common stock		(7,223	)		(6,524	)
Dividends paid		(17,630	)		(16,488	)
Net cash provided by financing activities		171,563			63,384
Net Increase in Cash and Cash Equivalents		22,532			19,799
Cash and Cash Equivalents at Beginning of Period		7,065			5,676
Cash and Cash Equivalents at End of Period	$	29,597		$	25,475
Noncash Investing and Financing Activities:
Utility construction expenditures	$	(4,316	)	$	(1,884	)

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
(In thousands)

	Three Months
	Ended January 31
	2006			2005
Net Income	$	71,997		$	71,277
Other Comprehensive Income:
Minimum pension liability adjustment, net of tax of ($1,778)		—			(2,748	)
Unrealized gain on marketable securities, net of tax of $220		—			348
Unrealized gain from hedging activities of equity method investments, net of tax of $1,424 in 2006 and $941 in 2005		2,241			1,499
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of ($211) in 2006 and ($217) in 2005		(333	)		(271	)
Total Comprehensive Income	$	73,905		$	70,105

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Unaudited)

1. The condensed consolidated financial statements have not been audited. These financial statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Form 10-K for the year ended October 31, 2005.

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, 2006 and October 31, 2005, and the results of operations and cash flows for the three months ended January 31, 2006 and 2005. Our business is seasonal in nature. The results of operations for the three months ended January 31, 2006, do not necessarily reflect the results to be expected for the full year.

We make estimates and assumptions when preparing the condensed consolidated financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

3. We follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (Statement 71). Statement 71 provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Statement 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods. The amounts recorded as regulatory assets in the condensed consolidated balance sheets as of January 31, 2006 and October 31, 2005, were $60.2 million and $85.8 million, respectively. The amounts recorded as regulatory liabilities in the condensed consolidated balance sheets as of January 31, 2006 and October 31, 2005, were $340.3 million and $333.3 million, respectively.

Significant inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with Statement 71. See Note 8 for information on related party transactions.

4. On November 3, 2005, the North Carolina Utilities Commission (NCUC) issued an order in a general rate case proceeding approving, among other things, an annual increase in margin of $20.2 million and authorizing new rates effective November 1, 2005. The order provided for the elimination of the weather normalization adjustment (WNA) mechanism in North Carolina and the establishment of a Customer Utilization Tracker (CUT). The CUT is experimental and can be effective for no more than three years, subject to review and approval in a future general rate case proceeding. The CUT provides for the recovery of our approved margin per customer independent of weather or other usage and consumption patterns of residential and commercial customers. The CUT tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection.

On January 3, 2006, the North Carolina Office of the Attorney General filed a notice of appeal in this rate proceeding challenging the lawfulness of the NCUC’s authorization and approval of the CUT. We believe the CUT is lawful, just and reasonable and reflects good public policy, and we intend to

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vigorously defend the NCUC’s action authorizing and approving the CUT. We are unable to predict the outcome of an appeal or the potential impact to our rates, charges or terms and conditions of service should the NCUC order be reversed or remanded.

5. Components of the net periodic benefit cost for our defined-benefit pension plans and our postretirement health care and life insurance benefits plan for the three months ended January 31, 2006 and 2005, are presented below.

	Pension Benefits						Other Benefits
In thousands	2006			2005			2006			2005
Service cost	$	3,149		$	2,312		$	409		$	311
Interest cost		3,971			2,628			629			480
Expected return on plan assets		(4,987	)		(3,402	)		(421	)		(230	)
Amortization of transition obligation		—			—			240			196
Amortization of prior-service cost		268			191			—			287
Amortization of actuarial (gain) loss		224			78			(82	)		—
Net periodic benefit cost	$	2,625		$	1,807		$	775		$	1,044

We estimate that we will contribute $15.3 million to the pension plans and $2.6 million to the other postretirement benefits plan in 2006.

6. We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the three months ended January 31, 2006 and 2005, is presented below.

In thousands except per share amounts	2006		2005
Net Income	$	71,997	$	71,277
Average shares of common stock outstanding for basic earnings per share		76,685		76,710
Contingently issuable shares under the Long- Term Incentive Plan		243		215
Average shares of dilutive stock		76,928		76,925
Earnings Per Share:
Basic	$	.94	$	.93
Diluted	$	.94	$	.93

7. We have two reportable business segments, regulated utility and non-utility activities. These segments were identified based on products and services, regulatory environments and our corporate organization and business decision-making activities. Operations of our regulated utility segment are conducted by the parent company. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures.

Operations of the regulated utility segment are reflected in operating income in the condensed consolidated statements of income. Operations of the non-utility activities segment are included in the condensed consolidated statements of income in “Income from equity method investments.”

We evaluate the performance of the regulated utility segment based on operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the

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consolidated financial statements for the year ended October 31, 2005.

Operations by segment for the three months ended January 31, 2006 and 2005, are presented below.

	Regulated				Non-utility
	Utility				Activities						Total
In thousands	2006		2005		2006			2005			2006		2005
Revenues from external customers	$	921,347	$	680,556	$	—		$	—		$	921,347	$	680,556
Operating income (loss)		125,553		123,178		(172	)		(134	)		125,381		123,044
Income from equity method investments		—		—		5,751			5,813			5,751		5,813
Income before income taxes and minority interest		113,141		112,146		5,473			5,608			118,614		117,754

Reconciliations to the condensed consolidated statements of income for the three months ended January 31, 2006 and 2005, are presented below.

In thousands	2006			2005
Operating Income:
Segment operating income	$	125,381		$	123,044
Utility income taxes		(44,392	)		(44,259	)
Non-utility activities		172			134
Operating income	$	81,161		$	78,919
Net Income:
Income before income taxes and minority interest for reportable segments	$	118,614		$	117,754
Income taxes		(46,617	)		(46,576	)
Less minority interest		—			99
Net income	$	71,997		$	71,277

8. The condensed consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in the condensed consolidated balance sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in the condensed consolidated statements of income.

We own 21.48% of the membership interests in Cardinal Pipeline Company, L.L.C., a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC. We have related party transactions as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. For the three months ended January 31, 2006 and 2005, these gas costs were $1.2 million. As of January 31, 2006 and October 31, 2005, we owed Cardinal $.4 million.

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC). We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For the three months ended January 31, 2006 and 2005, these gas costs were $3.2 million and $3.1 million, respectively. As of January 31, 2006 and October 31, 2005, we owed Pine Needle $1.1

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million.

We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. Under the terms of an amended and restated limited liability company operating agreement effective January 1, 2004, earnings and losses are allocated 25% to us and 75% to the other member. SouthStar sells natural gas to residential, commercial and industrial customers in the southeastern United States; however, SouthStar conducts most of its business in the unregulated retail gas market in Georgia. We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For the three months ended January 31, 2006 and 2005, these operating revenues were $8.6 million and $3.5 million, respectively. As of January 31, 2006 and October 31, 2005, SouthStar owed us $1.5 million and $.9 million, respectively.

9. We have purchased and sold financial options for natural gas in all three states for our gas purchase portfolios. The gains or losses on financial derivatives utilized in the regulated utility segment ultimately will be included in our rates to customers. Current period changes in the assets and liabilities from these risk management activities are recorded as a component of gas costs in amounts due customers in accordance with Statement 71. Accordingly, there is no earnings impact on the regulated utility segment as a result of the use of these financial derivatives. The fair value of gas purchase options decreased from $22.8 million as of October 31, 2005, to $7.5 million as of January 31, 2006, primarily due to options being exercised or options expiring during the period and being replaced with options having lower market values.

10. Prepayments decreased from $62.8 million as of October 31, 2005, to $13.6 million as of January 31, 2006, primarily due to a decrease in prepaid gas costs. Under asset management agreements, prepaid gas costs during the summer months represent purchases of gas that is not available for sale, and therefore not recorded in inventory, until November 1, the beginning of the winter period.

11. As of January 31, 2006, we had committed bank lines of credit totaling $250 million, for which we pay a maximum annual fee of $.3 million, and additional uncommitted lines of credit totaling $250 million on a no fee and as needed, if available basis. Outstanding short-term borrowings increased from $158.5 million as of October 31, 2005, to $350 million as of January 31, 2006, as cash flows during the period resulted in higher outstanding borrowings under our short-term lines of credit. Of the total amount outstanding as of January 31, 2006, $250 million was under the committed lines and $100 million was under the uncommitted lines. During the three months ended January 31, 2006, short-term borrowings ranged from $115 million to $378.5 million, and interest rates ranged from 4.07% to 4.89%.

12. In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), “Share-Based Payment” (Statement 123R). Statement 123R requires entities to adopt the fair value method of accounting for stock-based plans. The fair value method requires the amortization of the fair value of stock-based compensation as determined at the date of grant over the related vesting period. Under Statement 123R, most employee stock purchase plans that offer a discount of greater than 5% are considered compensatory. We adopted Statement 123R on November 1, 2005, and amended our employee stock purchase plan to lower the discount from 10% to 5%. The adoption of Statement 123R did not have any effect on our financial position, results of operations or cash flows.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), to clarify the term “conditional asset retirement” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” FIN 47 requires that a liability be recognized for the fair value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be

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reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Accordingly, we will adopt FIN 47 no later than our fourth fiscal quarter in 2006. We are currently assessing the impact FIN 47 may have on our consolidated balance sheet; however, we believe the adoption of FIN 47 will not have a material impact on our financial position, results of operations or cash flows.

13. Subsequent to the issuance of our condensed consolidated financial statements for the three months ended January 31, 2005, management identified errors in the condensed consolidated statement of cash flows relating to distributions of earnings received from equity method investees, changes in restricted cash and the amounts reported as construction expenditures. As a result, the accompanying condensed consolidated statement of cash flows for the three months ended January 31, 2005, has been restated from the amounts previously reported to correct the presentation of these items. The restatement did not affect previously reported operating income, net income, earnings per share or stockholders’ equity.

A summary of the significant effects of the restatement of the condensed consolidated statement of cash flows is as follows:

	As Previously
In thousands	Reported			As Restated
Cash flows from operating activities:
Distributions of earnings from equity method investments	$	—		$	1,423
Decrease (increase) in restricted cash		(58	)		—
Net cash used in operating activities		(20,933	)		(17,568	)
Cash flows from investing activities:
Distributions of capital from equity method investments		1,423			—
Decrease (increase) in restricted cash		—			(58	)
Net cash used in investing activities		(22,652	)		(26,017	)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion gives effect to the restatement of the condensed consolidated statement of cash flows discussed in Note 13 to the condensed consolidated financial statements.

Overview

Piedmont Natural Gas Company is an energy services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee. We also have equity method investments in joint venture, energy-related businesses. Our operations are comprised of two business segments.

The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. This segment is regulated by three state regulatory commissions that approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Factors critical to the success of the regulated utility include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in rates charged to customers.

The non-utility activities segment consists of our equity method investments in joint venture, energy-

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related businesses that are involved in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. We invest in joint ventures that are aligned with our business strategies to complement or supplement income from utility operations. We continually monitor performance of these ventures against expectations.

Weather conditions directly influence the volumes of natural gas delivered by the regulated utility. Significant portions of our revenues are generated during the winter season. During warm winters or unevenly cold winters, heating customers may significantly reduce their consumption of natural gas. Through October 31, 2005, we had weather normalization adjustment (WNA) mechanisms in all states that are designed to protect a portion of our revenues against warmer-than-normal weather, deviations from normal weather can affect our financial performance and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing the amounts we can charge our customers. In a general rate case proceeding during 2005, the NCUC ordered the establishment of a Customer Utilization Tracker (CUT) and the elimination of the WNA, effective November 1, 2005. For further information, see “Our Business” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Over the past few years, there have been significant increases in the wholesale cost of natural gas. The relationship between supply and demand has the greatest impact on wholesale gas prices. Increased prices of natural gas are being driven by increased demand that is exceeding the growth in available supply. The hurricanes in the Gulf Coast region in August and September 2005 severely impacted the natural gas production, processing and pipeline infrastructure. As a result of this disruption in supply and other supply and demand factors, wholesale gas prices increased dramatically which has significantly increased customers’ bills during the 2005-2006 heating season. There has been some moderation of natural gas prices in late 2005 and early 2006 but prices still remain high. Warmer-than-normal weather during this heating season mitigated the higher gas prices and decreased the usage of natural gas. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers; however, price increases could shift our customers’ preference away from natural gas toward other energy sources, particularly in the industrial market. Price increases could also affect the consumption levels of our customers or make it more difficult for them to pay their bills. We expect that the wholesale price of natural gas will remain high and volatile until natural gas supply and demand are in better balance.

We receive the majority of our natural gas supplies from the Gulf Coast region. We believe that diversification of our supply portfolio is in our customers’ best interest. We have a firm transportation contract pending for additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. The anticipated in-service date is November 2006. We have also executed an agreement with Hardy Storage Company for market-area storage capacity in West Virginia with an anticipated in-service date in 2007.

We have developed a comprehensive strategic communication plan to address the challenges facing our company and the natural gas industry. Our initiative emphasizes a partnership with our customers that is focused on reducing high energy bills through customer education, conservation measures and enrollment in our equal payment plan. We established a web site, NaturalGasAnswers.com, to help customers learn how to reduce the cost of heating their homes. An important part of the communication initiative is a grass-roots effort to seek customer support for proposed national energy policy solutions concerning access to additional domestic sources of supply, LNG imports, greater fuel diversity for the power-generation industry and increased Low Income Home Energy Assistance Program (LIHEAP) funding at the federal level. Our efforts have focused on informing our customers and the public about energy issues, encouraging our customers to advocate solutions to elected officials and reinforcing the value of

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our brand and the services we provide.

Although we have been operating in a relatively low-interest-rate environment for both short- and long-term debt financing during the past few years, the federal funds rate has steadily increased and is the highest it has been in over four years. We anticipate that interest rates will continue to rise, which could result in an increase in rates on our borrowings.

Part of our strategic plan is to manage our gas distribution business through sound rate and regulatory initiatives, control of our operating costs and implementation of new technologies. We are working to enhance the value and growth of our utility assets by good management of capital spending, both for improvements for current customers and the pursuit of customer growth opportunities in our service areas. We strive for quality customer service by investing in systems, processes and people. We will continue to work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.

Our strategic plan includes a focus on maintaining a debt-to-capitalization ratio within a range of 45 to 50%. We will continue to stress the importance of maintaining a strong balance sheet and investment-grade credit ratings to support our operating and investment needs. We continually monitor our level of short-term borrowings and secure short-term bank lines that meet our short-term operating needs.

Results of Operations

Operating Revenues

Operating revenues increased $240.8 million for the three months ended January 31, 2006, compared with the similar period in 2005 primarily due to the following increases:

• $261.3 million from increased commodity gas costs passed through to customers.

• $12.8 million from secondary market transactions, primarily due to increased commodity gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements.

• $15.5 million related to the impact of rate design changes in North Carolina and South Carolina effective November 1, 2005.

• $5.1 million net increase in North Carolina resulting from $13.4 million from the CUT mechanism compared with $8.3 million from the WNA for the similar prior period. For further discussion describing the evolution of the regulatory mechanisms effective November 1, 2005, see “Our Business” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

These increases were offset by a decrease of $64 million resulting from a decrease in volumes delivered of 5.6 million dekatherms, or an 8% decrease, primarily due to warmer weather and continued customer conservation.

Cost of Gas

Cost of gas increased $234 million for the three months ended January 31, 2006, compared with the similar period in 2005 primarily due to the following increases:

• $261.3 million from increased commodity gas costs.

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• $12.4 million from secondary market transactions.

These increases were partially offset by a decrease of $51.3 million resulting from a decrease in volumes delivered of 5.6 million dekatherms.

Under purchased gas adjustment (PGA) procedures 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 “Amounts due from customers” or “Amounts due to customers” in the condensed consolidated balance sheets.

In North Carolina and South Carolina, recoveries of gas costs are subject to annual gas cost recovery proceedings to determine the prudence of our gas purchases. We have been found prudent in all such past proceedings.

Margin

Margin increased $6.8 million for the three months ended January 31, 2006, compared with the similar period in 2005 primarily due to growth in the residential and commercial customer base and the impact of changes in rate design and regulatory mechanisms effective November 1, 2005, as noted above. These increases were offset by decreased consumption primarily due to warmer weather and continued customer conservation. Implementation of the CUT has partially mitigated both these factors in North Carolina.

Operations and Maintenance Expenses

Operations and maintenance expenses increased $3 million for the three months ended January 31, 2006, compared with the similar period in 2005 primarily due to the following increases:

• $.8 million in employee benefits expense primarily due to increases in pension costs, partially offset by decreases in postretirement health care and life insurance costs.

• $.8 million in rents and leases due to the new corporate office lease and telecommunications costs.

• $.6 million in outside labor for the customer service contact center and for the move to the new corporate office building.

• $.6 million in regulatory expense primarily due to fees to our state commissions that are based on revenues.

• $.5 million in payroll costs due to an increase in the costs associated with customer service and accrued long-term incentive plan liability.

• $.5 million in materials related to cancelled construction projects that were expensed.

These increases were partially offset by a decrease of $.8 million in the provision for uncollectibles. Effective November 1, 2005, the NCUC approved the recovery of all uncollected gas costs through the gas cost deferred account. As a result, only the portion of accounts written off relating to non-gas costs, or margin, is included in base rates and, accordingly, only this portion is included in the provision for uncollectibles expense. A similar mechanism has been in place, on an experimental basis, for our Tennessee operations since March 2004 whereby uncollected gas costs in excess of, or less than, those allowed in base rates are recovered from, or refunded to, customers through PGA procedures.

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Depreciation

Depreciation expense increased $1.1 million for the three months ended January 31, 2006, compared with the similar period in 2005 primarily due to increases in plant in service.

General taxes and other income (expense) were comparable from quarter to quarter.

Utility Interest Charges

Utility interest charges increased $.8 million for the three months ended January 31, 2006, compared with the similar period in 2005 primarily due to the following:

• $1.8 million increase in interest on short-term debt due to higher balances outstanding in the current period. See further discussion in “Financial Condition and Liquidity.”

• $.8 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in 2005.

Our Business

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company primarily engaged in the distribution of natural gas to 990,000 residential, commercial and industrial customers in portions of North Carolina, South Carolina and Tennessee, including 61,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation.

We continually assess the nature of our business and explore alternatives to traditional utility regulation. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional challenges and opportunities for us. We also regularly evaluate opportunities for obtaining natural gas supplies from different production regions and supply sources to maximize our natural gas portfolio flexibility and reliability, including the diversification of our supply portfolio through pipeline capacity arrangements that access new sources of supply and market-area storage and that diversify supply concentration away from the Gulf Coast region. We have a firm transportation contract pending with Midwestern Gas Transmission Company for 120,000 dekatherms per day of additional pipeline capacity that will provide access to Canadian and Rocky Mountain gas supplies via the Chicago hub, primarily to serve our Tennessee markets. The anticipated in-service date is November 2006. We have also executed an agreement with Hardy Storage Company for market-area storage capacity in West Virginia with an anticipated in-service date in 2007. We have a 50% equity interest in this project which is discussed in Note 10 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2005.

We have two reportable business segments, regulated utility and non-utility activities. For further information on business segments, see Note 7 to the condensed consolidated financial statements.

Our utility operations are regulated by the NCUC, the Public Service Commission of South Carolina and the Tennessee Regulatory Authority as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the FERC that affect the availability of and the prices paid for the interstate transportation

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of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity and safety of natural gas distribution systems and regulations of the Environmental Protection Agency relating to the use and release into the environment of hazardous wastes. In addition, we are subject to numerous regulations, such as those relating to employment practices, which are generally applicable to companies doing business in the United States of America.

In the Carolinas, our service area is comprised of numerous cities, towns and communities including Anderson, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide wholesale natural gas service to Greenville, Monroe, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to Gallatin and Smyrna.

Our regulatory commissions approve rates and tariffs that are designed to give us the opportunity to generate revenues to cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. Through October 31, 2005, we had WNA mechanisms in all three states that partially offset the impact of unusually cold or warm weather on bills rendered during the months of November through March for weather-sensitive customers. In North Carolina and Tennessee, adjustments are made directly to the customer’s bill. In South Carolina, the adjustments are calculated at the individual customer level and recorded in a deferred account (regulatory asset or liability) for subsequent collection from or refund to all customers in the class. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which results in an increase in revenues when weather is warmer than normal and a decrease in revenues when weather is colder than normal. The gas cost portion of our costs is recoverable through PGA procedures and is not affected by the WNA. Effective November 1, 2005, the WNA was eliminated in North Carolina and replaced with the CUT that provides for the recovery of our approved margin per customer independent of weather or other usage and consumption patterns of residential and commercial customers. The CUT tracks our margin earned monthly and will result in semi-annual rate adjustments to refund any over-collection or recover any under-collection.

On January 3, 2006, the North Carolina Office of the Attorney General filed a notice of appeal challenging the lawfulness of the NCUC’s authorization and approval of the CUT. We believe the CUT is lawful, just and reasonable and reflects good public policy, and we intend to vigorously defend the NCUC’s action authorizing and approving the CUT. We are unable to predict the outcome of an appeal or the potential impact to our rates, charges or terms and conditions of service should the NCUC order be reversed or remanded.

We invest in joint ventures to complement or supplement income from utility operations. If an opportunity aligns with our overall business strategies, we analyze and evaluate the project with a major factor being a projected rate of return greater than the returns allowed in our utility operations, due to the higher risk of such projects. We participate in the governance of the venture by having a management representative on the governing board of the venture. We monitor actual performance against expectations. Decisions regarding exiting joint ventures are based on many factors, including performance results and continued alignment with our business strategies.

Financial Condition and Liquidity

We believe we have access to adequate resources to meet our needs for working capital, construction expenditures, anticipated debt redemptions and dividend payments. These resources include net cash

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flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and bank lines of credit.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations resulting from such factors as weather, natural gas prices, collections from customers, natural gas purchases, gas inventory storage activity and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas in storage and the collection of amounts billed to customers during the peak heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage and decreases in receipts from customers.

During the peak heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The value of the gas can vary significantly from period to period due to the volatility in the price of natural gas. Our natural gas costs and amounts due to/from customers represent the difference between natural gas costs that we have paid to suppliers and amounts that we have collected from customers. These natural gas costs can cause cash flows to vary significantly from period to period.

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by customers in order to reduce their consumption. Temperatures above normal can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.

Net cash used in operating activities was $118.8 million and $17.6 million for the three months ended January 31, 2006 and 2005, respectively. The change was primarily due to increases in receivables, unbilled utility revenues and inventories, partially offset by an increase in trade payables, primarily related to increases in gas costs.

With the higher gas costs experienced in the 2005-2006 winter heating season, more customers have enrolled in our equal payment plan (EPP) to spread their gas bills over a twelve-month period. Net receivables from EPP customers increased $28.9 million from October 31, 2005, to January 31, 2006.

During the three months ended January 31, 2006, we continued to purchase flowing gas to serve our customers rather than fully utilize our storage withdrawal capabilities because of warmer-than-normal weather and uncertainties early in the heating season. Our gas in storage increased from $151.9 million as of October 31, 2005, to $188.8 million as of January 31, 2006.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is minimal based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary.

The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with

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electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, such as price volatility, the availability of natural gas in relation to other energy forms, general economic conditions, weather, energy conservation, the ability to convert from natural gas to other energy sources, and legislation. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. With a tighter balance between domestic supply and demand, the cost of natural gas from non-domestic sources may play a greater role in establishing the future market price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between supply and demand and the policies of foreign and domestic governments. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

Cash Flows from Investing Activities. Net cash used in investing activities was $30.2 million and $26 million for the three months ended January 31, 2006 and 2005, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the three months ended January 31, 2006, were $51.1 million ($47.4 million net of the allowance for funds used during construction, contributions in aid of construction and bond reimbursements).

During the three months ended January 31, 2006, the restrictions on cash totaling $13.1 million were removed in connection with implementing the NCUC order in the general rate proceeding discussed in Note 4 to the condensed consolidated financial statements. As ordered by the NCUC, such cash had been held in an expansion fund to extend natural gas service to unserved areas of the state.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports the growth in our customer base. We have budgeted $181.2 million for utility construction expenditures for fiscal 2006; however, we are not contractually obligated to expend capital until the work is completed. Due to projected growth in our service areas, significant utility construction expenditures are expected to continue and are a part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

Cash Flows from Financing Activities. Net cash provided by financing activities was $171.6 million and $63.4 million for the three months ended January 31, 2006 and 2005, respectively. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and employee stock plans, net of purchases under the common stock repurchase program. We sell common stock and long-term debt to cover cash requirements when market and other conditions favor such long-term financing.

As of January 31, 2006, we had committed bank lines of credit totaling $250 million, for which we pay a maximum annual fee of $.3 million, and additional uncommitted lines of credit totaling $250 million on a no fee and as needed, if available, basis. Outstanding short-term borrowings as of January 31, 2006, totaled $350 million, with $250 million under the committed lines and $100 million under the uncommitted lines. During the three months ended January 31, 2006, short-term borrowings ranged from

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$115 million to $378.5 million, and interest rates ranged from 4.07% to 4.89%. The lines of credit expire in April 2006 and we anticipate replacing the lines with a syndicated five-year facility. The syndicated facility is expected to have an initial committed line of $350 million with the ability to expand it to $600 million.

As of January 31, 2006, we had a line of credit for letters of credit of $1.5 million, of which $1.2 million were issued and outstanding. These letters of credit are used to guarantee claims from self-insurance under our general liability policies.

The level of short-term borrowings can vary significantly due to changes in the wholesale prices of natural gas and to the level of purchases of natural gas supplies to serve customer demand and for storage. Short-term debt may increase when wholesale prices for natural gas increase because we must pay suppliers for the gas before we collect our costs from customers through their monthly bills. Gas prices could continue to increase and fluctuate. If wholesale gas prices remain high, we may incur more short-term debt to pay for natural gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

During the three months ended January 31, 2006, we issued $4.9 million of common stock through dividend reinvestment and stock purchase plans. Under the Common Stock Open Market Purchase Program, we paid $7.2 million during the three months ended January 31, 2006, for .3 million shares of common stock that are available for reissuance to these plans.

In our fiscal second quarter in 2006, we intend to enter into an accelerated share repurchase program where we will repurchase and subsequently retire approximately four million shares of common stock over a four-year period. The accelerated share repurchase program will be in addition to shares that are repurchased on a normal basis through the open market program.

We have paid quarterly dividends on our common stock since 1956. The amount of cash dividends that may be paid is restricted by provisions contained in certain note agreements under which long-term debt was issued. As of January 31, 2006, none of our retained earnings was restricted. On March 3, 2006, the Board of Directors declared a quarterly dividend on common stock of $.24 per share, payable April 13, 2006, to shareholders of record at the close of business on March 24.

As of January 31, 2006, our capitalization, including current maturities of long-term debt, consisted of 41% in long-term debt and 59% in common equity. Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity.

In July 2006, we expect to make the scheduled payment of $35 million on the 9.44% senior notes. Depending upon our needs for long-term financing and current market conditions, we expect to issue approximately $200 million of long-term debt in our fiscal third quarter in 2006 under a shelf registration which has a remaining balance of $309.4 million.

As of January 31, 2006, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors. Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings.

We are subject to default provisions related to our long-term debt and short-term bank lines of credit. Failure to satisfy any of the default provisions would result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of January 31, 2006, we are in

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compliance with all default provisions.

Estimated Future Contractual Obligations

During the three months ended January 31, 2006, there were no material changes to our estimated future contractual obligations that were disclosed in our Form 10-K for the year ended October 31, 2005, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than operating leases that were discussed in Note 7 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2005.

Critical Accounting Policies and Estimates

We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results may differ significantly from these estimates and assumptions. We base our estimates on historical experience, where applicable, and other relevant factors that we believe are reasonable under the circumstances. On an ongoing basis, we evaluate estimates and assumptions and make adjustments in subsequent periods to reflect more current information if we determine that modifications in assumptions and estimates are warranted.

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, goodwill and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of the critical accounting estimates presented in our Form 10-K for the year ended October 31, 2005, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Management has discussed these critical accounting estimates with the Audit Committee of the Board of Directors. There have been no changes in our critical accounting policies and estimates since October 31, 2005.

Recent Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment” (Statement 123R). Statement 123R requires entities to adopt the fair value method of accounting for stock-based plans. The fair value method requires the amortization of the fair value of stock-based compensation as determined at the date of grant over the related vesting period. Under Statement 123R, most employee stock purchase plans that offer a discount of greater than 5% are considered compensatory. We adopted Statement 123R on November 1, 2005, and amended our employee stock purchase plan to lower the discount from 10% to 5%. The adoption of Statement 123R did not have any effect on our financial position, results of operations or cash flows.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), to clarify the term “conditional asset retirement” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations.” FIN 47 requires that a liability be recognized for the fair

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value of a conditional asset retirement obligation when incurred, if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation would be factored into the measurement of the liability when sufficient information exists. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Accordingly, we will adopt FIN 47 no later than our fourth fiscal quarter in 2006. We are currently assessing the impact FIN 47 may have on our consolidated balance sheet; however, we believe the adoption of FIN 47 will not have any impact on our financial position, results of operations or cash flows.

Recent Developments

At the Annual Meeting of Shareholders on March 3, 2006, shareholders approved an amendment to Article 3 of our Articles of Incorporation to increase the number of authorized shares of common stock from 100 million to 200 million shares. In addition, shareholders approved the Incentive Compensation Plan effective as of November 1, 2005. The plan provides for short-term and long-term incentive compensation payable in cash, stock options, restricted stock and other stock-based awards.

Forward-Looking Statements

Documents we file with the SEC may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations and information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to:

• Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our effectiveness in achieving the allowed rates of return and initiate rate proceedings or operating changes as needed. In addition, we purchase natural gas transportation and storage services from interstate and intrastate pipeline companies whose rates and services are regulated.

• Residential, commercial and industrial growth in our service areas. The ability to grow our customer base and the pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and fluctuations in the wholesale prices of natural gas and competitive energy sources.

• Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies and we expect this highly competitive environment to continue. We must be able to adapt to the changing environments and the competition.

• 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.

• Regulatory issues, customer growth, deregulation, economic and capital market conditions, the cost and availability of natural gas and weather conditions can impact our ability to meet internal performance goals.

• The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays and changes in project costs. Weather, general

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economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project. Our internally generated cash flows are not adequate to finance the full cost of this construction. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations.

• Changes in the availability and cost of natural gas. To meet firm 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 allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations.

• Impact of the Energy Policy Act of 2005. Key components of the bill include provisions that encourage fuel diversity in the generation of electricity, provide incentives promoting energy efficiency and innovative technology, allow an inventory of energy reserves in the Outer Continental Shelf and support Liquefied Natural Gas (LNG) imports and improved leasing and permitting processes in the development of existing supply fields.

• Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, can impact our suppliers and the pipelines that deliver gas to our distribution system. Weather conditions directly influence the supply of, demand for and the cost of natural gas.

• Changes in environmental, safety and system integrity regulations and the cost of compliance. We are subject to extensive federal, state and local regulations. Compliance with such regulations may result in increased capital or operating costs.

• Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.

• Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities. Future changes in accounting standards could affect our reported earnings or increase our liabilities.

• Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses and we assume such risks as an equity investor.

All of these factors are difficult to predict and some of them are beyond our control. For these reasons, you should not rely on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “should,” “could,” “will,” “assume,” “can,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.

Factors relating to regulation and management also may be described or incorporated by reference in 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 may also be other factors besides those described above that could cause actual conditions, events or results to differ from those in the forward-looking statements.

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Forward-looking statements are only as of the date they are made and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Please reference our web site at www.piedmontng.com for current information. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our web site as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We hold all financial instruments discussed in this item for purposes other than trading. We are potentially exposed to market risk due to changes in interest rates and the cost of gas. Our exposure to interest rate changes relates primarily to short-term debt. We are exposed to interest rate changes to long-term debt when we are in the market to issue long-term debt. As of January 31, 2006, all of our long-term debt was at fixed rates. Exposure to gas cost variations relates to the wholesale supply, demand and price of 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.

As of January 31, 2006, we had $350 million of short-term debt outstanding. The carrying amount of our short-term debt approximates fair value. The following table reflects our short-term borrowings during the three months ended January 31, 2006.

In thousands	High			Low
Outstanding short-term borrowings	$	378,500		$	115,000
Interest rates		4.89	%		4.07	%
Weighted average interest rate during the period		4.55	%

As of January 31, 2006, all of our long-term debt was at fixed interest rates and, therefore, not subject to interest rate risk.

Commodity Price Risk

In the normal course of business, we utilize exchange-traded contracts of various duration for the forward sale and purchase of a portion of our natural gas requirements. 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 financial exposure to changes in commodity prices as substantially all changes in purchased gas costs and the costs of hedging our gas supplies are passed on to customers through PGA procedures.

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 2 of this Form 10-Q.

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Item 4. Controls and Procedures

Our management, including the President and Chief Executive Officer and the Senior Vice President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Form 10-Q. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this Form 10-Q, our disclosure controls and procedures were effective in that they provide reasonable assurances that the information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods required by the United States Securities and Exchange Commission’s rules and forms.

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There have been no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the first quarter of fiscal 2006 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

We have only routine litigation in the normal course of business and do not expect the outcomes to have any material impact on our financial position, results of operations or cash flows.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

     c) Issuer Purchases of Equity Securities.

          The following table provides information with respect to purchases of common stock under the Common Stock Open Market Purchase Program during the three months ended January 31, 2006.

	Total		Average		Total Number of		Maximum Number of
	Number		Price		Shares Purchased		Shares that May
	of Shares		Paid Per		As Part of Publicly		Yet be Purchased
Period	Purchased		Share		Announced Program		Under the Program
November 2005		120,026	$	22.83		120,026		1,572,074
December 2005		50,421		23.42		50,421		8,521,653*
January 2006		135,179		24.42		135,179		8,386,474
Total		305,626				305,626

* Reflects increase of seven million shares explained below.

The Common Stock Open Market Purchase Program was announced on June 4, 2004, to purchase up to three million shares of common stock for reissuance under our dividend reinvestment, stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved the purchase of up to four million additional shares of common stock and amended the program to provide for purchases to maintain our debt-to-equity capitalization ratios at target levels. These combined actions increased the total authorized share repurchases from three million to ten million shares.

The amount of cash dividends that may be paid is restricted by provisions contained in certain note agreements under which long-term debt was issued. As of January 31, 2006, none of our retained earnings was restricted.

Item 6. Exhibits

Exhibits –
	31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
	31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.
	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer.
	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer.

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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, 2006	/s/ David J. Dzuricky
	David J. Dzuricky
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)
Date March 13, 2006	/s/ Barry L. Guy
	Barry L. Guy
	Vice President and Controller
	(Principal Accounting Officer)

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