Piedmont Natural Gas 10Q 2009 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)


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

		For the quarterly period ended April 30, 2009

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		(I.R.S. Employer
incorporation or organization)		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.x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).o Yes o No

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


Large accelerated filerx		Accelerated filero
Non-accelerated filero (Do not check if a smaller reporting company)		Smaller reporting companyo

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at June 2, 2009

Common Stock, no par value		72,959,779

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

April 30, 2009

TABLE OF CONTENTS

Part I. Financial Information

Item 1. Financial Statements

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


	April 30,		October 31,
	2009		2008
ASSETS
Utility Plant:
Utility plant in service	$	3,031,478	$	2,997,186
Less accumulated depreciation		848,527		813,822

Utility plant in service, net		2,182,951		2,183,364
Construction work in progress		65,874		57,470
Plant held for future use		6,729		—

Total utility plant, net		2,255,554		2,240,834

Other Physical Property, at cost (net of accumulated depreciation of $2,425 in 2009 and $2,351 in 2008)		791		864


Current Assets:
Cash and cash equivalents		20,649		6,991
Trade accounts receivable (less allowance for doubtful accounts of $3,591 in 2009 and $1,066 in 2008)		140,267		82,346
Income taxes receivable		—		731
Other receivables		4,512		393
Unbilled utility revenues		31,252		51,819
Inventories:
Gas in storage		92,666		190,275
Materials, supplies and merchandise		6,088		6,524
Gas purchase options, at fair value		3,299		22,645
Amounts due from customers		231,645		181,745
Prepayments		18,179		79,831
Other		96		96

Total current assets		548,653		623,396


Noncurrent Assets:
Equity method investments in non-utility activities		95,380		99,214
Goodwill		48,852		48,852
Marketable securities, at fair value		382		—
Overfunded postretirement asset		6,598		6,797
Regulatory asset for postretirement benefits		29,496		28,732
Gas purchase options, at fair value		3,342		32,434
Unamortized debt expense		9,555		9,915
Regulatory cost of removal asset		6,771		6,398
Other		40,470		40,965

Total noncurrent assets		240,846		273,307


Total	$	3,045,844	$	3,138,401

See notes to consolidated financial statements.


	April 30,			October 31,
(In thousands)	2009			2008
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value - 175 shares authorized	$	—		$	—
Common stock — no par value — shares authorized: 200,000; shares outstanding: 72,942 in 2009 and 73,246 in 2008		464,109			471,565
Paid-in capital		949			763
Retained earnings		509,753			414,246
Accumulated other comprehensive income (loss)		(4,959	)		670

Total stockholders’ equity		969,852			887,244
Long-term debt		793,471			794,261

Total capitalization		1,763,323			1,681,505


Current Liabilities:
Current maturities of long-term debt		30,000			30,000
Notes payable		205,500			406,500
Trade accounts payable		69,401			91,142
Other accounts payable		24,611			45,148
Income taxes accrued		18,057			4,414
Accrued interest		21,933			22,777
Customers’ deposits		26,147			23,881
Deferred income taxes		23,859			6,878
General taxes accrued		9,616			18,932
Gas purchase options, at fair value		75,287			42,205
Other		7,349			12,300

Total current liabilities		511,760			704,177


Noncurrent Liabilities:
Deferred income taxes		320,934			305,362
Unamortized federal investment tax credits		2,460			2,626
Regulatory liability for postretirement benefits		367			372
Accumulated provision for postretirement benefits		16,836			16,257
Cost of removal obligations		380,870			367,450
Gas purchase options, at fair value		14,284			22,177
Other		35,010			38,475

Total noncurrent liabilities		770,761			752,719


Commitments and Contingencies (Note 12)


Total	$	3,045,844		$	3,138,401

See notes to consolidated financial statements.

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


	Three Months Ended						Six Months Ended
	April 30						April 30
	2009			2008			2009			2008
Operating Revenues	$	455,432		$	634,178		$	1,235,076		$	1,422,648
Cost of Gas		285,479			472,897			844,440			1,034,341


Margin		169,953			161,281			390,636			388,307


Operating Expenses:
Operations and maintenance		53,352			53,282			104,077			105,859
Depreciation		24,306			22,893			48,448			45,598
General taxes		8,657			8,407			17,394			17,153
Income taxes		28,287			24,877			77,235			75,938


Total operating expenses		114,602			109,459			247,154			244,548


Operating Income		55,351			51,822			143,482			143,759


Other Income (Expense):
Income from equity method investments		17,832			17,734			27,621			26,452
Non-operating income (loss)		(132	)		84			(98	)		627
Non-operating expense		(857	)		(801	)		(1,206	)		(1,066	)
Income taxes		(6,757	)		(6,702	)		(10,473	)		(10,228	)


Total other income (expense)		10,086			10,315			15,844			15,785


Utility Interest Charges:
Interest on long-term debt		13,817			13,852			27,671			27,722
Allowance for borrowed funds used during construction		(532	)		(1,247	)		(1,227	)		(2,185	)
Other		(1,373	)		908			(1,519	)		3,114

Total utility interest charges		11,912			13,513			24,925			28,651


Net Income	$	53,525		$	48,624		$	134,401		$	130,893


Average Shares of Common Stock:
Basic		73,239			73,418			73,280			73,348
Diluted		73,514			73,677			73,582			73,617

Earnings Per Share of Common Stock:
Basic	$	0.73		$	0.66		$	1.83		$	1.78
Diluted	$	0.73		$	0.66		$	1.83		$	1.78

Cash Dividends Per Share of Common Stock	$	0.27		$	0.26		$	0.53		$	0.51

See notes to consolidated financial statements.

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


	Six Months Ended
	April 30
	2009			2008
Cash Flows from Operating Activities:
Net income	$	134,401		$	130,893
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		51,045			47,818
Amortization of investment tax credits		(165	)		(184	)
Allowance for doubtful accounts		2,525			3,264
Deferred gain on sale of land		(155	)		(106	)
Earnings from equity method investments		(27,621	)		(26,452	)
Distributions of earnings from equity method investments		21,885			32,090
Deferred income taxes		36,178			41,538
Stock-based compensation expense		168			168
Changes in assets and liabilities:
Gas purchase options, at fair value		73,627			(2,703	)
Receivables		(43,998	)		(112,041	)
Inventories		98,045			27,091
Amounts due from customers		(49,900	)		20,412
Settlement of legal asset retirement obligations		(769	)		(607	)
Overfunded postretirement asset		199			1,705
Regulatory asset for postretirement benefits		(764	)		338
Other assets		61,627			61,779
Accounts payable		(39,874	)		27,644
Amounts due to customers		—			9,746
Regulatory liability for postretirement benefits		(5	)		(956	)
Provision for postretirement benefits		579			522
Other liabilities		287			9,681

Net cash provided by operating activities		317,315			271,640


Cash Flows from Investing Activities:
Utility construction expenditures		(52,389	)		(84,537	)
Allowance for funds used during construction		(1,227	)		(2,185	)
Contributions to equity method investments		—			(10,790	)
Distributions of capital from equity method investments		315			121
Proceeds from sale of land and buildings		—			554
Decrease in restricted cash		—			2,196
Investment in marketable securities		(365	)		—
Proceeds from sale of vehicles		127			—
Other		856			1,263

Net cash used in investing activities		(52,683	)		(93,378	)


Cash Flows from Financing Activities:
Decrease in notes payable, net		(201,000	)		(117,000	)
Retirement of long-term debt		(790	)		(174	)
Expenses related to expansion of the short-term facility		—			(106	)
Issuance of common stock through dividend reinvestment and employee stock plans		7,646			7,648
Repurchases of common stock		(17,857	)		(29,169	)
Dividends paid		(38,922	)		(37,411	)
Other		(51	)		—

Net cash used in financing activities		(250,974	)		(176,212	)


Net Increase in Cash and Cash Equivalents		13,658			2,050
Cash and Cash Equivalents at Beginning of Period		6,991			7,515

Cash and Cash Equivalents at End of Period	$	20,649		$	9,565

Noncash Investing and Financing Activities:
Accrued construction expenditures	$	2,404		$	1,776
Guaranty		—			101

See notes to consolidated financial statements.

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


	Three Months Ended						Six Months Ended
	April 30						April 30
	2009			2008			2009			2008
Net Income	$	53,525		$	48,624		$	134,401		$	130,893

Other Comprehensive Income:
Unrealized (loss) gain from hedging activities of equity method investments, net of tax of ($1,858) and $306 for the three months ended April 30, 2009 and 2008, respectively, and ($3,369) and $470 for the six months ended April 30, 2009 and 2008, respectively		(2,886	)		481			(5,229	)		739
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $310 and ($649) for the three months ended April 30, 2009 and 2008, respectively, and ($256) and ($796) for the six months ended April 30, 2009 and 2008, respectively		480			(1,011	)		(400	)		(1,241	)


Total Comprehensive Income	$	51,119		$	48,094		$	128,772		$	130,391

See notes to consolidated financial statements.

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

1.		Summary of Significant Accounting Policies

		Unaudited Interim Financial Information

The consolidated financial statements have not been audited. We have prepared the unaudited consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements prepared in conformity with generally accepted accounting principles in the United States of America are omitted in this interim report under these SEC rules and regulations. 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, 2008.

Seasonality and Use of Estimates

The unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at April 30, 2009 and October 31, 2008, the results of operations for the three months and six months ended April 30, 2009 and 2008, and cash flows for the six months ended April 30, 2009 and 2008. Our business is seasonal in nature. The results of operations for the three months and six months ended April 30, 2009 do not necessarily reflect the results to be expected for the full year.

We make estimates and assumptions when preparing the 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

Significant Accounting Policies

Our accounting policies are described in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2008. There were no significant changes to those accounting policies during the six months ended April 30, 2009 other than the adoption of Financial Accounting Standards Board (FASB) Staff Position (FSP) FSP FIN 39-1. For further information, see Note 8 to the consolidated financial statements in this Form 10-Q.

In March 2009, we deferred the development and construction of our previously announced liquefied natural gas (LNG) peak storage facility in Robeson County, North Carolina based on revised growth projections. Based on our current growth projections, we may resume development of the project in 2011 to prepare for construction in 2012 in order to provide service in 2015. In accordance with utility accounting practice, we have classified as plant held for future use expenditures associated with the LNG facility. The amount classified as plant held for future use includes capitalized charges for the allowance for funds used during construction through the date the amounts were transferred to plant held for future use from construction work in progress.

Rate-Regulated Basis of Accounting

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 and regulatory liabilities in the consolidated balance sheets as of April 30, 2009 and October 31, 2008 are as follows.


	April 30,		October 31,
In thousands	2009		2008
Regulatory Assets	$	312,227	$	263,205
Regulatory Liabilities		396,870		383,684

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. For information on related party transactions, see Note 7 to the consolidated financial statements in this Form 10-Q.

Accounting Pronouncements

In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161). Statement 161 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities. We adopted Statement 161 effective on February 1, 2009 for derivatives that we record on the consolidated balance sheets in accordance with Statement 133. The disclosure requirements are presented in “Quantitative and Qualitative Disclosures” in Note 8 to the consolidated financial statements in this Form 10-Q.

In December 2008, the FASB issued FSP FAS 132(R)-1, that amended SFAS No. 132(R), “Employers’ Disclosures about Pension and Other Postretirement Benefits,” that requires additional disclosures about plan assets of defined benefit pension and other postretirement plans. This staff position requires that employers provide more transparency about the assets held by retirement plans or other postretirement employee benefit plans, the concentration of risk in those plans and information about the fair value measurements of plan assets similar to the disclosures required by SFAS No. 157, “Fair Value Measurements” (Statement 157). FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since this staff position only requires additional disclosures about plan assets of defined benefit pension and other postretirement plans, it is not expected to have a material impact on our financial position, results of operations or cash flows. We will adopt FSP FAS 132(R)-1 during our fiscal year ending October 31, 2010.

after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted FSP FAS 107-1 and APB 28-1 this quarter. Comparative information is not required at initial adoption. The disclosure requirements are presented in “Fair Value Measurements” in Note 8 to the consolidated financial statements in this Form 10-Q.

Also in April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating the fair value in accordance with Statement 157 when the volume and level of activity for the asset or liability have significantly decreased. We adopted FSP FAS 157-4 effective this quarter, as concurrent adoption of this FSP is required with the early adoption of FSP FAS 107-1 and APB 28-1. The adoption had no impact on our consolidated financial statements.

In May 2009, the FASB issued SFAS No.165, “Subsequent Events” (Statement 165). Statement 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before the date that the financial statements are issued or are available to be issued. It requires disclosure of the date through which an entity has evaluated subsequent events. Statement 165 is effective for interim and annual periods ending after June 15, 2009. We do not expect Statement 165 to have a material impact on our financial position, results of operations or cash flows. We will adopt Statement 165 during the period ending July 31, 2009.

Regulatory Matters

In August 2008, we filed testimony with the North Carolina Utilities Commission (NCUC) in support of our gas cost purchasing and accounting practices for the period ended May 31, 2008. A hearing was held in December 2008. On February 20, 2009, the NCUC issued an order approving our accounting of gas costs for the twelve months ended May 31, 2008 and found our gas purchasing polices and practices prudent during the review period.

In December 2008, we filed an annual report for the twelve months ended December 31, 2007 with the Tennessee Regulatory Authority (TRA) that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. On April 29, 2009, the TRA staff filed its compliance audit report, with which we concurred. On May 18, 2009, the TRA issued an order adopting all findings from the staff audit. The order includes cost of gas adjustments for the calendar year 2007 review period. There was no material impact from these gas cost adjustments. We were found to be in compliance with the TRA rules in the use of the ACA mechanism.

Earnings per Share

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 and six months ended April 30, 2009 and 2008 is presented below.


	Three Months				Six Months
In thousands except per share amounts	2009		2008		2009		2008
Net Income	$	53,525	$	48,624	$	134,401	$	130,893


Average shares of common stock outstanding for basic earnings per share		73,239		73,418		73,280		73,348
Contingently issuable shares under incentive compensation plans		275		259		302		269


Average shares of dilutive stock		73,514		73,677		73,582		73,617


Earnings Per Share of Common Stock:
Basic	$	0.73	$	0.66	$	1.83	$	1.78
Diluted	$	0.73	$	0.66	$	1.83	$	1.78

Accelerated Share Repurchase

On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the accelerated share repurchase (ASR) program, which were consolidated. Upon this authorization, there were 7,010,074 shares available for repurchase under the program.

On March 20, 2009, we entered into an ASR agreement with an investment bank to purchase and retire 700,000 shares of our common stock from an investment bank at the closing price that day of $26.35 per share. Total consideration paid to purchase the shares of $18.4 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the consolidated balance sheets.

As part of the ASR agreement, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in approximately 35 trading days. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 700,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price was higher than the initial purchase closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price for the shares purchased was lower than the initial purchase closing price. At settlement on April 21, 2009, we received cash of $.6 million from the investment bank and recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the consolidated balance sheets. The $.6 million was the difference between the investment bank’s weighted average purchase price of $25.6093 less a discount of $.10 for a settlement price of $25.5093 and the initial purchase closing price of $26.35 per share multiplied by 700,000 shares.

Employee Benefit Plans

Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other postretirement employee benefits (OPEB) plan and our 401(k) plans. These amendments applied to nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective January 1, 2009, these same amendments apply to all employees, including those covered by the Nashville, Tennessee bargaining unit contract. The details of the changes to these plans are described in Note 7 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2008.

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the three months ended April 30, 2009 and 2008 are presented below.


	Qualified Pension						Nonqualified Pension					Other Benefits
In thousands	2009			2008			2009			2008		2009			2008
Service cost	$	1,487		$	2,163		$	6		$	7	$	360		$	317
Interest cost		2,750			2,835			81			69		579			509
Expected return on plan assets		(4,138	)		(4,145	)		—			—		(426	)		(370	)
Amortization of transition obligation		—			—			—			—		167			169
Amortization of prior service (credit) cost		(549	)		(478	)		5			—		—			—
Amortization of actuarial gain		—			—			(5	)		—		—			—

Total	$	(450	)	$	375		$	87		$	76	$	680		$	625

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the six months ended April 30, 2009 and 2008 are presented below.


	Qualified Pension						Nonqualified Pension					Other Benefits
In thousands	2009			2008			2009			2008		2009			2008
Service cost	$	2,974		$	4,325		$	13		$	13	$	720		$	633
Interest cost		5,501			5,670			164			139		1,159			1,019
Expected return on plan assets		(8,276	)		(8,289	)		—			—		(853	)		(740	)
Amortization of transition obligation		—			—			—			—		334			338
Amortization of prior service (credit) cost		(1,099	)		(956	)		10			—		—			—
Amortization of actuarial gain		—			—			(15	)		—		—			—

Total	$	(900	)	$	750		$	172		$	152	$	1,360		$	1,250

We contributed $87,000 to the money purchase pension plan in February 2009. We anticipate that we will contribute the following amounts to our plans in 2009.


	In thousands
Qualified pension plan	$	22,000
Nonqualified pension plans		504
OPEB plan		3,400

We have a defined contribution restoration plan that is funded annually by us and covers all officers at the vice president level and above. For the six months ended April 30, 2009, we have contributed $.4 million to this plan. We have a voluntary deferral plan for the benefit of all officers, director-level employees and regional executives; we make no contributions to this plan.

Both deferred compensation plans are funded through a rabbi trust with a bank as the trustee. At April 30, 2009, we have a liability of $.5 million for these plans.

See Note 8 to the consolidated financial statements of this Form 10-Q for information on the investments in marketable securities that are held in the trust.

Business Segments

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 current 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 consolidated statements of income. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments” and “Non-operating income.”

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and 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 consolidated financial statements in our Form 10-K for the year ended October 31, 2008.

Operations by segment for the three months and six months ended April 30, 2009 and 2008 are presented below.


	Regulated				Non-utility
In thousands	Utility				Activities						Total
	2009		2008		2009			2008			2009		2008
Three Months
Revenues from external customers	$	455,432	$	634,178	$	—		$	—		$	455,432	$	634,178
Margin		169,953		161,281		—			—			169,953		161,281
Operations and maintenance expenses		53,352		53,282		37			47			53,389		53,329
Income from equity method investments		—		—		17,832			17,734			17,832		17,734
Operating income (loss) before income taxes		83,638		76,699		(45	)		(54	)		83,593		76,645
Income before income taxes		70,788		62,654		17,781			17,549			88,569		80,203

Six Months
Revenues from external customers	$	1,235,076	$	1,422,648	$	—		$	—		$	1,235,076	$	1,422,648
Margin		390,636		388,307		—			—			390,636		388,307
Operations and maintenance expenses		104,077		105,859		77			68			104,154		105,927
Income from equity method investments		—		—		27,621			26,452			27,621		26,452
Operating income (loss) before income taxes		220,717		219,697		(177	)		(203	)		220,540		219,494
Income before income taxes		194,680		191,034		27,429			26,025			222,109		217,059

Reconciliations to the consolidated statements of income for the three months and six months ended April 30, 2009 and 2008 are presented below.


In thousands	Three Months						Six Months
	2009			2008			2009			2008
Operating Income:
Segment operating income before income taxes	$	83,593		$	76,645		$	220,540		$	219,494
Utility income taxes		(28,287	)		(24,877	)		(77,235	)		(75,938	)
Non-utility activities before income taxes		45			54			177			203

Operating income	$	55,351		$	51,822		$	143,482		$	143,759


Net Income:
Income before income taxes for reportable segments	$	88,569		$	80,203		$	222,109		$	217,059
Income taxes		(35,044	)		(31,579	)		(87,708	)		(86,166	)

Net income	$	53,525		$	48,624		$	134,401		$	130,893

Equity Method Investments

The 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 consolidated balance sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in the consolidated statements of income.

We own 21.49% 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 each period of the three months and six months ended April 30, 2009 and 2008, these transportation costs and the amounts we owed Cardinal as of April 30, 2009 and October 31, 2008 are as follows.


	Three Months				Six Months
In thousands	2009		2008		2009		2008
Transportation costs	$	1,001	$	1,012	$	2,035	$	2,047

	April 30,		October 31,
	2009		2008
Trade accounts payable	$	337	$	349

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C., a North Carolina limited liability company. Pine Needle owns a 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 each period of the three months and six months ended April 30, 2009 and 2008, these gas storage costs and the amounts we owed Pine Needle as of April 30, 2009 and October 31, 2008 are as follows.


	Three Months				Six Months
In thousands	2009		2008		2009		2008
Gas storage costs	$	2,926	$	2,704	$	5,950	$	5,471

	April 30,		October 31,
	2009		2008
Trade accounts payable	$	986	$	1,019

We own 30% of the membership interests in SouthStar Energy Services LLC, a Delaware limited liability company. Under the terms of the Amended and Restated Limited Liability Company Agreement (Restated Agreement), earnings and losses are allocated 25% to us and 75% to the other member, Georgia Natural Gas Company (GNGC), a subsidiary of AGL Resources, Inc. (AGLR), with the exception of earnings and losses in the Ohio and Florida markets, which are allocated to us at our ownership percentage of 30%. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States with most of its business being conducted in the unregulated retail gas market in Georgia.

The SouthStar Restated Agreement includes a provision granting GNGC the option to purchase our ownership interest in SouthStar. Under the provision, GNGC has the option to purchase our entire 30% interest effective on January 1, 2010 provided they give us notice of their intent to exercise the option by November 1, 2009. If GNGC exercises its option, the purchase price would be based on the market value of SouthStar as defined in the Restated Agreement. On March 16, 2009, we filed a lawsuit in the Court of Chancery of the State of Delaware against GNGC based on statements filed in AGLR’s 2008 Form 10-K in which they re-characterized GNGC’s right to purchase our interest in SouthStar as an “evergreen” right. For further information on this lawsuit, see Note 12 in this Form 10-Q.

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 each period of the three months and six months ended April 30, 2009 and 2008, our operating revenues from these sales and the amounts SouthStar owed us as of April 30, 2009 and October 31, 2008 are as follows.


	Three Months				Six Months
In thousands	2009		2008		2009		2008
Operating revenues	$	2,180	$	3,217	$	5,178	$	6,229

	April 30,		October 31,
	2009		2008
Trade accounts receivable	$	525	$	1,202

Piedmont Hardy Storage Company, LLC (Piedmont Hardy), a wholly owned subsidiary of Piedmont, owns 50% of the membership interests in Hardy Storage Company LLC (Hardy Storage), a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia that is regulated by the FERC. Initial service to customers began April 1, 2007 when customers began injecting gas into storage for subsequent winter withdrawals. Final service levels were placed into service on April 1, 2009 as scheduled.

On June 29, 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility for up to a total of $173.1 million for funding during the construction period.

The members of Hardy Storage have each agreed to guarantee 50% of the construction financing. Our guaranty was executed by Piedmont Energy Partners, Inc. (PEP), a wholly owned subsidiary of Piedmont and a sister company of Piedmont Hardy. Our share of the guaranty is capped at $111.5 million. Depending upon the facility’s performance over the first three years after the in-service date, there could be additional construction expenditures of up to $10 million for contingency wells, of which PEP will guarantee 50%.

Securing PEP’s guaranty is a pledge of intercompany notes issued by Piedmont held by non-utility subsidiaries of PEP. Should Hardy Storage be unable to perform its payment obligation under the construction financing, PEP will call on Piedmont for the payment of the notes, plus accrued interest, for the amount of the guaranty. Also pledged is our membership interest in Hardy Storage.

For the six months ended April 30, 2009, we have made no equity contributions to fund construction expenditures. Upon completion of project construction, including any contingency wells if needed, the members intend to target a capitalization structure of 70% debt and 30% equity. After the satisfaction of certain conditions in the note purchase agreement, amounts outstanding under the interim notes will convert to a fifteen-year mortgage-style debt instrument without recourse to the members. We expect the conversion to occur by May 2010. To the extent that more funding is needed, the members will evaluate funding options at that time.

We record a liability at fair value for this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter, with a corresponding increase to our investment account in the venture. As our risk in the project changes, the fair value of the guaranty is adjusted accordingly through a quarterly evaluation. The details of the guaranty at April 30, 2009 and October 31, 2008 are as follows.


	April 30,		October 31,
In thousands	2009		2008
Guaranty liability	$	1,234	$	1,234
Amount outstanding under the construction financing		123,410		123,410

We have related party transactions as a customer of Hardy Storage and record in cost of gas the storage costs charged by Hardy Storage. For each period of the three months and six months ended April 30, 2009 and 2008, our gas storage costs and the amounts we owed Hardy Storage as of April 30, 2009 and October 31, 2008 are as follows.


	Three Months				Six Months
In thousands	2009		2008		2009		2008
Gas storage costs	$	2,330	$	2,364	$	4,652	$	4,572

	April 30,		October 31,
	2009		2008
Trade accounts payable	$	782	$	774

8.		Financial Instruments and Risk Management

		Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. Based on the value of our positions in these brokerage accounts and the associated margin requirements, we may be required to deposit cash into these brokerage accounts. In April 2007, the FASB issued a staff position, FSP FIN 39-1, that amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. On November 1, 2008, we elected “not to net” fair value amounts for our derivative instruments or the fair value of the right to reclaim cash collateral under FSP FIN 39-1 and moved to a gross presentation. We include amounts recognized for the right to reclaim cash collateral in our current assets and current liabilities. We had the right to reclaim cash collateral of $87.5 million and $67.3 million as of April 30, 2009 and October 31, 2008, respectively.

Fair Value Measurements

In September 2006, the FASB issued Statement 157 (“Fair Value Measurements”). Statement 157 provides enhanced guidance for using fair value to measure assets and liabilities and applies

whenever other standards require (or permit) the measurement of assets or liabilities at fair value, but does not expand the use of fair value measurement to any new circumstances. Under Statement 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. Statement 157 clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. Statement 157 establishes a fair value hierarchy for valuation inputs that prioritizes the information used to develop those assumptions into three levels.

In November 2007, the FASB delayed the implementation of Statement 157 for one year only for other nonfinancial assets and liabilities. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.

We adopted Statement 157 on November 1, 2008 for our financial assets and liabilities, which consist primarily of derivatives that we record on the consolidated balance sheets in accordance with Statement 133. The adoption of Statement 157 had no impact on our financial position, results of operations or cash flows. There was no cumulative effect adjustment to retained earnings as a result of the adoption. We will adopt Statement 157 for our nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis on November 1, 2009 and are currently evaluating the impact on our financial position, results of operations and cash flows.

The carrying value of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate fair value.

We utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally observable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs into the following fair value hierarchy levels as set forth in Statement 157.

Level 1

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity has the ability to access as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives and investments in marketable securities.

Level 2

Level 2 inputs are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly corroborated or observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. We obtain market price data from multiple sources in order to value our Level 2 transactions, and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include non-exchange-traded derivative instruments such as over-the-counter (OTC) options.

Level 3

Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customer’s needs. We do not have any material financial assets or liabilities classified as Level 3.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of April 30, 2009. As required by Statement 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their consideration with the fair value hierarchy levels.

Recurring Fair Value Measurements under Statement 157 as of April 30, 2009


			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable		Total
	Markets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
In thousands
Assets:
Derivatives held for distribution operations	$	6,641	$	—	$	—	$	6,641
Debt and equity securities held as trading securities		382		—		—		382

Total fair value assets	$	7,023	$	—	$	—	$	7,023


Liabilities:
Derivatives held for distribution operations	$	76,980	$	12,591	$	—	$	89,571

The determination of the fair values incorporates various factors required under Statement 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), and the impact of our nonperformance risk on our liabilities.

Our utility segment derivative instruments are used in accordance with programs filed or approved with the NCUC, the Public Service Commission of South Carolina (PSCSC) and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net costs and the gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our purchased gas adjustment (PGA) procedures. In accordance with Statement 71, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due to customers” or “Amounts due from customers” in our consolidated balance sheets. These derivative instruments include exchange-traded and OTC derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1. OTC

derivative contracts are valued using broker or dealer quotation services or market transactions in either the listed or OTC markets and are classified within Level 2.

Trading securities include assets in a trust established for our deferred compensation plans and are included in “Marketable securities, at fair value” in the consolidated balance sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

We adopted FSP FAS 107-1 and APB 28-1 for interim disclosures of the fair value of financial instruments this quarter. In developing the fair value of our long-term debt, we use a discounted cash flow technique that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury bench mark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion, are shown below.


	Carrying
In thousands	Amount		Fair Value
As of April 30, 2009	$	823,471	$	873,213
As of October 31, 2008		824,261		798,057

Quantitative and Qualitative Disclosures

Effective February 1, 2009, we adopted SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities” (Statement 161) for derivatives that we record on the consolidated balance sheets in accordance with Statement 133. Statement 161 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement 133), by requiring expanded qualitative, quantitative and credit-risk disclosures about derivative instruments and hedging activities. Statement 161 requires specific disclosures regarding how and why an entity uses derivative instruments; how derivative instruments and related hedged items are accounted for; and how derivative instruments and related hedged items affect an entity’s financial position, results of operations and cash flows. Statement 161 also amended Statement 107 to clarify that derivative instruments are subject to Statement 107’s concentration-of-credit-risk disclosures.

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions and thus are not accounted for as hedging instruments under Statement 133. As required by Statement 161, the fair value amounts are presented on a gross basis and do not reflect any netting of asset and liability amounts or cash collateral amounts under master netting arrangements. As of April 30, 2009, our financial options were comprised of both long and short commodity positions. A long position is an option contract (obligation or right) to purchase the commodity at a specified price, while a short position is an option contract (obligation or right) to sell the commodity at a specified price. As of April 30, 2009, we had long gas options of 116,090,000 dekatherms and short gas options of 55,480,000 dekatherms providing total coverage of 73,350,000 dekatherms over the period from June 2009 through November 2010.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of April 30, 2009.

Fair Value of Derivative Instruments as of April 30, 2009


	Balance Sheet Classification	Fair Value
		(in thousands)
Derivatives Not Designated as Hedging Instruments under Statement 133

Asset Financial Instruments
Current gas purchase options (June 2009 - May 2010)	Current Assets — Gas purchase options	$	3,299
Noncurrent gas purchase options (June 2010 - November 2010)	Noncurrent Assets — Gas purchase options		3,342

Total			6,641

Liability Financial Instruments
Current gas purchase options (June 2009 - May 2010)	Current Liabilities — Gas purchase options		75,287
Noncurrent gas purchase options (June 2010 - November 2010)	Noncurrent Liabilities — Gas purchase options		14,284

Total			89,571

Total Financial Instruments, net		$	(82,930	)

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide increased price stability for our customers. Accordingly, there is no earnings impact of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives.

The following table presents the impact that financial instruments would have had on our consolidated statements of income for the three and six months ended April 30, 2009, absent the regulatory treatment under our approved PGA procedures.


													Location of (Loss)
	Amount of (Loss) Recognized						Amount of (Loss) Deferred						Recognized through
	on Derivative Instruments						Under PGA Procedures						PGA Procedures
(in thousands)
	Three Months			Six Months			Three Months			Six Months
	Ended			Ended			Ended			Ended
	April 30, 2009			April 30, 2009			April 30, 2009			April 30, 2009
Derivatives Not Designated as Hedging Instruments under Statement 133

Gas purchase options	$	(41,476	)	$	(82,616	)	$	(41,476	)	$	(82,616	)	Cost of Gas


Total	$	(41,476	)	$	(82,616	)	$	(41,476	)	$	(82,616	)

In Tennessee, the cost of these options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our Tennessee Incentive Plan (TIP) approved by the TRA. In South Carolina, the costs of these options are pre-approved by the PSCSC for recovery from customers subject to the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, costs associated with our hedging program are not pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Risk Management

Our OTC derivative financial instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments over and above payments made in the normal course of business when we are in a net liability position. At April 30, 2009, we have one International Swaps and Derivatives Association (ISDA) agreement for the purpose of securing put options as a part of our overall hedging program. The ISDA agreement specifies a net liability exceeding $50 million before we are obligated to post collateral. The net liability extended under this agreement is a function of the credit rating assigned to us by Standard & Poor’s Ratings Services (S&P), which is currently A/stable. In the event of a downgrade in our S&P credit rating to A-, the net liability available to us would decline to $40 million before we would be obligated to post collateral. The aggregate fair value of the derivative instruments that are in a net liability position on April 30, 2009 under the ISDA agreement is $12.6 million, for which we are not required to post collateral. These instruments are acquired under the provisions of our regulatory tariffs. Therefore, should credit-risk-related factors require us to deposit funds as collateral, these amounts would be treated as costs associated with our hedging programs under the recovery mechanism filed with and allowed by each of our state regulators.

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under an Enterprise Risk Management Policy. In addition, we have an Energy Price Risk Management Committee that monitors compliance with our hedging programs, policies and procedures.

Long-Term Debt Instruments

During the six months ended April 30, 2009, we paid $.8 million to noteholders of the 6.25% insured quarterly notes. These notes have a redemption right upon the death of the owner of the notes, within specified limitations.

10.

Short-Term Debt Instruments

We have a syndicated five-year revolving credit facility with aggregate commitments totaling $450 million to meet working capital needs. This facility may be increased up to $600 million and includes annual renewal options and letters of credit. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. The facility provides a line of credit for letters of credit of $5 million, of which $2.4 million and $1.9 million were issued and outstanding at April 30, 2009 and October 31, 2008, respectively. These letters of credit are used to guarantee claims from self-insurance under our general liability policies. The credit facility bears interest based on the 30-day LIBOR rate plus from 15 to 35 basis points, based on our credit ratings.

Effective December 3, 2008, we entered into a syndicated seasonal credit facility with aggregate commitments totaling $150 million. Advances under this seasonal facility bore interest at a rate based on the 30-day LIBOR rate plus from 75 to 175 basis points, based on our credit ratings. This seasonal credit facility expired on March 31, 2009. We entered into this facility to provide lines of credit in addition to the senior revolving credit facility discussed above in order to have additional resources to meet seasonal cash flow requirements and general corporate needs. This seasonal credit facility replaced the two short-term credit facilities with banks for unsecured commitments totaling $75 million that were effective from October 27 and 29, 2008 through December 3, 2008.

As of April 30, 2009 and October 31, 2008, outstanding short-term borrowings under our syndicated credit facility as included in “Notes payable” in the consolidated balance sheets were $205.5 million and $406.5 million, respectively. During the three months ended April 30, 2009,

short-term borrowings ranged from $186.5 million to $448 million, and interest rates ranged from ..67% to 1.67% (weighted average of .74%). During the six months ended April 30, 2009, short-term borrowings ranged from $186.5 million to $556.5 million, and interest rates ranged from .58% to 2.84% (weighted average of 1.05%). Our credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 52% at April 30, 2009.

11.

Employee Share-Based Plans

Under Board of Directors approved incentive compensation plans, eligible officers and other participants are awarded units depending upon the level of performance achieved by Piedmont during multi-year performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed.

The compensation expense related to the incentive compensation plans for the three months and six months ended April 30, 2009 and 2008, and the amounts recorded as liabilities as of April 30, 2009 and October 31, 2008 are presented below.


	Three Months				Six Months
In thousands	2009		2008		2009		2008
Compensation expense	$	1,131	$	959	$	976	$	2,286

	April 30,		October 31,
	2009		2008
Liability	$	6,287	$	10,749

The accrual of compensation expense is based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

Also under our incentive compensation plan, 65,000 restricted shares of our common stock with a value at the date of grant of $1.7 million were granted to our President and Chief Executive Officer on September 1, 2006. During the vesting period, any dividends paid on these shares are accrued and converted into additional shares at the closing price on the date of the dividend payment. The restricted shares and any additional shares accrued through dividends will vest over a five-year period only if he is an employee on each vesting date. We recorded compensation expense under this grant of $84,100 for the three months ended April 30, 2009 and 2008, and $168,300 for the six months ended April 30, 2009 and 2008. We are recording compensation on the straight-line method.

Shares of common stock to be issued under the incentive compensation plans are contingently issuable shares and are included in our calculation of fully diluted earnings per share.

12.		Commitments and Contingent Liabilities

		Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to fifteen years. The time periods for gas supply contracts range from one to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service range from one to three years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the consolidated statements of income as part of gas purchases and included in cost of gas.

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases.

Legal

On March 16, 2009, we filed a lawsuit in the Court of Chancery of the State of Delaware against GNGC, a wholly-owned subsidiary of AGLR. GNGC is our partner in SouthStar. The lawsuit arises from statements in AGLR’s most recently filed Form 10-K, filed with the SEC on February 5, 2009, re-characterizing GNGC’s right to purchase our interest in SouthStar as an “evergreen” right. The suit asks the Court to enter a judgment declaring that GNGC does not have such a perpetual right and that the final option to purchase our interest in SouthStar expires on November 1, 2009. Trial has been set before the Court of Chancery of the State of Delaware on August 25 and 26, 2009.

Other than described above, we have only routine litigation in the normal course of business.

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general liability policies. We had $2.4 million in letters of credit that were issued and outstanding at April 30, 2009. Additional information concerning letters of credit is included in Note 10 to the consolidated financial statements in this Form 10-Q.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded.

In October 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated and paid $5.3 million, charged to the estimated environmental liability, that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources. On one of these nine properties, we performed additional clean-up activities, including the removal of an underground storage tank, in anticipation of an impending sale.

There are three other MGP sites located in Hickory, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated. In addition to these sites, we acquired the liability for an MGP site located in Reidsville, North Carolina, in connection with the acquisition in 2002 of certain assets and liabilities of North Carolina Services, a division of NUI Utilities, Inc.

In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress) prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.

We are continuing to investigate and remediate the Huntersville LNG facility. Our estimate of the total cost to remediate the facility is $1.1 million, of which we have incurred $.7 million through April 30, 2009. For further information about the Huntersville LNG facility, see Note 6 to our Form 10-K for the year ended October 31, 2008.

Further evaluation of the MGP sites and the underground storage tank sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial position, cash flows or results of operations.

During 2008, through the normal course of an on-going business review, one of our operating districts was found to have coatings on their pipelines containing asbestos. We have taken action to educate employees on the hazards of asbestos and to implement procedures for removing these coatings from our pipelines when we must excavate and expose small portions of the pipeline. We continue to determine the impacts and related costs to us, if any, and the impact to employees and contractors, if any.

Additional information concerning commitments and contingencies is set forth in Note 6 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2008.

Other

We have entered into a stipulation and agreement with FERC’s Office of Enforcement regarding certain instances of alleged non-compliance with FERC’s capacity release regulations regarding posting and bidding requirements for short-term releases. The agreement is subject to approval by the FERC and requires us, among other matters, to pay a penalty in settlement of the matter. The penalty, which has been accrued, did not have a material effect on our results of operations.

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

Forward-Looking Statements

This report as well as other 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 affecting us and those from whom we purchase natural gas transportation and storage service, including those that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our ability to earn appropriate rates of return and initiate general rate proceedings as needed.

	•		Residential, commercial, industrial and power generation growth and energy consumption in our service areas. The ability to grow our customer base, the pace of that growth and the levels of energy consumption 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 competitive environment to continue.

	•		The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts or to tariff rates that are at lower per-unit margins than that customer’s existing rate.

	•		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 economic conditions and the cost of funds to finance our capital projects can materially alter the cost and timing of a project.

	•		Access to capital markets. Our internally generated cash flows are not adequate to finance the full cost of capital expenditures. 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 capital markets or our financial condition could affect access to and cost of capital.

	•		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.

	•		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, and could affect our reported earnings or increase our liabilities.

	•		Changes in tax law and regulations. New tax law and regulations may be passed that could affect our reported earnings or increase our liabilities. Producers, marketers and pipelines are subject to changes in tax laws and regulations that increase our exposure to supply and price fluctuations.

	•		Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.

Other factors may be described elsewhere in this report. All of these factors are difficult to predict and many 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.

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 website 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 website as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Executive Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation 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.

In 1994, our predecessor, which was incorporated in 1950 under the same name, was merged into a newly formed North Carolina corporation for the purpose of changing our state of incorporation to North Carolina.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service to Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, 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.

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. Factors critical to the success of the regulated segment include a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. For the six months ended April 30, 2009, 80% of our earnings before taxes came from our regulated utility segment. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas transportation. For further information on business segments, see Note 6 to the consolidated financial statements in this Form 10-Q. For information about our equity method investments, see Note 7 to the consolidated financial statements in this Form 10-Q.

Our utility operations are regulated by the NCUC, the PSCSC and the TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also 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 purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission 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.

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 the opportunity to earn a fair rate of return for our shareholders. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection of margin or recover any under-collection of margin. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered during the months of November through March for residential and commercial customers. 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 margin decoupling mechanism or the WNA.

We continually assess the nature of our business and explore alternatives in our core business of traditional regulated utility service. Non-traditional ratemaking initiatives and market-based pricing of products and services provide additional opportunities and challenges for us. We also regularly evaluate opportunities for obtaining natural gas from different supply regions to diversify our natural gas portfolio.

We are seeing the impacts of the economic recession in our market area with a decline in customer growth in our new construction market and continued customer conservation practices. We are also experiencing a decline in margin in our commercial and industrial markets from lower energy consumption related to company closings and reduced production and business activities. We continue to pursue customer growth opportunities, including residential customer conversions, in our service areas. A further weakening of the economy in our service areas could result in a greater decline in customer additions and energy consumption which could adversely affect our revenues or restrict our future growth.

We have deferred the development and construction of our previously announced LNG peak storage facility in Robeson County, North Carolina based on our current growth projections. Our current growth projections indicate that we may need to resume development of the project in 2011 to prepare for construction in 2012 in order to provide service in 2015. With the uncertain economic outlook, we will monitor customer growth trends in our markets and plan for the development of the project when needed to meet future customer requirements.

Our current customer growth projections for fiscal 2009 are gross customer additions in the range of 1-1.5% and an increase of .5-1% in the number of net customers billed. This compares to fiscal year 2008 gross and net customer increases of approximately 2%.

Under current economic conditions, it may become more difficult for customers to pay their gas bills, leading to slower collections and higher-than-normal levels of accounts receivable and ultimately increasing the non-gas bad debt expense. With a slower turnover of accounts receivable, our level of borrowings could increase in order to meet our working capital needs.

Our strategic focus is on our core business of providing safe, reliable and quality natural gas distribution service to our customers in the growing Southeast market area. Part of our strategic plan is to responsibly manage our gas distribution business through control of our operating costs, implementation of new technologies and sound rate and regulatory initiatives. We are working to enhance the value and growth of our utility assets by good management of capital spending, including improvements for current customers and the pursuit of profitable customer growth opportunities in our service areas. We strive to provide excellent customer service by investing in technology, processes and people. We work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.

We seek to maintain a long-term debt-to-capitalization ratio within a range of 45% to 50%. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

We will continue our efforts to promote natural gas and to inform consumers about the environmental benefits of using natural gas directly in their homes and businesses for the most efficient use of natural gas. This positions us, now and into the future, as an environmentally responsible energy choice for our customers.

We remain focused on implementing and improving our underlying business processes while at the same time monitoring economic and other ongoing developments in order to ensure that our operations and business plan stay in step with these developments.

We invest in joint ventures to complement or supplement income from our regulated utility operations if an opportunity aligns with our overall business strategies and allows us to leverage our core competencies. We analyze and evaluate potential projects 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 our ventures by having management representatives on the governing boards. We monitor actual performance against expectations, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies, or in the case of SouthStar, the exercise of an option by a member to purchase our interest. For further information, see Note 7 to the consolidated financial statements in this Form 10-Q.

Results of Operations

We reported net income of $53.5 million for the three months ended April 30, 2009 as compared to $48.6 million for the same period in 2008. The following table sets forth a comparison of the components of our consolidated statements of income for the three months ended April 30, 2009 as compared with the three months ended April 30, 2008.

Income Statement Components


	Three Months Ended April 30							Percent
In thousands, except per share amounts	2009		2008		Variance			Change
Operating Revenues	$	455,432	$	634,178	$	(178,746	)		(28.2	)%
Cost of Gas		285,479		472,897		(187,418	)		(39.6	)%

Margin		169,953		161,281		8,672			5.4	%

Operations and Maintenance		53,352		53,282		70			0.1	%
Depreciation		24,306		22,893		1,413			6.2	%
General Taxes		8,657		8,407		250			3.0	%
Income Taxes		28,287		24,877		3,410			13.7	%

Total Operating Expenses		114,602		109,459		5,143			4.7	%

Operating Income		55,351		51,822		3,529			6.8	%
Other Income (Expense), net of tax		10,086		10,315		(229	)		(2.2	)%
Utility Interest Charges		11,912		13,513		(1,601	)		(11.8	)%

Net Income	$	53,525	$	48,624	$	4,901			10.1	%


Average Shares of Common Stock:
Basic		73,239		73,418		(179	)		(0.2	)%
Diluted		73,514		73,677		(163	)		(0.2	)%


Earnings Per Share of Common Stock:
Basic	$	0.73	$	0.66	$	0.07			10.6	%
Diluted	$	0.73	$	0.66	$	0.07			10.6	%

We reported net income of $134.4 million for the six months ended April 30, 2009 as compared to $130.9 million for the same period in 2008. The following table sets forth a comparison of the components of our consolidated statements of income for the six months ended April 30, 2009 as compared with the six months ended April 30, 2008.

Income Statement Components


	Six Months Ended April 30							Percent
In thousands, except per share amounts	2009		2008		Variance			Change
Operating Revenues	$	1,235,076	$	1,422,648	$	(187,572	)		(13.2	)%
Cost of Gas		844,440		1,034,341		(189,901	)		(18.4	)%

Margin		390,636		388,307		2,329			0.6	%

Operations and Maintenance		104,077		105,859		(1,782	)		(1.7	)%
Depreciation		48,448		45,598		2,850			6.3	%
General Taxes		17,394		17,153		241			1.4	%
Income Taxes		77,235		75,938		1,297			1.7	%

Total Operating Expenses		247,154		244,548		2,606			1.1	%

Operating Income		143,482		143,759		(277	)		(0.2	)%
Other Income (Expense), net of tax		15,844		15,785		59			0.4	%
Utility Interest Charges		24,925		28,651		(3,726	)		(13.0	)%

Net Income	$	134,401	$	130,893	$	3,508			2.7	%


Average Shares of Common Stock:
Basic		73,280		73,348		(68	)		(0.1	)%
Diluted		73,582		73,617		(35	)		—	%


Earnings Per Share of Common Stock:
Basic	$	1.83	$	1.78	$	0.05			2.8	%
Diluted	$	1.83	$	1.78	$	0.05			2.8	%

Key statistics are shown in the table below for the three months ended April 30, 2009 and 2008.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Three Months Ended
	April 30									Percent
	2009			2008			Variance			Change
Deliveries in Dekatherms (in thousands):
Sales Volumes		34,870			34,869			1			—	%
Transportation Volumes		22,583			19,593			2,990			15.3	%

Throughput		57,453			54,462			2,991			5.5	%

Secondary Market Volumes		9,576			16,052			(6,476	)		(40.3	)%


Customers Billed (at period end)		964,623			963,266			1,357			0.1	%
Gross Customer Additions		2,337			4,481			(2,144	)		(47.8	)%


Degree Days
Actual		1,204			1,163			41			3.5	%
Normal		1,212			1,226			(14	)		(1.1	)%
Percent warmer than normal		0.7	%		5.1	%		n/a			n/a


Number of Employees (at period end)		1,829			1,859			(30	)		(1.6	)%

Key statistics are shown in the table below for the six months ended April 30, 2009 and 2008.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Six Months Ended
	April 30									Percent
	2009			2008			Variance			Change
Deliveries in Dekatherms (in thousands):
Sales Volumes		87,246			84,064			3,182			3.8	%
Transportation Volumes		46,738			42,952			3,786			8.8	%

Throughput		133,984			127,016			6,968			5.5	%

Secondary Market Volumes		22,968			32,137			(9,169	)		(28.5	)%


Customers Billed (at period end)		964,623			963,266			1,357			0.1	%
Gross Customer Additions		6,250			11,644			(5,394	)		(46.3	)%


Degree Days
Actual		3,148			2,918			230			7.9	%
Normal		3,068			3,095			(27	)		(0.9	)%
Percent (colder) warmer than normal		(2.6	)%		5.7	%		n/a			n/a


Number of Employees (at period end)		1,829			1,859			(30	)		(1.6	)%

Operating Revenues

Operating revenues decreased $178.7 million for the three months ended April 30, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$109.8 million from revenues in secondary market transactions due to decreased activity and gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

	•		$56.1 million primarily from commodity and demand costs passed through to sales customers.

	•		$9.2 million from revenues under the margin decoupling mechanism.

	•		$2.5 million of commodity gas costs related to volumes delivered to sales customers.

	•		$1.2 million from a decrease in volumes delivered to transportation customers other than power generation.

	•		$.8 million from revenues under the WNA in South Carolina and Tennessee.

Operating revenues decreased $187.6 million for the six months ended April 30, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$146.8 million from revenues in secondary market transactions due to decreased activity and gas costs.

	•		$30.2 million from revenues under the margin decoupling mechanism.

	•		$22.5 million primarily from commodity and demand costs passed through to sales customers.

	•		$7.6 million from revenues under the WNA in South Carolina and Tennessee.

	•		$2.6 million from a decrease in volumes delivered to transportation customers other than power generation.

These decreases were partially offset by an increase of $22.9 million of commodity gas costs from higher volume deliveries to sales customers.

Cost of Gas

Cost of gas decreased $187.4 million for the three months ended April 30, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$108.9 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

	•		$57.6 million from commodity and demand costs passed through to sales customers.

	•		$2.5 million of commodity gas costs related to volumes delivered to sales customers.

Cost of gas decreased $189.9 million for the six months ended April 30, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$147.1 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

	•		$48.6 million from commodity and demand costs passed through to sales customers.

These decreases were partially offset by an increase of $22.9 million of commodity gas costs from higher volume deliveries to sales customers.

Under 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 consolidated balance sheets.

Margin

Margin increased $8.7 million for the three months ended April 30, 2009 compared with the same period in 2008 primarily due to the following increases:

	•		$4.7 million from net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to regulatory gas cost accounting reviews. This increase reflects $3.3 million of negative adjustments in 2008.

	•		$3.4 million from increased rates approved in the North Carolina general rate case effective November 1, 2008.

	•		$2.2 million from growth and increased volumes in our residential and commercial markets.

These increases were partially offset by $2.4 million from decreased volumes delivered to industrial customers due to the impact of the economic downturn.

Margin increased $2.3 million for the six months ended April 30, 2009 compared with the same period in 2008 primarily due to the following increases:

	•		$4.6 million from increased rates approved in the North Carolina general rate case effective November 1, 2008.

	•		$1.9 million from growth and increased volumes in our residential and commercial markets.

	•		$.8 million from conservation programs in the prior year.

	•		$.3 million from monthly capacity release and off-system sales transactions.

These increases were partially offset by the following decreases:

	•		$4.8 million from decreased volumes delivered to industrial customers.

	��		$.5 million from net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to regulatory gas cost accounting reviews.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impact of volatile wholesale commodity prices and resulting gas costs which are 56% of revenues and transportation and storage costs which are 5% of revenues for the six months ended April 30, 2009.

Our utility margin is impacted also by certain regulatory mechanisms as defined elsewhere in this document and in our Form 10-K for the year ended October 31, 2008. These include WNA in Tennessee and South Carolina, the Natural Gas Rate Stabilization in South Carolina, secondary market activity in North Carolina and South Carolina, TIP in Tennessee, margin decoupling mechanism in North Carolina and negotiated loss treatment and the collection of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.

Operations and Maintenance Expenses

Operations and maintenance expenses were comparable for the three months ended April 30, 2009 compared with the same period in 2008.

Operations and maintenance expenses decreased $1.8 million for the six months ended April 30, 2009 compared with the same period in 2008 primarily due to decreases in employee benefits due to reductions in pension expense from changes in plan design and lower group insurance expense from claims experience and fewer employees.

Depreciation

Depreciation expense increased $1.4 million and $2.9 million for the three months and six months ended April 30, 2009 compared with the same period in 2008, respectively, primarily due to increases in plant in service.

General Taxes

General taxes were comparable for the three months and six months ended April 30, 2009 as compared with the same period in 2008.

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, non-operating income, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and other miscellaneous expenses.

Other Income (Expense) components were comparable for the three months ended April 30, 2009 as compared with the same period in 2008. The primary change to Other Income (Expense) for the six months ended April 30, 2009 as compared with the same period in 2008 was in income from equity method investments. All other changes were insignificant for the period.

Income from equity method investments increased $1.2 million for the six months ended April 30, 2009 as compared with the same period in 2008 primarily due to the following:

	•		$1.8 million increase in earnings from SouthStar primarily due to higher contributions from the management of storage and transportation assets, a 2008 pricing settlement with the Georgia regulatory commission and higher operating margins in Ohio, partially offset by a change in retail pricing plan mix and a decrease in the average number of customers and lower of cost or market inventory adjustments.

	•		$.5 million decrease in earnings from Hardy Storage primarily due to lower revenues and interest income along with higher operations and maintenance expenses and property taxes and the amortization of deferred interest on financing fees.

Utility Interest Charges

Utility interest charges decreased $1.6 million for the three months ended April 30, 2009 compared with the same period in 2008 primarily due to the following:

	•		$1.9 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in the current period.

	•		$.5 million decrease in interest on short-term debt primarily due to the average interest rate of the current period being 250 basis points lower than the prior year period which more than offset higher levels of borrowing in the current period.

	•		$.7 million increase in the allowance for borrowed funds.

Utility interest charges decreased $3.7 million for the six months ended April 30, 2009 compared with the same period in 2008 primarily due to the following:

	•		$2.7 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in the current period.

	•		$2.2 million decrease in interest on short-term debt primarily due to the average interest rate of the current period being 320 basis points lower than the prior year period even though borrowings were higher in the current period.

	•		$1 million increase in the allowance for borrowed funds.

Financial Condition and Liquidity

To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term bank borrowings. We access our short-term credit facilities to finance our working capital needs and growth. Although the credit markets tightened in the latter half of 2008, we believe that these sources, including amounts available to us under our existing facility, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions and dividend payments.

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 purchases and prices, natural gas storage activity, collections from customers 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 winter heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage, seasonal construction activity and decreases in receipts from customers.

During the winter heating season, our accounts payable increase to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to volatility in the price of natural gas, which is a function of market fluctuations in the price of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts and in amounts due to/from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

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 heating bills. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term borrowings to meet current cash requirements.

Because of the economic recession, we may incur additional bad debt expense during the winter heating season, as well as experience increased customer conservation. We may incur more short-term debt to pay for gas supplies and other operating costs, since collections from customers could be slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, will significantly mitigate the impact these factors may have on our results of operations.

Net cash provided by operating activities was $317.3 million and $271.6 million for the six months ended April 30, 2009 and 2008, respectively. Net cash provided by operating activities reflects a $3.5 million increase in net income for 2009 compared with 2008. The effect of changes in working capital on net cash provided by operating activities is described below:

	•		Trade accounts receivable and unbilled utility revenues increased $39.9 million in the current period primarily due to increased amounts billed to customers in 2009 as compared with 2008 due to higher volumes delivered. Volumes sold to residential and commercial customers increased 6.3 million dekatherms as compared with the same prior period primarily due to weather that was 8% colder. Total throughput increased 7 million dekatherms as compared with the same prior period.

	•		Net amounts due from customers increased $49.9 million primarily resulting from realized and unrealized losses on hedging activities, partially offset by decreases for gas cost differences deferred and the impact of the decrease in amounts recorded under the margin decoupling mechanism.

	•		Gas in storage decreased $97.6 million in the current period primarily due to withdrawals from gas in storage and a decrease in the average cost of gas in storage as compared to the prior year.

	•		Prepaid gas costs decreased $63.3 million in the current period primarily due to gas becoming available for sale during the period. Under some gas supply contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the winter heating season.

	•		Trade accounts payable decreased $19.3 million in the current period primarily due to decreased gas costs.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs and fixed and variable non-gas costs and the opportunity to earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA in South Carolina and Tennessee generated credits to customers of $.8 million and charges of $6.8 million in the six months ended April 30, 2009 and 2008, respectively. In Tennessee, adjustments are made directly to individual customer bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in a deferred account for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism reduced margin by $3.8 million and increased margin by $26.4 million in the six months ended April 30, 2009 and 2008, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanism.

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 not significant 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. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

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 electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, reliability and

energy efficiency. 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, with 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. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

In an effort to keep customer rates competitive and to maximize earnings, we continue to implement business process improvement and operations and maintenance cost management programs to capture operational efficiencies while improving customer service.

Cash Flows from Investing Activities. Net cash used in investing activities was $52.7 million and $93.4 million for the six months ended April 30, 2009 and 2008, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the six months ended April 30, 2009 were $52.4 million as compared to $84.5 million in the same prior period primarily due to lower system infrastructure investments consistent with slower customer growth.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Gross utility construction expenditures totaling $172 million are forecasted for 2009, a reduction of $74 million to our original budget. The change in our construction expenditures forecast primarily reflects the deferral of $53 million for the Robeson LNG storage project and the deferral of $18 million for pipeline infrastructure to serve new gas fired power generation markets in North Carolina. We are not contractually obligated to expend capital until the work is completed.

In May 2009, we contributed $.9 million to our Hardy Storage joint venture as part of our equity contribution for construction of the FERC regulated interstate storage facility.

Cash Flows from Financing Activities. Net cash used in financing activities was $251 million and $176.2 million for the six months ended April 30, 2009 and 2008, 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 may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to pay down outstanding short-term borrowings, to repurchase common stock under the common stock repurchase program and to pay quarterly dividends on our common stock. As of April 30, 2009, our current assets were $548.7 million and our current liabilities were $511.8 million primarily due to seasonal requirements as discussed above.

As of April 30, 2009, we had committed lines of credit under our syndicated credit facility of $450 million with the ability to expand up to $600 million, for which we pay an annual fee of $35,000

plus six basis points for any unused amount up to $450 million. Outstanding short-term borrowings decreased from $406.5 million as of October 31, 2008 to $205.5 million as of April 30, 2009 primarily due to the collections of amounts that had been billed to customers during the winter months, partially offset by the purchase of shares under our ASR program, payments for interest on long-term debt and property taxes and payments to suppliers for the winter heating season. During the six months ended April 30, 2009, short-term borrowings ranged from $186.5 million to $556.5 million, and interest rates ranged from .58% to 2.84% (weighted average of 1.05%).

As of April 30, 2009, under our syndicated credit facility, we had available letters of credit of $5 million of which $2.4 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general liability policies. As of April 30, 2009, unused lines of credit available under our syndicated credit facility, including the issuance of the letters of credit, totaled $242.1 million.

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 and hedging transactions 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 fluctuate.

Due to the economic downturn and lower customer growth projections, we have delayed the Robeson County LNG project, as well as other capital expenditures as mentioned above. At this time, we do not anticipate issuing long-term debt in fiscal 2009. However, we will continue to monitor customer growth trends in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt.

During the six months ended April 30, 2009, we issued $7.6 million of common stock through dividend reinvestment and stock purchase plans.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program and our ASR program as described in Part II, Item 2 of this Form 10-Q. On March 6, 2009, the Board of Directors authorized the consolidation of these programs and the repurchase of up to an additional 4 million shares. Upon this authorization, 7,010,074 shares were available for repurchase. Such shares will be cancelled and become authorized but unissued shares available for issuance under our dividend reinvestment, employee stock purchase and incentive compensation plans.

On March 20, 2009, through an ASR agreement with an investment bank, we repurchased and retired 700,000 shares of common stock for $18.4 million. On April 21, 2009, final settlement of the transaction occurred, and we received cash of $.6 million from the investment bank.

We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of April 30, 2009, our retained earnings were not restricted. On June 5, 2009, the Board of Directors declared a quarterly dividend on common stock of $.27 per share, payable July 15, 2009 to shareholders of record at the close of business on June 25, 2009.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are

necessary to maintain attractive credit ratings. As of April 30, 2009, our capitalization, including current maturities of long-term debt, consisted of 46% in long-term debt and 54% in common equity.

The components of our total debt outstanding (short-term debt and long-term debt) to our total capitalization as of April 30, 2009 and 2008, and October 31, 2008, are summarized in the table below.


	April 30					October 31					April 30
In thousands	2009		Percentage			2008		Percentage			2008		Percentage
Short-term debt	$	205,500		10	%	$	406,500		19	%	$	78,500		4	%
Current portion of long-term debt		30,000		1	%		30,000		1	%		—		—	%
Long-term debt		793,471		40	%		794,261		38	%		824,713		45	%

Total debt		1,028,971		51	%		1,230,761		58	%		903,213		49	%
Common stockholders’ equity		969,852		49	%		887,244		42	%		951,130		51	%

Total capitalization (including short-term debt)	$	1,998,823		100	%	$	2,118,005		100	%	$	1,854,343		100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flows relative to outstanding debt, capital expenditures, operating cash flow coverage of interest and pension liabilities and funding status. Rating agencies also consider qualitative factors, such as the consistency of our earnings over time, the quality of management, corporate governance and business strategy, the risks associated with our utility and non-utility businesses and the regulatory commissions that establish rates in the states where we operate.

As of April 30, 2009, all of our long-term debt was unsecured. Our long-term debt is rated “A” by S&P and “A3” by Moody’s Investors Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all our debt agreements. As of April 30, 2009, there has been no event of default giving rise to acceleration of our debt.

Estimated Future Contractual Obligations

During the three months ended April 30, 2009, 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, 2008, 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 and letters of credit that were discussed in Note 6 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2008 and the credit extended by our counterparty in OTC derivative contracts as discussed in Note 8 to the consolidated financial statements in this Form 10-Q.

Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our consolidated balance sheets. We have recorded an estimated liability of $1.2 million as of April 30, 2009 and October 31, 2008, respectively. The possibility of having to perform on the guaranty is largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 7 to the consolidated financial statements in this Form 10-Q.

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, 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, 2008, 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, 2008.

Recent Accounting Pronouncements

effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since this staff position only requires additional disclosures about plan assets of defined benefit pension and other postretirement plans, it is not expected to have a material impact on our financial position, results of operations or cash flows. We will adopt FSP FAS 132(R)-1 during our fiscal year ending October 31, 2010.

In April 2009, the FASB issued FSP FAS 107-1 and Accounting Principles Board (APB) APB 28-1, “Interim Disclosures about Fair Values of Financial Instruments,” that amends SFAS 107, “Disclosures about Fair Values of Financial Instruments” (Statement 107), and requires that publicly traded companies disclose the fair value of financial instruments during interim reporting, in addition to the information provided annually. It also amends APB Opinion No. 28, “Interim Financial Reporting,” to require the interim disclosures. This FSP is effective for periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted FSP FAS 107-1 and APB 28-1 this quarter. Comparative information is not required at initial adoption. The disclosure requirements are presented in “Fair Value Measurements” in Note 8 to the consolidated financial statements in this Form 10-Q.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (Statement 165). Statement 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before the date that the financial statements are issued or are available to be issued. It requires disclosure of the date through which an entity has evaluated subsequent events. Statement 165 is effective for interim and annual periods ending after June 15, 2009. We do not expect Statement 165 to have a material impact on our financial position, results of operations or cash flows. We will adopt Statement 165 during the period ending July 31, 2009.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various forms of market risk, including the credit risk of our suppliers and our customers, interest rate risk, commodity price risk and weather risk. We seek to identify, assess, monitor and manage market risk and credit risk in accordance with defined policies and procedures under an Enterprise Risk Management Policy and with the direction of the Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors’ oversight, and senior management takes an active role in the development of policies and procedures.

We hold all financial instruments discussed below for purposes other than trading.

Credit Risk

We enter into contracts with third parties to buy and sell natural gas. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. The policy specifies limits on the contract amount and duration based on the counterparty’s credit rating. The

policy is also designed to mitigate credit risks through a requirement for credit enhancements that include letters of credit or parent guaranties. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy any supply or demand contractual obligations that were incurred while under the management of this third party.

We have mitigated exposure to the risk of non-payment of utility bills by customers. In North Carolina and South Carolina, gas costs related to uncollectible accounts are recovered through PGA procedures. In Tennessee, the gas cost portion of net write-offs for a fiscal year that exceed the gas cost portion included in base rates is recovered through PGA procedures. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from those customers that do not satisfy our predetermined credit standards. Significant increases in the price of natural gas can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of April 30, 2009, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.

We have short-term borrowing arrangements to provide working capital and general corporate liquidity. The level of borrowings under such arrangements varies from period to period depending upon many factors, including the cost of wholesale natural gas and our gas supply hedging programs, our investments in capital projects, the level and expense of our storage inventory and the collection of receivables. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.

As of April 30, 2009, we had $205.5 million of short-term debt outstanding under our syndicated credit facility at a weighted average interest rate of .71%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $.7 million during the three months ended April 30, 2009 and $2.8 million during the six months ended April 30, 2009.

Commodity Price Risk

We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner. As such, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures,

differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts due from customers” or any over-recoveries are included in “Amounts due to customers” in our consolidated balance sheets for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers.

We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize over-the-counter and New York Mercantile Exchange (NYMEX) exchange-traded instruments of various durations for the forward purchase of a portion of our natural gas requirements, subject to regulatory review and approval.

Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. Costs have never been disallowed in any jurisdiction.

Weather Risk

We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. In these states, this risk is mitigated by WNA mechanisms that are designed to offset the impact of colder-than-normal or warmer-than-normal weather in our residential and commercial markets. In North Carolina, we manage our weather risk through a margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold.

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.

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, the President and Chief Executive Officer and the Senior Vice President 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 and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

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 were 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 second quarter of fiscal 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

We have only routine litigation in the normal course of business.

Item 1A. Risk Factors

During the six months ended April 30, 2009, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2008.

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, including the accelerated stock repurchase program, during the three months ended April 30, 2009.


					Total Number of		Maximum Number
	Total Number				Shares Purchased		of Shares that May
	of Shares		Average Price		as Part of Publicly		Yet be Purchased
Period	Purchased		Paid Per Share		Announced Program		Under the Program *
Beginning of the period								3,010,074
02/01/09 - 02/28/09		—	$	—		—		3,010,074
03/01/09 - 03/31/09		700,000	$	25.51		700,000		6,310,074
04/01/09 - 04/30/09		—	$	—		—		6,310,074

Total		700,000	$	25.51		700,000


*		The Common Stock Open Market Purchase Program was approved by the Board of Directors and 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 on that date an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock 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 additional four million shares are referred to as our accelerated share repurchase program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings

available for restricted payments. As of April 30, 2009, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 4. Submission of Matters to a Vote of Security Holders

We held our Annual Meeting of Shareholders on March 6, 2009 to elect four directors, to ratify the selection of our independent registered public accounting firm and to approve an amendment to our Articles of Incorporation eliminating the classified structure of the Board of Directors. The record date for determining the shareholders entitled to receive notice of and to vote at the meeting was January 7, 2009. We solicited proxies for the meeting according to section 14(a) of the Securities and Exchange Act of 1934. There was no solicitation in opposition to management’s solicitations.

Shareholders elected all of the nominees for director as listed in the proxy statement by the following votes:


	Voted		Voted		NOT
	FOR		WITHHELD		VOTED
For terms expiring in 2012:
E. James Burton		59,490,910		1,053,625		12,811,527
John W. Harris		51,937,954		8,606,581		12,811,527
Aubrey B. Harwell, Jr.		59,452,459		1,092,076		12,811,527
David E. Shi		59,509,860		1,034,675		12,811,527

The current terms of continuing directors Jerry W. Amos, Vicki McElreath, Thomas E. Skains and Frankie T. Jones, Sr. will expire at our annual meeting in 2010. The current terms of continuing directors Malcolm E. Everett III, Muriel W. Sheubrooks, Frank B. Holding, Jr., and Minor M. Shaw will expire at our annual meeting in 2011.

Shareholders ratified the selection by the Board of Directors of the firm Deloitte & Touche LLP as our independent public accounting firm for the fiscal year ending October 31, 2009, by the following vote:


Voted	Voted	Voted	Non-	NOT
FOR	AGAINST	ABSTAINING	Votes	VOTED
59,510,158	739,784	294,593	-	12,811,527

An affirmative vote of at least 80% of the outstanding shares entitled to vote in the election of directors was required to adopt the proposed amendment to our articles of incorporation to eliminate classification of the Board of Directors. The proposal received less than the 80% affirmative vote required for its adoption and was not approved by the following vote:


Voted	Voted	Voted	Non-	NOT
FOR	AGAINST	ABSTAINING	Votes	VOTED
57,950,700	1,513,425	1,080,397	13	12,811,527

Item 6. Exhibits

Compensatory Contracts:

10.1		Piedmont Natural Gas Company Employee Stock Purchase Plan, amended and restated as of April 1, 2009 (Exhibit 4.1, Form 8-K dated April 13, 2009).

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.

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)

DateJune 5, 2009		/s/ David J. Dzuricky
		David J. Dzuricky Senior Vice President and Chief Financial Officer (Principal Financial Officer)

DateJune 5, 2009		/s/ Jose M. Simon
		Jose M. Simon Vice President and Controller (Principal Accounting Officer)

Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended April 30, 2009

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Good

Piedmont Natural Gas (PNY) 10-Q2009 Q1 Quarterly report

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