e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended July 31, 2009


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 Number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)


North Carolina		56-0556998

(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


4720 Piedmont Row Drive, Charlotte, North Carolina		28210

(Address of principal executive offices)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ 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 filer þ

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ 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 August 31, 2009

Common Stock, no par value		73,110,548

Part I. Financial Information

Item 1. Financial Statements

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


	July 31,		October 31,
	2009		2008

ASSETS
Utility Plant:
Utility plant in service	$	3,043,513	$	2,997,186
Less accumulated depreciation		864,097		813,822

Utility plant in service, net		2,179,416		2,183,364
Construction work in progress		81,883		57,470
Plant held for future use		6,751		—

Total utility plant, net		2,268,050		2,240,834

Other Physical Property, at cost (net of accumulated
depreciation of $2,462 in 2009 and $2,351 in 2008)		754		864


Current Assets:
Cash and cash equivalents		13,219		6,991
Trade accounts receivable (less allowance for doubtful
accounts of $1,949 in 2009 and $1,066 in 2008)		76,211		82,346
Income taxes receivable		27,821		731
Other receivables		4,287		393
Unbilled utility revenues		10,801		51,819
Inventories:
Gas in storage		107,668		190,275
Materials, supplies and merchandise		5,357		6,524
Gas purchase options, at fair value		4,660		22,645
Amounts due from customers		208,970		181,745
Prepayments		35,332		79,831
Other		96		96

Total current assets		494,422		623,396


Noncurrent Assets:
Equity method investments in non-utility activities		101,748		99,214
Goodwill		48,852		48,852
Marketable securities, at fair value		421		—
Overfunded postretirement asset		28,634		6,797
Regulatory asset for postretirement benefits		29,879		28,732
Gas purchase options, at fair value		1,979		32,434
Unamortized debt expense		9,357		9,915
Regulatory cost of removal asset		6,958		6,398
Other		44,472		40,965

Total noncurrent assets		272,300		273,307


Total	$	3,035,526	$	3,138,401

See notes to consolidated financial statements.


	July 31,			October 31,
	2009			2008
(In thousands)

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: 73,092 in 2009 and 73,246 in 2008		467,511			471,565
Paid-in capital		1,192			763
Retained earnings		482,616			414,246
Accumulated other comprehensive income (loss)		(3,413	)		670

Total stockholders’ equity		947,906			887,244
Long-term debt		792,815			794,261

Total capitalization		1,740,721			1,681,505


Current Liabilities:
Current maturities of long-term debt		30,000			30,000
Notes payable		257,500			406,500
Trade accounts payable		50,784			91,142
Other accounts payable		26,916			45,148
Income taxes accrued		—			4,414
Accrued interest		11,887			22,777
Customers’ deposits		24,165			23,881
Deferred income taxes		31,595			6,878
General taxes accrued		14,149			18,932
Gas purchase options, at fair value		49,440			42,205
Other		5,136			12,300

Total current liabilities		501,572			704,177


Noncurrent Liabilities:
Deferred income taxes		345,099			305,362
Unamortized federal investment tax credits		2,378			2,626
Regulatory liability for postretirement benefits		372			372
Accumulated provision for postretirement benefits		17,129			16,257
Cost of removal obligations		387,745			367,450
Gas purchase options, at fair value		4,604			22,177
Other		35,906			38,475

Total noncurrent liabilities		793,233			752,719


Commitments and Contingencies (Note 11)


Total	$	3,035,526		$	3,138,401

See notes to consolidated financial statements.

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


	Three Months Ended						Nine Months Ended
	July 31						July 31
	2009			2008			2009			2008

Operating Revenues	$	180,201		$	354,709		$	1,415,276		$	1,777,357
Cost of Gas		99,362			277,689			943,802			1,312,031


Margin		80,839			77,020			471,474			465,326


Operating Expenses:
Operations and maintenance		50,124			49,738			154,200			155,598
Depreciation		24,488			23,581			72,937			69,179
General taxes		8,841			7,928			26,235			25,080
Income taxes		(4,199	)		(6,846	)		73,035			69,092


Total operating expenses		79,254			74,401			326,407			318,949


Operating Income		1,585			2,619			145,067			146,377


Other Income (Expense):
Income from equity method investments		3,828			4,278			31,449			30,730
Non-operating income (loss)		(51	)		(87	)		(149	)		541
Non-operating expense		(749	)		(251	)		(1,955	)		(1,317	)
Income taxes		(866	)		(1,410	)		(11,339	)		(11,638	)


Total other income (expense)		2,162			2,530			18,006			18,316


Utility Interest Charges:
Interest on long-term debt		13,829			13,866			41,500			41,588
Allowance for borrowed funds used during construction		(483	)		(1,288	)		(1,710	)		(3,473	)
Other		(2,299	)		249			(3,818	)		3,364

Total utility interest charges		11,047			12,827			35,972			41,479


Net Income (Loss)	$	(7,300	)	$	(7,678	)	$	127,101		$	123,214


Average Shares of Common Stock:
Basic		72,983			73,368			73,180			73,355
Diluted		72,983			73,368			73,476			73,628

Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.10	)	$	1.74		$	1.68
Diluted	$	(0.10	)	$	(0.10	)	$	1.73		$	1.67

Cash Dividends Per Share of Common Stock	$	0.27		$	0.26		$	0.80		$	0.77

See notes to consolidated financial statements.

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


	Nine Months Ended
	July 31
	2009			2008
Cash Flows from Operating Activities:
Net income	$	127,101		$	123,214
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		76,827			72,504
Amortization of investment tax credits		(248	)		(275	)
Allowance for doubtful accounts		883			1,816
Gain on sale of property		(418	)		(201	)
Earnings from equity method investments		(31,449	)		(30,730	)
Distributions of earnings from equity method investments		22,750			33,041
Deferred income taxes		67,083			45,413
Stock-based compensation expense		252			252
Changes in assets and liabilities:
Gas purchase options, at fair value		38,102			10,504
Receivables		42,376			(9,501	)
Inventories		83,774			(38,077	)
Amounts due from customers		(27,225	)		2,648
Settlement of legal asset retirement obligations		(1,127	)		(960	)
Overfunded postretirement asset		(21,837	)		(9,390	)
Regulatory asset for postretirement benefits		(1,147	)		500
Other assets		12,146			26,867
Accounts payable		(56,141	)		32,665
Amounts due to customers		—			6,886
Regulatory liability for postretirement benefits		—			(1,420	)
Provision for postretirement benefits		872			569
Other liabilities		(26,480	)		(12,200	)

Net cash provided by operating activities		306,094			254,125


Cash Flows from Investing Activities:
Utility construction expenditures		(83,208	)		(140,952	)
Allowance for funds used during construction		(1,710	)		(3,473	)
Contributions to equity method investments		(862	)		(10,790	)
Distributions of capital from equity method investments		315			121
Proceeds from sale of property		644			2,043
Decrease in restricted cash		—			2,196
Investment in marketable securities		(373	)		—
Other		1,258			1,593

Net cash used in investing activities		(83,936	)		(149,262	)


Cash Flows from Financing Activities:
Decrease in notes payable, net		(149,000	)		(26,000	)
Retirement of long-term debt		(1,446	)		(354	)
Expenses related to expansion of the short-term facility		—			(106	)
Issuance of common stock through dividend reinvestment and employee stock plans		11,048			11,637
Repurchases of common stock		(17,857	)		(36,228	)
Dividends paid		(58,624	)		(56,474	)
Other		(51	)		—

Net cash used in financing activities		(215,930	)		(107,525	)


Net Increase (Decrease) in Cash and Cash Equivalents		6,228			(2,662	)
Cash and Cash Equivalents at Beginning of Period		6,991			7,515

Cash and Cash Equivalents at End of Period	$	13,219		$	4,853


Noncash Investing and Financing Activities:
Accrued construction expenditures	$	2,449		$	908
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						Nine Months Ended
	July 31						July 31
	2009			2008			2009			2008

Net Income (Loss)	$	(7,300	)	$	(7,678	)	$	127,101		$	123,214

Other Comprehensive Income:
Unrealized (loss) gain from hedging activities of equity method investments, net of tax of ($257) and $524 for the three months ended July 31, 2009 and 2008, respectively, and ($3,626) and $994 for the nine months ended July 31, 2009 and 2008, respectively		(400	)		814			(5,629	)		1,552
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $1,253 and ($263) for the three months ended July 31, 2009 and 2008, respectively, and $997 and ($1,059) for the nine months ended July 31, 2009 and 2008, respectively		1,946			(411	)		1,546			(1,652	)


Total Comprehensive Income (Loss)	$	(5,754	)	$	(7,275	)	$	123,018		$	123,114

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 (GAAP) 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 July 31, 2009 and October 31, 2008, the results of operations for the three months and nine months ended July 31, 2009 and 2008, and cash flows for the nine months ended July 31, 2009 and 2008. Our business is seasonal in nature. The results of operations for the three months and nine months ended July 31, 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 nine months ended July 31, 2009 other than the adoption of Financial Accounting Standards Board (FASB) Staff Position (FSP) FSP FIN 39-1. For further information on the adoption of FSP FIN 39-1, see Note 7 to the consolidated financial statements in this Form 10-Q.

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated through the filing date of this Form 10-Q. There are no subsequent events that would have a material impact on our financial position, results of operations or cash flows.

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 expenditures associated with the

LNG facility as “Plant held for future use” in the consolidated balance sheets. The amount classified as 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 July 31, 2009 and October 31, 2008 are as follows.


	July 31,		October 31,
In thousands	2009		2008

Regulatory Assets	$	294,040	$	263,205
Regulatory Liabilities		403,481		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 6 to the consolidated financial statements in this Form 10-Q.

Accounting Pronouncements

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.

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 adopted Statement 165 for the period ended July 31, 2009. It had no impact on our financial position, results of operations or cash flows as the result of our evaluation through the filing date for this Form 10-Q.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (Statement 168). The FASB Accounting Standards Codification (ASC) will become the source of authoritative U.S. GAAP recognized by the FASB applicable to nongovernmental entities. On the effective date of Statement 168, the ASC will supersede all existing non-SEC accounting and reporting standards. Statement 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Statement 168 will not have any impact on our financial position, results of operations or cash flows since the ASC does not change GAAP for public nongovernmental entities. We will adopt Statement 168 during the period ending October 31, 2009 and modify any GAAP references.

2. Regulatory Matters

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

On August 3, 2009, we filed testimony with the North Carolina Utilities Commission (NCUC) in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2009. A hearing has been scheduled for October 6, 2009. We are unable to predict the outcome of this proceeding at this time.

On August 12, 2009, the Public Service Commission of South Carolina (PSCSC) approved our purchased gas adjustments and found our gas purchasing policies to be prudent for the period covering the twelve months ended March 31, 2009.

On June 15, 2009, we filed a cost and revenue study as permitted by the Natural Gas Rate Stabilization Act with the PSCSC requesting a change in rates from those approved by the PSCSC in an order dated October 14, 2008. On September 1, 2009, we and the Office of Regulatory Staff filed a settlement agreement with the PSCSC addressing our proposed rate changes. The settlement, if approved, will result in a $1.1 million increase in margin based on a return on equity of 11.2%, effective November 1, 2009. The settlement is pending approval by the PSCSC. We are unable to predict the outcome of this proceeding at this time.

On July 16, 2009, we filed a petition with the Tennessee Regulatory Authority (TRA) requesting approval to decouple residential rates in Tennessee and to offer three energy efficiency programs to residential customers. We are proposing a margin decoupling tracker mechanism that is designed to allow us to recover from our residential customers the approved per customer margin as approved in our last general rate proceeding. The proposed energy efficiency programs in Tennessee are designed to promote energy conservation and efficiency by residential customers and are similar to approved energy efficiency programs in North Carolina. We propose to initially spend $.5 million annually on these programs with shareholder contributions of $.25 million in year one, $.15 million in year two and $.07 million in year three of the programs. We have requested an effective date of September 1, 2009. On August 24, 2009, the TRA suspended the tariff and established a contested case to address the filing. We are unable to predict the outcome of this proceeding at this time.

On July 1, 2009, we filed an annual report for the twelve months ended December 31, 2008 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment mechanism. We are unable to predict the outcome of this proceeding at this time.

3. 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 nine months ended July 31, 2009 and 2008 is presented below.


	Three Months						Nine Months
In thousands except per share amounts	2009			2008			2009		2008

Net Income (Loss)	$	(7,300	)	$	(7,678	)	$	127,101	$	123,214


Average shares of common stock outstanding for basic earnings per share		72,983			73,368			73,180		73,355
Contingently issuable shares under incentive compensation plans *		—			—			296		273

Average shares of dilutive stock		72,983			73,368			73,476		73,628


Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.10	)	$	1.74	$	1.68
Diluted	$	(0.10	)	$	(0.10	)	$	1.73	$	1.67


*		For the three months ended July 31, 2009 and 2008, the inclusion of 276 and 268 contingently issuable shares, respectively, would have been antidilutive.

4. 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 applied 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 July 31, 2009 and 2008 are presented below.


	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2009			2008			2009		2008		2009			2008
Service cost	$	1,325		$	1,400		$	6	$	7	$	(56	)	$	304
Interest cost		2,929			2,886			81		69		541			489
Expected return on plan assets		(4,290	)		(4,382	)		—		—		25			(355	)
Amortization of transition obligation		—			—			—		—		167			162
Amortization of prior service (credit) cost		(549	)		(464	)		5		—		—			—

Total	$	(585	)	$	(560	)	$	92	$	76	$	677		$	600

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2009 and 2008 are presented below.


	Qualified Pension						Nonqualified Pension					Other Benefits
In thousands	2009			2008			2009			2008		2009			2008
Service cost	$	4,300		$	5,726		$	19		$	20	$	664		$	938
Interest cost		8,430			8,556			244			208		1,700			1,508
Expected return on plan assets		(12,567	)		(12,671	)		—			—		(827	)		(1,096	)
Amortization of transition obligation		—			—			—			—		500			500
Amortization of prior service (credit) cost		(1,648	)		(1,420	)		15			—		—			—
Amortization of actuarial gain		—			—			(15	)		—		—			—

Total	$	(1,485	)	$	191		$	263		$	228	$	2,037		$	1,850

We contributed $87,000 to the money purchase pension plan in February 2009 and $22 million to the qualified pension plan in July 2009. We anticipate that we will contribute the following amounts to our other plans in 2009.


	In thousands

Nonqualified pension plans	$	504
OPEB plan		3,400

We have a defined contribution restoration plan that we fund annually and that covers all officers at the vice president level and above. For the nine months ended July 31, 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 July 31, 2009, we have a liability of $.6 million for these plans.

See Note 7 to the consolidated financial statements of this Form 10-Q for information on the investments in marketable securities that are held in the trust.

5. 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 operations. Operations of the non-utility activities segment are included in the consolidated statements of operations 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 nine months ended July 31, 2009 and 2008 are presented below.


	Regulated						Non-utility
	Utility						Activities						Total
In thousands	2009			2008			2009			2008			2009			2008

Three Months
Revenues from external customers	$	180,201		$	354,709		$	—		$	—		$	180,201		$	354,709
Margin		80,839			77,020			—			—			80,839			77,020
Operations and maintenance expenses		50,124			49,738			198			60			50,322			49,798
Income from equity method investments		—			—			3,828			4,278			3,828			4,278
Operating loss before income taxes		(2,614	)		(4,227	)		(267	)		(34	)		(2,881	)		(4,261	)
Income (loss) before income taxes		(14,206	)		(17,250	)		3,573			4,136			(10,633	)		(13,114	)

Nine Months
Revenues from external customers	$	1,415,276		$	1,777,357		$	—		$	—		$	1,415,276		$	1,777,357
Margin		471,474			465,326			—			—			471,474			465,326
Operations and maintenance expenses		154,200			155,598			275			128			154,475			155,726
Income from equity method investments		—			—			31,449			30,730			31,449			30,730
Operating income (loss) before income taxes		218,102			215,469			(444	)		(237	)		217,658			215,232
Income before income taxes		180,474			173,784			31,001			30,160			211,475			203,944

Reconciliations to the consolidated statements of operations for the three months and nine months ended July 31, 2009 and 2008 are presented below.


	Three Months						Nine Months
In thousands	2009			2008			2009			2008
Operating Income:
Segment operating income (loss) before income taxes	$	(2,881	)	$	(4,261	)	$	217,658		$	215,232
Utility income taxes		4,199			6,846			(73,035	)		(69,092	)
Non-utility activities before income taxes		267			34			444			237

Operating income	$	1,585		$	2,619		$	145,067		$	146,377


Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(10,633	)	$	(13,114	)	$	211,475		$	203,944
Income taxes		3,333			5,436			(84,374	)		(80,730	)

Net income (loss)	$	(7,300	)	$	(7,678	)	$	127,101		$	123,214

6. 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 operations.

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 nine months ended July 31, 2009 and 2008, these transportation costs and the amounts we owed Cardinal as of July 31, 2009 and October 31, 2008 are as follows.


	Three Months				Nine Months
In thousands	2009		2008		2009		2008

Transportation costs	$	1,035	$	1,035	$	3,070	$	3,081


	July 31,		October 31,
	2009		2008

Trade accounts payable	$	349	$	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 nine months ended July 31, 2009 and 2008, these gas storage costs and the amounts we owed Pine Needle as of July 31, 2009 and October 31, 2008 are as follows.


	Three Months				Nine Months
In thousands	2009		2008		2009		2008

Gas storage costs	$	3,207	$	3,022	$	9,157	$	8,493


	July 31,		October 31,
	2009		2008

Trade accounts payable	$	1,081	$	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, which we believe will expire on November 1, 2009. On July 29, 2009, we restructured the ownership interests in SouthStar. Under the terms of the new agreement, we will sell half of our 30% membership interest in SouthStar to GNGC effective January 1, 2010, retaining a 15% earnings and membership share in SouthStar after the sale. At closing, we will receive $57.5 million from GNGC resulting in an estimated after-tax gain of $30 million in 2010 or $.41 per diluted share. The agreement, which has been approved by both companies’ boards of directors, also resolves issues concerning GNGC’s option to purchase our ownership interest in SouthStar. As part of the agreement, GNGC will not have any further option rights to our remaining 15% interest. The agreement is subject to the approval and consent of the Georgia Public Service Commission (Georgia PSC). For further information, see Note 11 to the consolidated financial statements 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 nine months ended July 31, 2009 and 2008, our operating revenues from these sales and the amounts SouthStar owed us as of July 31, 2009 and October 31, 2008 are as follows.


	Three Months				Nine Months
In thousands	2009		2008		2009		2008

Operating revenues	$	1,459	$	4,826	$	6,638	$	11,055


	July 31,		October 31,
	2009		2008

Trade accounts receivable	$	534	$	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 nine months ended July 31, 2009, we have made equity contributions of $.9 million 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 July 31, 2009 and October 31, 2008 are as follows.


	July 31,		October 31,
In thousands	2009		2008

Guaranty liability — PEP	$	1,234	$	1,234
Amount outstanding under the construction financing — Hardy Storage		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 nine months ended July 31, 2009 and 2008, our gas storage costs and the amounts we owed Hardy Storage as of July 31, 2009 and October 31, 2008 are as follows.


	Three Months				Nine Months
In thousands	2009		2008		2009		2008

Gas storage costs	$	2,344	$	2,326	$	6,996	$	6,898


	July 31,		October 31,
	2009		2008

Trade accounts payable	$	781	$	774

7. 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. 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 on November 1, 2008. 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 $57.7 million and $67.3 million as of July 31, 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.

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 for our financial assets and liabilities 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 have determined that the impact on our financial position, results of operations and cash flows will not be material.

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 July 31, 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 July 31, 2009


			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable		Total
	Markets		Inputs		Inputs		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Value
Assets:
Derivatives held for distribution operations	$	6,639	$	—	$	—	$	6,639
Debt and equity securities held as trading securities		421		—		—		421

Total fair value assets	$	7,060	$	—	$	—	$	7,060

Liabilities:
Derivatives held for distribution operations	$	53,478	$	566	$	—	$	54,044

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 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.

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 July 31, 2009	$	822,815	$	940,245
As of October 31, 2008		824,261		798,057

Quantitative and Qualitative Disclosures

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 SFAS No. 107, “Disclosures about Fair Values of Financial Instruments” (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 July 31, 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 July 31, 2009, we had long gas options of 96.1 million dekatherms and short gas options of 51.4 million dekatherms providing total coverage of 62.5 million dekatherms over the period from September 2009 through November 2010.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of July 31, 2009.

Fair Value of Derivative Instruments as of July 31, 2009


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

Asset Financial Instruments
Current gas purchase options (Sept. 2009 — August 2010)	Current Assets — Gas purchase options	$	4,660
Noncurrent gas purchase options (Sept. 2010 — November 2010)	Noncurrent Assets — Gas purchase options		1,979

Total			6,639


Liability Financial Instruments
Current gas purchase options (Sept. 2009 — August 2010)	Current Liabilities — Gas purchase options		49,440
Noncurrent gas purchase options (Sept. 2010 — November 2010)	Noncurrent Liabilities — Gas purchase options		4,604

Total			54,044


Total Financial Instruments, net		$	(47,405	)

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 operations for the three and nine months ended July 31, 2009, absent the regulatory treatment under our approved PGA procedures.


	Amount of (Loss) Recognized						Amount of (Loss) Deferred
	on Derivative Instruments						Under PGA Procedures
	Three Months			Nine Months			Three Months			Nine Months			Location of (Loss)
	Ended			Ended			Ended			Ended			Recognized through
(in thousands)	July 31, 2009			July 31, 2009			July 31, 2009			July 31, 2009			PGA Procedures
Derivatives Not Designated as Hedging Instruments under Statement 133

Gas purchase options	$	(36,632	)	$	(119,248	)	$	(36,632	)	$	(119,248	)	Cost of Gas


Total	$	(36,632	)	$	(119,248	)	$	(36,632	)	$	(119,248	)

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 July 31, 2009, we have four International Swaps and Derivatives Association (ISDA) agreements for the purpose of securing put options as a part of our overall hedging program. The ISDA agreements specify a net liability of $50 million, $30 million, $25 million and $2 million before we are obligated to post collateral. The net liability extended under the agreements 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 $92 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 July 31, 2009 under one ISDA agreement is $.6 million of a total net authorized liability of $50 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.

8. Long-Term Debt Instruments

During the nine months ended July 31, 2009, we paid $1.4 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.

9. Short-Term Debt Instruments

We have a syndicated five-year revolving credit facility that expires April 2011 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 July 31, 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 July 31, 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 $257.5

million and $406.5 million, respectively. During the three months ended July 31, 2009, short-term borrowings ranged from $131.5 million to $271 million, and interest rates ranged from .53% to .67% (weighted average of .57%). During the nine months ended July 31, 2009, short-term borrowings ranged from $131.5 million to $556.5 million, including amounts borrowed under a seasonal credit facility that expired March 31, 2009, and interest rates ranged from .53% to 2.84% (weighted average of .95%). 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 53% at July 31, 2009.

10. Employee Share-Based Plans

Under Board of Directors approved incentive compensation plans, eligible officers and other participants are awarded units that pay out 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 nine months ended July 31, 2009 and 2008, and the amounts recorded as liabilities as of July 31, 2009 and October 31, 2008 are presented below.


	Three Months				Nine Months
In thousands	2009		2008		2009		2008

Compensation expense	$	589	$	1,240	$	1,565	$	3,527


	July 31,		October 31,
	2009		2008

Liability	$	6,876	$	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 July 31, 2009 and 2008, and $252,400 for the nine months ended July 31, 2009 and 2008 on the straight-line method.

Subsequent to July 31, 2009, the Compensation Committee of the Board of Directors clarified the tax withholding provisions of the award. This clarification required us to correct our accounting

for the award from an equity award to a liability award. There was no material impact on our financial position, results of operations, or cash flows for any period from the grant date through the current period. For future periods, the liability related to this award will be re-measured to market value at each reporting period and at the settlement date.

The award which vested as of September 1, 2009 covered 20% of the grant, including accrued dividends, for a total of 14,611 shares of common stock. After the withholding of $.2 million for federal and state taxes, our President and Chief Executive Officer received 8,153 shares valued at the New York Stock Exchange composite closing price at September 1, 2009 of $24.24.

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. Currently, it is our policy to issue new shares for share-based awards.

11. 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 fourteen 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 operations 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 arose from statements in AGLR’s most recently filed Form 10-K, filed with the SEC on February 5, 2009, re-characterizing GNGC’s option 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 will expire on November 1, 2009.

On July 29, 2009, we reached a settlement with GNGC that provides for the dismissal of the lawsuit and the restructuring of the ownership interests in SouthStar. Under the terms of the settlement agreement, we will sell half of our 30% membership interest in SouthStar to GNGC effective January 1, 2010 for $57.5 million, retaining a 15% earnings and membership share in SouthStar after the sale. The agreement, which has been approved by both companies’ boards of directors, also resolves the issues concerning GNGC’s option to purchase our membership interest in SouthStar. As part of the agreement, GNGC will not have any further option rights to our remaining 15% interest. The agreement is subject to approval by the Georgia PSC.

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 July 31, 2009. Additional information concerning letters of credit is included in Note 9 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 our Huntersville LNG facility. During the three months ended July 31, 2009, our estimate of the total cost to remediate the facility increased from $1.1 million to $1.6 million, for which we increased our reserve by the additional $.5 million. We

have incurred $.7 million through July 31, 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 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 was approved by the FERC and required us, among other matters, to pay a penalty in settlement of the matter. The penalty, which was paid in July 2009, did not have a material effect on our financial position, cash flows or results of operations.

12. Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated through September 4, 2009, the filing date of this Form 10-Q. For information on subsequent events disclosure items related to regulatory matters and share-based payments, see Note 2 and Note 10, respectively, to the consolidated financial statements of this Form 10-Q.

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, including climate change legislation, 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.

	•		Changes in outstanding shares. The number of outstanding shares may fluctuate due to repurchases under our Common Stock Open Market Purchase Program or new issuances.

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 nine months ended July 31, 2009, 85% 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 the nine months ended July 31, 2009, 3% of our earnings before taxes came from regulated non-utility activities and 12% of our earnings before taxes came from unregulated non-utility activities in our non-utility segment. For further information on business segments, see Note 5 to the consolidated financial statements in this Form 10-Q. For information about our equity method investments, see Note 6 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 environment. 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% 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 has become more difficult for customers to pay their gas bills, leading to slower collections and higher-than-normal levels of accounts receivable and 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.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009. The bill includes a carbon cap and trade program with a progressive cap on economy-wide greenhouse gas emissions, with an allocation, auction and trading of allowances. Natural gas utilities would be covered by the program beginning in 2016. As of the date of this filing, the Senate has not passed comparable legislation.

We will continue our efforts to promote natural gas and to inform consumers about the environmental benefits of efficiently using natural gas directly in their homes and businesses to

reduce greenhouse gas emissions. 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 regulatory 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. We have entered into an agreement to sell half of our 30% interest in SouthStar to GNGC for $57.5 million to be effective January 1, 2010. For further information, see Note 6 to the consolidated financial statements in this Form 10-Q.

Results of Operations

We reported a net loss of $7.3 million for the three months ended July 31, 2009 as compared to a net loss of $7.7 million for the same period in 2008. The following table sets forth a comparison of the components of our consolidated statements of operations for the three months ended July 31, 2009 as compared with the three months ended July 31, 2008.

Operating Statement Components


	Three Months Ended July 31
In thousands, except per share amounts	2009			2008			Variance			Percent Change
Operating Revenues	$	180,201		$	354,709		$	(174,508	)		(49.2)	%
Cost of Gas		99,362			277,689			(178,327	)		(64.2)	%

Margin		80,839			77,020			3,819			5.0	%

Operations and Maintenance		50,124			49,738			386			0.8	%
Depreciation		24,488			23,581			907			3.8	%
General Taxes		8,841			7,928			913			11.5	%
Income Taxes		(4,199	)		(6,846	)		2,647			38.7	%

Total Operating Expenses		79,254			74,401			4,853			6.5	%

Operating Income		1,585			2,619			(1,034	)		(39.5)	%
Other Income (Expense), net of tax		2,162			2,530			(368	)		(14.5)	%
Utility Interest Charges		11,047			12,827			(1,780	)		(13.9)	%

Net Loss	$	(7,300	)	$	(7,678	)	$	378			4.9	%


Average Shares of Common Stock:
Basic		72,983			73,368			(385	)		(0.5)	%
Diluted		72,983			73,368			(385	)		(0.5)	%


Loss Per Share of Common Stock:
Basic	$	(0.10	)	$	(0.10	)	$	—			—	%
Diluted	$	(0.10	)	$	(0.10	)	$	—			—	%

We reported net income of $127.1 million for the nine months ended July 31, 2009 as compared to $123.2 million for the same period in 2008. The following table sets forth a comparison of the components of our consolidated statements of operations for the nine months ended July 31, 2009 as compared with the nine months ended July 31, 2008.

Operating Statement Components


	Nine Months Ended July 31
In thousands, except per share amounts	2009		2008		Variance			Percent Change
Operating Revenues	$	1,415,276	$	1,777,357	$	(362,081	)		(20.4	)%
Cost of Gas		943,802		1,312,031		(368,229	)		(28.1	)%

Margin		471,474		465,326		6,148			1.3	%

Operations and Maintenance		154,200		155,598		(1,398	)		(0.9	)%
Depreciation		72,937		69,179		3,758			5.4	%
General Taxes		26,235		25,080		1,155			4.6	%
Income Taxes		73,035		69,092		3,943			5.7	%

Total Operating Expenses		326,407		318,949		7,458			2.3	%

Operating Income		145,067		146,377		(1,310	)		(0.9	)%
Other Income (Expense), net of tax		18,006		18,316		(310	)		(1.7	)%
Utility Interest Charges		35,972		41,479		(5,507	)		(13.3	)%

Net Income	$	127,101	$	123,214	$	3,887			3.2	%


Average Shares of Common Stock:
Basic		73,180		73,355		(175	)		(0.2	)%
Diluted		73,476		73,628		(152	)		(0.2	)%


Earnings Per Share of Common Stock:
Basic	$	1.74	$	1.68	$	0.06			3.6	%
Diluted	$	1.73	$	1.67	$	0.06			3.6	%

Key statistics are shown in the table below for the three months ended July 31, 2009 and 2008.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Three Months Ended
	July 31
	2009			2008			Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		9,946			11,228			(1,282	)		(11.4	)%
Transportation Volumes		26,949			27,703			(754	)		(2.7	)%

Throughput		36,895			38,931			(2,036	)		(5.2	)%

Secondary Market Volumes		9,344			13,246			(3,902	)		(29.5	)%


Customers Billed (at period end)		941,564			943,294			(1,730	)		(0.2	)%
Gross Customer Additions		2,774			4,111			(1,337	)		(32.5	)%

Degree Days
Actual		43			35			8			22.9	%
Normal		51			53			(2	)		(3.8	)%
Percent warmer than normal		(15.7	)%		(34.0	)%		n/a			n/a

Number of Employees (at period end)		1,828			1,846			(18	)		(1.0	)%

Key statistics are shown in the table below for the nine months ended July 31, 2009 and 2008.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Nine Months Ended
	July 31
	2009			2008			Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		97,192			95,293			1,899			2.0	%
Transportation Volumes		73,687			70,654			3,033			4.3	%

Throughput		170,879			165,947			4,932			3.0	%

Secondary Market Volumes		32,312			45,383			(13,071	)		(28.8	)%


Customers Billed (at period end)		941,564			943,294			(1,730	)		(0.2	)%
Gross Customer Additions		9,024			15,755			(6,731	)		(42.7	)%

Degree Days
Actual		3,191			2,953			238			8.1	%
Normal		3,119			3,148			(29	)		(0.9	)%
Percent colder (warmer) than normal		2.3	%		(6.2	)%		n/a			n/a

Number of Employees (at period end)		1,828			1,846			(18	)		(1.0	)%

Operating Revenues

Operating revenues decreased $174.5 million for the three months ended July 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$127.4 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.

	•		$39.4 million primarily from gas costs passed through to sales customers.

	•		$12.7 million of commodity gas costs related to volumes delivered to sales customers.

	•		$1.1 million from a decrease in volumes delivered to transportation customers other than power generation.

These decreases were partially offset by an increase of $3.4 million in revenues under the margin decoupling mechanism.

Operating revenues decreased $362.1 million for the nine months ended July 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$274.2 million from revenues in secondary market transactions due to decreased activity and gas costs.

	•		$61.9 million primarily from gas costs passed through to sales customers.

	•		$26.8 million from revenues under the margin decoupling mechanism.

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

	•		$3.7 million from a decrease in volumes delivered to transportation customers other than power generation.

These decreases were partially offset by an increase of $10.2 million of commodity gas costs from higher volume deliveries to sales customers.

Cost of Gas

Cost of gas decreased $178.3 million for the three months ended July 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$126.1 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

	•		$34.9 million primarily from gas costs passed through to sales customers.

	•		$12.7 million of commodity gas costs related to volumes delivered to sales customers.

Cost of gas decreased $368.2 million for the nine months ended July 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$273.2 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

	•		$83.5 million primarily from gas costs passed through to sales customers.

These decreases were partially offset by an increase of $10.2 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 $3.8 million for the three months ended July 31, 2009 compared with the same period in 2008 primarily due to $5.8 million from increased rates approved in the North Carolina general rate case effective November 1, 2008, partially offset by a decrease of $1.3 million from monthly capacity release and off-system sales transactions.

Margin increased $6.1 million for the nine months ended July 31, 2009 compared with the same period in 2008 primarily due to the following increases:

	•		$9.8 million from increased rates approved in the North Carolina general rate case effective November 1, 2008.

	•		$1.1 million from growth in our residential and commercial markets.

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

These increases were partially offset by the following decreases:

	•		$2.8 million from decreased volumes delivered to industrial customers.

	•		$1.7 million from net adjustments to gas costs, inventory, supplier refunds and lost and unaccounted for gas due to regulatory gas cost accounting reviews.

	•		$1 million from monthly capacity release and off-system sales transactions.

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 53.9% of revenues, and transportation and storage costs which are 6.7% of revenues, for the nine months ended July 31, 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 July 31, 2009 compared with the same period in 2008.

Operations and maintenance expenses decreased $1.4 million for the nine months ended July 31, 2009 compared with the same period in 2008 primarily due to the following decreases:

	•		$2.6 million in employee benefits due to reductions in pension expense from changes in the discount rate and plan design, regulatory deferral of the Tennessee portion of the annual plan funding and lower group insurance expense from claims experience and fewer employees.

	•		$1 million in transportation costs.

	•		$.8 million in advertising costs.

These decreases were partially offset by the following increases:

	•		$1.6 million in regulatory amortization expense.

	•		$1.3 million in the provision for uncollectibles.

Depreciation

Depreciation expense increased $.9 million and $3.8 million for the three months and nine months ended July 31, 2009 compared with the same period in 2008, respectively, primarily due to increases in plant in service.

General Taxes

General taxes increased $.9 million and $1.2 million for the three months and nine months ended July 31, 2009, respectively, compared with the same periods in 2008 primarily due to increases in property taxes due to a larger property tax base and county reassessments.

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 July 31, 2009 as compared with the same period in 2008. The primary change to Other Income (Expense) for the nine months ended July 31, 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 $.7 million for the nine months ended July 31, 2009 as compared with the same period in 2008 primarily due to the following:

	•		$1.3 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 PSC 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 property taxes and amortization of deferred interest on financing fees.

Utility Interest Charges

Utility interest charges decreased $1.8 million for the three months ended July 31, 2009 compared with the same period in 2008 primarily due to the following:

	•		$2.3 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in the current period.

	•		$.4 million decrease in interest on short-term debt primarily due to the average interest rate of the current period being 220 basis points lower than the prior year period which more than offset higher levels of borrowing in the current period.

	•		$.8 million increase in the allowance for borrowed funds.

Utility interest charges decreased $5.5 million for the nine months ended July 31, 2009 compared with the same period in 2008 primarily due to the following:

	•		$5 million decrease in net interest expense on amounts due to/from customers due to higher net receivables in the current period.

	•		$2.6 million decrease in interest on short-term debt primarily due to the average interest rate of the current period being 300 basis points lower than the prior year period even though borrowings were higher in the current period.

	•		$1.8 million increase in the allowance for borrowed funds.

	•		$.3 million increase in interest from the regulatory treatment of certain components of deferred income taxes.

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 facility 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 $306.1 million and $254.1 million for the nine months ended July 31, 2009 and 2008, respectively. Net cash provided by operating activities reflects a $3.9 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 decreased $46.3 million in the current period primarily due to the decrease in unbilled volumes and amounts billed to customers reflected lower gas costs in 2009 as compared with 2008, partially offset by higher volumes delivered. Volumes sold to residential and commercial customers increased 6.7 million dekatherms as compared with the same prior period primarily due to weather that was 8% colder. Total throughput increased 4.9 million dekatherms as compared with the same prior period.

	•		Net amounts due from customers increased $27.2 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 $82.6 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 $46.5 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 $37.9 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 nine months ended July 31, 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 increased margin by $.5 million and by $27.3 million in the nine months ended July 31, 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.

In July 2009, we reached a settlement in our lawsuit with GNGC that will restructure our ownership interest in SouthStar. Under the terms of the settlement agreement, we will sell half of our 30% membership interest in SouthStar to GNGC effective January 1, 2010, retaining a 15% earnings and membership share in SouthStar after the sale. Currently, earnings and losses are allocated to us at 25% with the exception of earnings and losses in the Ohio and Florida markets, which are allocated to us at our membership percentage of 30%. At closing, we will receive $57.5 million from GNGC resulting in an estimated after-tax gain of $30 million in 2010 or $.41 per diluted share. The agreement is subject to the approval and consent of the Georgia PSC.

Cash Flows from Investing Activities. Net cash used in investing activities was $83.9 million and $149.3 million for the nine months ended July 31, 2009 and 2008, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the nine months ended July 31, 2009 were $83.2 million as compared to $141 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 $151 million are forecasted for 2009, a reduction of $95 million from our original budget and a reduction of $21 million from our previous forecast. The change in our construction expenditures forecast primarily reflects the deferral of $53 million for the Robeson LNG storage project and the deferral of $26 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 $215.9 million and $107.5 million for the nine months ended July 31, 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 July 31, 2009, our current assets were $494.4 million and our current liabilities were $501.6 million primarily due to seasonal requirements as discussed above.

As of July 31, 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 $257.5 million as of July 31, 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 accelerated share repurchase (ASR) program, payments for interest on long-term debt and property taxes and payments to suppliers for the winter heating season. During the nine months ended July 31, 2009, short-term borrowings ranged from $131.5 million to $556.5 million, including amounts borrowed under a seasonal credit facility that expired March 31, 2009, and interest rates ranged from .53% to 2.84% (weighted average of .95%).

As of July 31, 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 July 31, 2009, unused lines of credit available under our syndicated credit facility, including the issuance of the letters of credit, totaled $190.1 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 deferred the development and construction of 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 nine months ended July 31, 2009, we issued $11 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 four million shares. Upon this authorization, 7,010,074 shares were available for repurchase. Upon 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 July 31, 2009, our retained earnings were not restricted. On September 3, 2009, the Board of Directors declared a quarterly dividend on common stock of $.27 per share, payable October 15, 2009 to shareholders of record at the close of business on September 24, 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 July 31, 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 July 31, 2009 and 2008, and October 31, 2008, are summarized in the table below.


	July 31					October 31					July 31
In thousands	2009		Percentage			2008		Percentage			2008		Percentage
Short-term debt	$	257,500		13	%	$	406,500		19	%	$	169,500		9	%
Current portion of long-term debt		30,000		1	%		30,000		1	%		—		—	%
Long-term debt		792,815		39	%		794,261		38	%		824,533		43	%

Total debt		1,080,315		53	%		1,230,761		58	%		994,033		52	%
Common stockholders’ equity		947,906		47	%		887,244		42	%		921,829		48	%

Total capitalization (including short-term debt)	$	2,028,221		100	%	$	2,118,005		100	%	$	1,915,862		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 July 31, 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 July 31, 2009, there has been no event of default giving rise to acceleration of our debt.

Estimated Future Contractual Obligations

During the three months ended July 31, 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 7 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 July 31, 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 6 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

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 July 31, 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 July 31, 2009, we had $257.5 million of short-term debt outstanding under our syndicated credit facility at an interest rate of .53%. 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 $.5 million during the three months ended July 31, 2009 and $3 million during the nine months ended July 31, 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. Such disclosure controls and procedures are designed to provide reasonable assurance 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. 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 at the reasonable assurance level.

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 third 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 nine months ended July 31, 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, during the three months ended July 31, 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								6,310,074
05/01/09 - 05/31/09		—	$	—		—		6,310,074
06/01/09 - 06/30/09		—	$	—		—		6,310,074
07/01/09 - 07/31/09		—	$	—		—		6,310,074

Total		—	$	—		—


*		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 July 31, 2009, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 6. Exhibits


3.1		Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009

		Compensatory Contracts:

10.1		Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008

		Other Contracts:

10.2		Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 2009

10.3		Settlement Agreement by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (Exhibit 10.1, Form 8-K dated August 4, 2009)

10.4		Third Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 29, 2009 (Exhibit 10.2, Form 8-K dated August 4, 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.

Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended July 31, 2009

Exhibits


	3.1			Restated Articles of Incorporation of Piedmont Natural Gas Company, Inc., dated as of March 2009

	10.1			Amendment No. 1 to Director Retirement Benefits Agreements with outside directors, dated as of December 31, 2008

	10.2			Second Amendment to Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC by and between Georgia Natural Gas Company and Piedmont Energy Company, dated July 2, 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


		Page

Part I.	Financial Information

Item 1.	Financial Statements		1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		41
Item 4.	Controls and Procedures		43

Part II.	Other Information

Item 1.	Legal Proceedings		44
Item 1A.	Risk Factors		44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		44
Item 6.	Exhibits		45

	Signatures		46
EX-3.1
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2


	Piedmont Natural Gas Company, Inc. (Registrant)
Date September 4, 2009	/s/ David J. Dzuricky
	David J. Dzuricky
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)


Date September 4, 2009	/s/ Jose M. Simon
	Jose M. Simon
	Vice President and Controller (Principal Accounting Officer)