- Quarterly Report (10-Q)

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, 2011

¨	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		(I.R.S. Employer
incorporation or organization)		Identification No.)

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

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

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


Large accelerated filer þ	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ 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 September 2, 2011
Common Stock, no par value		72,171,413

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

July 31, 2011

TABLE OF CONTENTS


		Page
Part I.	Financial Information

Item 1.	Financial Statements	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	44

Part II.	Other Information

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

	Signatures	47

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)


	July 31, 2011		October 31, 2010
ASSETS
Utility Plant:
Utility plant in service	$	3,345,557	$	3,176,312
Less accumulated depreciation		963,016		917,300

Utility plant in service, net		2,382,541		2,259,012
Construction work in progress		124,260		171,901
Plant held for future use		6,751		6,751

Total utility plant, net		2,513,552		2,437,664


Other Physical Property, at cost (net of accumulated depreciation of $788 in 2011 and $729 in 2010)		471		528


Current Assets:
Cash and cash equivalents		104,685		5,619
Trade accounts receivable (less allowance for doubtful accounts of $2,858 in 2011 and $929 in 2010)		84,649		62,370
Income taxes receivable		14,317		24,856
Other receivables		2,397		2,289
Unbilled utility revenues		7,271		21,337
Inventories:
Gas in storage		91,700		101,734
Materials, supplies and merchandise		3,136		4,547
Gas purchase derivative assets, at fair value		1,413		2,819
Amounts due from customers		19,609		62,336
Prepayments		28,892		39,832
Other current assets		790		101

Total current assets		358,859		327,840


Noncurrent Assets:
Equity method investments in non-utility activities		85,969		80,287
Goodwill		48,852		48,852
Marketable securities, at fair value		1,499		997
Overfunded postretirement asset		40,149		17,342
Regulatory asset for postretirement benefits		63,217		64,775
Unamortized debt expense		11,692		8,576
Regulatory cost of removal asset		18,951		17,825
Other noncurrent assets		56,135		48,589

Total noncurrent assets		326,464		287,243


Total	$	3,199,346	$	3,053,275

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)


	July 31, 2011			October 31, 2010
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value — 175 shares authorized	$	—		$	—
Common stock — no par value — shares authorized: 200,000; shares outstanding: 72,130 in 2011 and 72,282 in 2010		441,259			445,640
Retained earnings		581,066			519,831
Accumulated other comprehensive loss		(87	)		(530	)

Total stockholders’ equity		1,022,238			964,941
Long-term debt		675,000			671,922

Total capitalization		1,697,238			1,636,863


Current Liabilities:
Current maturities of long-term debt		60,000			60,000
Bank debt		269,500			242,000
Trade accounts payable		67,800			66,019
Other accounts payable		30,498			49,645
Accrued interest		11,475			20,134
Customers’ deposits		26,194			25,631
Deferred income taxes		—			4,933
General taxes accrued		14,982			20,100
Amounts due to customers		5,475			—
Other current liabilities		2,341			10,098

Total current liabilities		488,265			498,560


Noncurrent Liabilities:
Deferred income taxes		502,393			429,225
Unamortized federal investment tax credits		2,023			2,145
Accumulated provision for postretirement benefits		15,412			14,805
Cost of removal obligations		456,793			436,072
Other noncurrent liabilities		37,222			35,605

Total noncurrent liabilities		1,013,843			917,852


Commitments and Contingencies (Note 14)


Total	$	3,199,346		$	3,053,275

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 July 31						Nine Months Ended July 31
	2011			2010			2011			2010

Operating Revenues	$	197,274		$	211,603		$	1,241,897		$	1,358,185
Cost of Gas		115,311			133,706			756,997			888,667


Margin		81,963			77,897			484,900			469,518


Operating Expenses:
Operations and maintenance		53,351			55,295			163,344			164,838
Depreciation		26,128			24,691			76,601			73,529
General taxes		9,206			8,753			29,767			26,096
Utility income taxes		(7,111	)		(7,371	)		71,003			68,499


Total operating expenses		81,574			81,368			340,715			332,962


Operating Income (Loss)		389			(3,471	)		144,185			136,556


Other Income (Expense):
Income from equity method investments		2,360			2,607			22,500			27,748
Gain on sale of interest in equity method investment		—			—			—			49,674
Non-operating income		711			(31	)		1,349			283
Non-operating expense		(303	)		(227	)		(1,481	)		(1,603	)
Income taxes		(482	)		(558	)		(8,149	)		(29,449	)


Total other income (expense)		2,286			1,791			14,219			46,653


Utility Interest Charges:
Interest on long-term debt		11,269			13,280			35,440			39,805
Allowance for borrowed funds used during construction		(1,928	)		(6,360	)		(5,603	)		(7,662	)
Other		2,037			918			5,422			9

Total utility interest charges		11,378			7,838			35,259			32,152


Net Income (Loss)	$	(8,703	)	$	(9,518	)	$	123,145		$	151,057


Average Shares of Common Stock:
Basic		72,007			71,968			72,010			72,315
Diluted		72,007			71,968			72,235			72,668

Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.12	)	$	(0.13	)	$	1.71		$	2.09
Diluted	$	(0.12	)	$	(0.13	)	$	1.70		$	2.08

Cash Dividends Per Share of Common Stock	$	0.29		$	0.28		$	0.86		$	0.83

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
	2011			2010

Cash Flows from Operating Activities:
Net income	$	123,145		$	151,057
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		79,707			76,867
Amortization of investment tax credits		(122	)		(271	)
Allowance for doubtful accounts		1,929			1,883
Gain on sale of interest in equity method investment, net of tax		—			(30,222	)
Net gain on sale of property		—			(158	)
Income from equity method investments		(22,500	)		(27,748	)
Distributions of earnings from equity method investments		14,961			29,000
Deferred income taxes, net		67,292			2,189
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		1,406			(26,241	)
Receivables		(10,494	)		10,953
Inventories		11,445			3,908
Amounts due from/to customers		48,202			160,025
Settlement of legal asset retirement obligations		(1,137	)		(634	)
Overfunded postretirement asset		(22,807	)		(10,803	)
Regulatory asset for postretirement benefits		1,558			550
Other assets		15,258			55,147
Accounts payable		(12,461	)		(18,294	)
Provision for postretirement benefits		607			(10,275	)
Other liabilities		(16,015	)		(7,309	)

Net cash provided by operating activities		279,974			359,624


Cash Flows from Investing Activities:
Utility construction expenditures		(137,591	)		(141,677	)
Allowance for funds used during construction		(5,603	)		(7,662	)
Contributions to equity method investments		(6,222	)		—
Distributions of capital from equity method investments		8,968			7,389
Proceeds from sale of interest in equity method investment		—			57,500
Proceeds from sale of property		885			1,320
Investments in marketable securities		(466	)		(484	)
Other		2,065			(38	)

Net cash used in investing activities		(137,964	)		(83,652	)

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)


	Nine Months Ended July 31
	2011			2010

Cash Flows from Financing Activities:
Borrowings under bank debt	$	1,451,000		$	816,500
Repayments under bank debt		(1,423,500	)		(1,000,500	)
Proceeds from issuance of long-term debt		200,000			—
Retirement of long-term debt		(196,922	)		(502	)
Expenses related to issuance and reacquiring of long-term debt		(1,760	)		—
Expenses related to issuance of credit facility		(2,164	)		—
Issuance of common stock through dividend reinvestment and employee stock plans		15,392			14,283
Repurchases of common stock		(23,004	)		(47,295	)
Dividends paid		(61,980	)		(60,056	)
Other		(6	)		(768	)

Net cash used in financing activities		(42,944	)		(278,338	)


Net Increase (Decrease) in Cash and Cash Equivalents		99,066			(2,366	)
Cash and Cash Equivalents at Beginning of Period		5,619			7,558

Cash and Cash Equivalents at End of Period	$	104,685		$	5,192


Cash Paid During the Year for:
Interest	$	46,904		$	51,022
Income Taxes:
Income taxes paid	$	4,935		$	30,958
Income taxes refunded		1,893			1,830

Income taxes, net	$	3,042		$	29,128


Noncash Investing and Financing Activities:
Accrued construction expenditures	$	4,937		$	1,074
Guaranty		—			1,234

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (Unaudited)

(In thousands)


	Three Months Ended July 31						Nine Months Ended July 31
	2011			2010			2011			2010

Net Income (Loss)	$	(8,703	)	$	(9,518	)	$	123,145		$	151,057

Other Comprehensive Income:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($125) and $94 for the three months ended July 31, 2011 and 2010, respectively, and ($70) and ($77) for the nine months ended July 31, 2011 and 2010, respectively		(191	)		148			(110	)		(117	)
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $47 and $263 for the three months ended July 31, 2011 and 2010, respectively, and $355 and $1,147 for the nine months ended July 31, 2011 and 2010, respectively		73			407			553			1,779


Total Comprehensive Income (Loss)	$	(8,821	)	$	(8,963	)	$	123,588		$	152,719

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, 2010.

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, 2011 and October 31, 2010, the results of operations for the three months and nine months ended July 31, 2011 and 2010, and cash flows for the nine months ended July 31, 2011 and 2010. Our business is seasonal in nature. The results of operations for the three months and nine months ended July 31, 2011 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 as of 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, 2010. There were no significant changes to those accounting policies during the nine months ended July 31, 2011.

Rate-Regulated Basis of Accounting

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide 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 these regulations, 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.

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commission during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income. Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all of our recorded regulatory assets are recoverable in current rates or future rate proceedings.

Regulatory assets and liabilities in the consolidated balance sheets as of July 31, 2011 and October 31, 2010 are as follows.


In thousands	July 31, 2011		October 31, 2010

Regulatory assets	$	161,529	$	197,772
Regulatory liabilities		463,953		439,075

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 accounting regulations prescribed under rate-based regulation. For information on related party transactions, see Note 8 to the consolidated financial statements in this Form 10-Q.

Fair Value Measurements

The carrying value of cash and cash equivalents, receivables, bank debt, accounts payable and accrued interest approximates fair value. Our financial assets and liabilities are recorded at fair value and consist primarily of derivatives that are recorded in the consolidated balance sheets in accordance with derivative accounting standards.

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. The fair value of our financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs in the fair value hierarchy levels as set forth in the fair value guidance.

For the fair value measurements of our derivatives and marketable securities, see Note 10 to the consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 8 to our Form 10-K for the year ended October 31, 2010. For further information on our fair value methodologies, see Note 1.F to our Form 10-K for the year ended October 31, 2010. There were no significant changes to these fair value methodologies during the three months ended July 31, 2011.

Financing Receivables

We originate and subsequently own installment loans made to our natural gas customers under our Third Party Financing Program. Under the Third Party Financing Program, we offer financing to qualifying customers for the purchase and installation of gas appliances and HVAC equipment. The quality of these loans is comparable to the quality of our natural gas receivables. We perform credit evaluations of our customers and maintain reserves for estimated credit losses based on historical experience and the aging of the loan balances. As of July 31, 2011, we do not have loans that are impaired. We recognize interest revenue on these loans using the simple add-on interest method. The loans outstanding under the Third Party Financing Program are presented below.


In thousands	July 31, 2011

Third party financing program loans outstanding	$	6,772

The reconciliation of activity in the reserve related to the Third Party Financing Program is presented below.


In thousands	Three Months Ended July 31, 2011

Balance at beginning of period	$	240
Additions charged to uncollectibles expense		56
Accounts written off, net of recoveries		(63	)

Balance at end of period	$	233

Recently Issued Accounting Guidance

In January 2010, the Financial Accounting Standards Board (FASB) issued accounting guidance to require separate disclosures about purchases, sales, issuances and settlements relating to Level 3 fair value measurements. The guidance will be effective for interim periods for fiscal years beginning after December 15, 2010. We will adopt the guidance for Level 3 disclosure for recurring and non-recurring items covered under the fair value guidance for the first quarter of our fiscal year ending October 31, 2012. Since the guidance addresses only disclosures related to fair value measurements under Level 3, we do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. We will adopt the amended fair value guidance for the second quarter of our fiscal year ending October 31, 2012. We do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued accounting guidance to increase the prominence of other comprehensive income (OCI) in financial statements. The guidance gives businesses two options for presenting OCI. An OCI statement can be included with the statement of operations, and together the two will make a statement of comprehensive income. Alternatively, businesses can present a separate OCI statement, but that statement must appear consecutively with the statement of operations within the financial report. The guidance will be effective for interim and annual periods beginning after December 15, 2011. We will adopt the OCI presentation guidance for the second quarter of our fiscal year ending October 31, 2012. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows. We intend to present net income and other comprehensive income in one continuous statement.

2. Regulatory Matters

On February 26, 2010, we filed a petition with the Tennessee Regulatory Authority (TRA) to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. On April 12, 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would deny recovery of $1.5 million for us. Once the TRA issues its order on this matter, we intend to seek their reconsideration. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows.

On September 9, 2010, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2010 under the Tennessee Incentive Plan (TIP). On May 25, 2011, the TRA issued an order approving our TIP account balances.

On December 6, 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. This one-time eighteen month audit period is designed to synchronize the ACA audit year with the TIP plan year in order to facilitate the audit process for future periods. On August 15, 2011, the TRA issued an order approving the deferred gas cost account.

On February 15, 2011, the Public Service Commission of South Carolina (PSCSC) set a hearing date of July 13, 2011 for our annual review of purchased gas costs and gas purchasing policies for the twelve months ended March 31, 2011. On July 1, 2011, we and the Office of Regulatory Staff (ORS) filed a joint settlement agreement stating that our gas purchasing policies and practices during the review period were reasonable and prudent and in compliance with the gas cost recovery provisions of our tariff and relevant PSCSC orders during the review period and that we managed our hedging program during the review period in a reasonable and prudent manner. The settlement agreement also stipulated that our hedging program should no longer have a required minimum amount of hedging. On August 10, 2011, the PSCSC accepted the settlement agreement and requested that the ORS seek a public briefing on the issue of how to measure the prudence of hedging programs in future annual review proceedings.

On February 24, 2011, the ORS requested that the PSCSC temporarily suspend the commission-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions for the cost of natural gas. This suspension of the hedging program was requested to be effective prospectively upon the issuance of an order by the PSCSC. All existing hedges would continue to be managed under the current approved hedging programs as gas costs in the annual review of purchased gas costs and gas purchasing policies. On March 4, 2011, we filed a letter with the PSCSC stating that we believe that it is reasonable and prudent to continue our current hedging program to provide some degree of high gas price protection for natural gas consumers. We believe that some price volatility will continue to exist in the market due to unpredictable events. Oral arguments and informational briefings on this matter were heard by the PSCSC on April 21, 2011. On June 17, 2011, the ORS withdrew its petition for suspension of gas hedging programs. On July 13, 2011, the PSCSC granted the ORS’ motion to withdraw the above mentioned petition and directed the ORS and the regulated gas utilities in South Carolina to address the prudence of gas hedging activities in annual review proceedings.

On June 15, 2011, we filed a cost and revenue study with the PSCSC as permitted by the Natural Gas Rate Stabilization Act requesting a change in rates from those approved by the PSCSC in an order dated October 13, 2010. On September 1, 2011, we and the ORS filed a settlement agreement with the PSCSC addressing our proposed rate changes. The settlement, if approved, will result in a decrease of $3.1 million in revenues based on

a return on equity of 11.3% and lower depreciation of $1.9 million for South Carolina utility plant in service, effective November 1, 2011. The settlement is pending approval by the PSCSC. We are unable to predict the outcome of this proceeding at this time.

On August 1, 2011, 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, 2011. We are unable to predict the outcome of this proceeding at this time.

On September 2, 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges for all customers to produce overall incremental revenues of $16.7 million, or 8.9% above the current annual revenues. In addition, the petition also requested modification of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes are proposed to be effective March 1, 2012. 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, 2011 and 2010 is presented below.

		$151,057			$151,057			$151,057		$151,057
	Three Months						Nine Months
In thousands except per share amounts	2011			2010			2011		2010

Net Income (Loss)	$	(8,703	)	$	(9,518	)	$	123,145	$	151,057


Average shares of common stock outstanding for basic earnings per share		72,007			71,968			72,010		72,315
Contingently issuable shares under incentive compensation plans *		—			—			225		353

Average shares of dilutive stock		72,007			71,968			72,235		72,668


Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.12	)	$	(0.13	)	$	1.71	$	2.09
Diluted	$	(0.12	)	$	(0.13	)	$	1.70	$	2.08

*	For the three months ended July 31, 2011 and 2010, the inclusion of 204 and 339 contingently issuable shares, respectively, would have been antidilutive.

4. Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in a rabbi trust established for our deferred compensation plans that became effective on January 1, 2009. For further information on the deferred compensation plans, see Note 6 to the consolidated financial statements in this Form 10-Q.

The money market investments in the trust approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on the quoted market prices as traded on the exchanges. We have matched the current portion of the deferred compensation liability with the current asset and the noncurrent deferred compensation liability with the noncurrent asset; the current portion has been included in “Other current assets” in the consolidated balance sheets. The composition of these securities as of July 31, 2011 and October 31, 2010 is as follows.

		$1,346		$1,346		$1,346		$1,346
	July 31, 2011				October 31, 2010
In thousands	Cost		Fair Value		Cost		Fair Value

Current trading securities:
Money markets	$	—	$	—	$	—	$	—
Mutual funds		31		37		4		5

Total current trading securities		31		37		4		5


Noncurrent trading securities:
Money markets		220		220		254		254
Mutual funds		1,095		1,279		618		743

Total noncurrent trading securities		1,315		1,499		872		997


Total trading securities	$	1,346	$	1,536	$	876	$	1,002

5. Capital Stock

During the nine months ended July 31, 2011, we issued 522,000 shares of common stock under our dividend reinvestment and stock purchase plan (DRIP) and employee stock purchase plan (ESPP) for a total of $14.9 million. During the same period, we issued 126,000 shares of common stock under our incentive compensation plan for a total of $3.7 million. In January 2011, we repurchased 800,000 shares of common stock under the Common Stock Open Market Purchase Plan for a total payment of $23 million.

6. Employee Benefit Plans

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended July 31, 2011 and 2010 are presented below.

		$1,931			$1,931			$1,931		$1,931		$1,931			$1,931
	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2011			2010			2011		2010		2011			2010

Service cost	$	1,931		$	1,852		$	11	$	10	$	350		$	334
Interest cost		2,869			2,473			52		61		374			476
Expected return on plan assets		(5,157	)		(4,530	)		—		—		(384	)		(345	)
Amortization of transition obligation		—			—			—		—		167			167
Amortization of prior service (credit) cost		(548	)		(548	)		5		5		—			—
Amortization of actuarial loss		1,110			399			11		2		—			59

Total	$	205		$	(354	)	$	79	$	78	$	507		$	691

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2011 and 2010 are presented below.
	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2011			2010			2011		2010		2011			2010

Service cost	$	6,381		$	6,052		$	34	$	29	$	1,049		$	1,003
Interest cost		8,268			8,173			156		182		1,121			1,429
Expected return on plan assets		(15,456	)		(14,080	)		—		—		(1,150	)		(1,036	)
Amortization of transition obligation		—			—			—		—		500			500
Amortization of prior service (credit) cost		(1,648	)		(1,648	)		15		15		—			—
Amortization of actuarial loss		2,660			1,499			31		7		—			178

Total	$	205		$	(4	)	$	236	$	233	$	1,520		$	2,074

In November 2010, we contributed $22 million to the qualified pension plan, and in January 2011, we contributed $.3 million to the money purchase pension plan. We anticipate that we will contribute the following amounts to our other plans in 2011.


In thousands

Nonqualified pension plan	$	517
OPEB plan		1,400

We have a defined contribution restoration (DCR) plan that we fund annually and that covers all officers at the vice president level and above. For the nine months ended July 31, 2011, we contributed $.4 million to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral plan for the benefit of all director-level employees and officers; corporate contributions are not made to this plan. Both deferred compensation plans are funded through a rabbi trust with a bank as the trustee. As of July 31, 2011, we have a liability of $1.8 million for these plans.

See Note 4 and Note 10 to the consolidated financial statements in this Form 10-Q for information on the investments in marketable securities that are held in the trust.

7. 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 that are held by our wholly owned subsidiaries.

Operations of the regulated utility segment are reflected in “Operating Income (Loss)” 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, 2010.

Operations by segment for the three months and nine months ended July 31, 2011 and 2010 are presented below.

		$1,358,185			$1,358,185			$1,358,185			$1,358,185			$1,358,185			$1,358,185
In thousands	Regulated Utility						Non-utility Activities						Total
	2011			2010			2011			2010			2011			2010

Three Months
Revenues from external customers	$	197,274		$	211,603		$	—		$	—		$	197,274		$	211,603
Margin		81,963			77,897			—			—			81,963			77,897
Operations and maintenance expenses		53,351			55,295			33			24			53,384			55,319
Gain from sale of interest in equity method investment		—			—			—			—			—			—
Income from equity method investments		—			—			2,360			2,607			2,360			2,607
Operating income (loss) before income taxes		(6,722	)		(10,842	)		59			(303	)		(6,663	)		(11,145	)
Income (loss) before income taxes		(17,750	)		(18,719	)		2,418			2,388			(15,332	)		(16,331	)

Nine Months
Revenues from external customers	$	1,241,897		$	1,358,185		$	—		$	—		$	1,241,897		$	1,358,185
Margin		484,900			469,518			—			—			484,900			469,518
Operations and maintenance expenses		163,344			164,838			80			258			163,424			165,096
Gain from sale of interest in equity method investment		—			—			—			49,674			—			49,674
Income from equity method investments		—			—			22,500			27,748			22,500			27,748
Operating income (loss) before income taxes		215,188			205,055			(85	)		(633	)		215,103			204,422
Income before income taxes		179,871			172,130			22,426			76,875			202,297			249,005

Reconciliations to the consolidated statements of operations for the three months and nine months ended July 31, 2011 and 2010 are presented below.

		$249,005			$249,005			$249,005			$249,005
	Three Months						Nine Months
In thousands	2011			2010			2011			2010

Operating Income:
Segment operating income (loss) before income taxes	$	(6,663	)	$	(11,145	)	$	215,103		$	204,422
Utility income taxes		7,111			7,371			(71,003	)		(68,499	)
Non-utility activities before income taxes		(59	)		303			85			633

Operating income (loss)	$	389		$	(3,471	)	$	144,185		$	136,556


Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(15,332	)	$	(16,331	)	$	202,297		$	249,005
Income taxes		6,629			6,813			(79,152	)		(97,948	)

Net income (loss)	$	(8,703	)	$	(9,518	)	$	123,145		$	151,057

8. 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. (Cardinal), a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC.

On October 22, 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide the additional delivery service, we have executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to spend an estimated $48 million for a new compressor station and expanded meter stations in order to increase the capacity of its system by up to 199,000 dekatherms per day of firm capacity for us and another customer. As an equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of July 31, 2011, our contributions related to this expansion were $6.2 million.

The members’ capital will be replaced with permanent financing with a target overall capital structure of 45-50% debt and 50-55% equity after the project is placed into service, scheduled to be June 1, 2012. Our service subscription to Cardinal’s capacity following the system expansion will increase from approximately 37% to approximately 53%. The NCUC issued a formal certificate order for Progress Energy Carolinas for their Wayne County generation project in October 2009.

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, 2011 and 2010, these transportation costs and the amounts we owed Cardinal as of July 31, 2011 and October 31, 2010 are as follows.

	$3,070	$3,070	$3,070	$3,070
	Three Months		Nine Months
In thousands	2011	2010	2011	2010

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

			July 31, 2011	October 31, 2010

Trade accounts payable			$349	$349

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. Pine Needle owns an interstate liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (FERC).

We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For each period of the three months and nine months ended July 31, 2011 and 2010, these gas storage costs and the amounts we owed Pine Needle as of July 31, 2011 and October 31, 2010 are as follows.

	$9,236	$9,236	$9,236	$9,236
	Three Months		Nine Months
In thousands	2011	2010	2011	2010

Gas storage costs	$2,518	$2,922	$8,159	$9,236

			July 31, 2011	October 31, 2010

Trade accounts payable			$849	$985

We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States and Ohio with most of its business being conducted in the unregulated retail gas market in Georgia. On January 1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC, who has no further rights to acquire our remaining 15% interest. We continue to account for our 15% membership interest in SouthStar using the equity method, as we retain board representation with voting rights equal to GNGC on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

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, 2011 and 2010, our operating revenues from these sales and the amounts SouthStar owed us as of July 31, 2011 and October 31, 2010 are as follows.


	Three Months		Nine Months
In thousands	2011	2010	2011	2010

Operating revenues	$2,184	$1,905	$2,819	$2,965

			July 31, 2011	October 31, 2010

Trade accounts receivable			$666	$713

Piedmont Hardy Storage Company, LLC, 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. 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.

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, 2011 and 2010, these gas storage costs and the amounts we owed Hardy Storage as of July 31, 2011 and October 31, 2010 are as follows.


	Three Months		Nine Months
In thousands	2011	2010	2011	2010

Gas storage costs	$2,425	$2,425	$7,276	$6,961

			July 31, 2011	October 31, 2010

Trade accounts payable			$808	$808

9. Variable Interest Entities

Effective November 1, 2010, we adopted the FASB guidance that requires us to evaluate our variable interest in a variable interest entity (VIE) to qualitatively assess whether we have a controlling financial interest, and if so, determine whether we are the primary beneficiary. Under accounting guidance, a VIE is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As of July 31, 2011, we have determined that we are not the primary beneficiary, as defined by the authoritative guidance related to consolidations, in any of our equity method investments, which are discussed in Note 8. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance.

Our investments in joint ventures, as discussed in Note 8, are currently accounted for under the equity method. We will continue to account for these investments under this method, as we determined we are not the consolidating investor. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of July 31, 2011 and October 31, 2010, our investment balances are as follows.


In thousands	July 31, 2011		October 31, 2010

Cardinal	$	18,176	$	11,837
Pine Needle		19,079		21,810
SouthStar		18,373		17,146
Hardy Storage		30,341		29,494

Total equity method investments in non-utility activities	$	85,969	$	80,287

We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

10. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts for our derivative instruments and the fair value of the right to reclaim cash collateral. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of July 31, 2011 and October 31, 2010, we had long gas purchase options providing total coverage of 25.6 million dekatherms and 33.5 million dekatherms, respectively. The long gas purchase options held at July 31, 2011 are for the period from September 2011 through August 2012.

Fair Value Measurements

In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. 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. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in Note 1.F to the consolidated financial statements in our Form 10-K for the year ended October 31, 2010.

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, 2011 and October 31, 2010. 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 within the fair value hierarchy levels. We have had no transfers between any level during the three months ended July 31, 2011 and 2010.

Recurring Fair Value Measurements as of July 31, 2011


In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value

Assets:
Derivatives held for distribution operations	$	1,413	$	—	$	—	$	1,413
Debt and equity securities held as trading securities:
Money markets		220		—		—		220
Mutual funds		1,316		—		—		1,316

Total fair value assets	$	2,949	$	—	$	—	$	2,949

Recurring Fair Value Measurements as of October 31, 2010


In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value

Assets:
Derivatives held for distribution operations	$	2,819	$	—	$	—	$	2,819
Debt and equity securities held as trading securities:
Money markets		254		—		—		254
Mutual funds		748		—		—		748

Total fair value assets	$	3,821	$	—	$	—	$	3,821

Our utility segment derivative instruments are used in accordance with programs filed with or approved by 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 accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets. These derivative instruments include exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Trading securities include assets in a rabbi 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, consistently applied, 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.


In thousands	Carrying Amount			Fair Value

As of July 31, 2011		$	735,000		$	840,396
As of October 31, 2010			731,922			890,277

Quantitative and Qualitative 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 derivative accounting standards. As required by the accounting guidance, 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.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of July 31, 2011 and October 31, 2010.

Fair Value of Derivative Instruments


In thousands	Fair Value July 31, 2011		Fair Value October 31, 2010

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets — Gas purchase derivative assets (September 2011-August 2012)	$	1,413

Current Assets — Gas purchase derivative assets (December 2010-November 2011)			$	2,819

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 some level of protection against significant price increases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives generally has no earnings impact.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on our consolidated statements of operations for the three months and nine months ended July 31, 2011 and 2010, absent the regulatory treatment under our approved PGA procedures.


In thousands	Amount of Loss Recognized on Derivatives and Deferred Under PGA Procedures				Location of Loss Recognized through PGA Procedures
	Three Months Ended July 31		Nine Months Ended July 31
	2011	2010	2011	2010

Gas purchase options	$1,687	$16,910	$7,812	$50,686	Cost of Gas

In Tennessee, the cost of gas purchase 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 TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Risk Management

Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.

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

11. Long-Term Debt Instruments

During the nine months ended July 31, 2011 and 2010, we paid principal amounts of $.1 million and $.5 million, respectively, to noteholders of the 6.25% insured quarterly notes. We redeemed all of the 6.25% insured quarterly notes on June 1, 2011, which had an aggregate principal balance of $196.8 million.

On June 6, 2011, we issued five-year $40 million notes at an interest rate of 2.92% and ten-year $160 million notes at an interest rate of 4.24%.

On July 7, 2011, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for our investments in our subsidiaries, and for repurchases of shares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities.

12. Short-Term Debt Instruments

We have a $650 million three-year unsecured revolving syndicated credit facility that expires in January 2014. The facility has an option to expand up to $850 million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. This facility provides a line of credit for letters of credit of $10 million, of which $3.5 million was issued and outstanding at July 31, 2011. The five-year credit facility in place prior to January 25, 2011 provided a line of credit for letters of credit of $5 million, of which $2.7 million was issued and outstanding at October 31, 2010. These letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. The credit facility bears interest based on the 30-day LIBOR rate plus from 65 to 150 basis points, based on our credit ratings. Amounts borrowed remain outstanding until repaid and such amounts do not mature daily. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

Our outstanding short-term bank borrowings, as included in “Bank debt” in the consolidated balance sheets, were $269.5 million, as of July 31, 2011 under our syndicated three-year credit facility and $242 million, as of October 31, 2010 under our syndicated five-year credit facility, in LIBOR cost-plus loans. During the three months ended July 31, 2011, short-term bank borrowings ranged from $74 million to $296 million, and interest rates ranged from 1.09% to 1.12% (weighted average of 1.09%). During the nine months ended July 31, 2011, short-term bank borrowings ranged from $74 million to $426 million, and interest rates ranged from .51% to 1.17% (weighted average of .85%). Our syndicated three-year revolving 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 50% at July 31, 2011.

13. Employee Share-Based Plans

Under our shareholder approved incentive compensation plan, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan 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. For the three months and nine months ended July 31, 2011 and 2010, we recorded compensation expense, and as of July 31, 2011 and October 31, 2010, we have accrued a liability for these awards 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.

In December 2010, a long-term retention award under the incentive compensation plan was approved for eligible officers and other participants. This is a retention award that will be distributed to participants who have met the retention requirements at the end of a three-year period ending in December 2013 in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. For the three months and nine months ended July 31, 2011, we recorded compensation expense, and as of July 31, 2011, we have accrued a liability for these awards based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value at the settlement date.

Also under our approved incentive plan, 65,000 unvested shares of our common stock were granted to our President and Chief Executive Officer in September 2006. During the five-year 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. In accordance with the vesting schedule, 20%, 30% and 50% of the shares vested on September 1, 2009, 2010 and 2011, respectively. For the three months and nine months ended July 31, 2011 and 2010, we recorded compensation expense, and as of July 31, 2011 and October 31, 2010, we have accrued a liability for the award 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.

The compensation expense related to the incentive compensation plans for the three months and nine months ended July 31, 2011 and 2010, and the amounts recorded as liabilities as of July 31, 2011 and October 31, 2010 are presented below.


	Three Months				Nine Months
In thousands	2011		2010		2011		2010

Compensation expense		$(1,106)		$1,342		$1,060		$6,071



	July 31, 2011		October 31, 2010

Liability		$4,826		$9,914

On a quarterly basis, we issue shares of common stock under the ESPP and have accounted for the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.

Currently, it is our policy to issue new shares for share-based awards. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares and are included in our calculation of fully diluted earnings per share.

14. 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 twenty-one years. The time periods for gas supply contracts range from one to two 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 four 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

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 $3.5 million in letters of credit that were issued and outstanding at July 31, 2011. Additional information concerning letters of credit is included in Note 12 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 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.

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.

As part of a voluntary agreement with the North Carolina Department of Environment and Natural Resources (NCDENR), we conducted and completed the soil and groundwater remediation for the Hickory, North Carolina MGP site. The soil and groundwater remediation report was approved by NCDENR. We continue to conduct periodic groundwater monitoring at this site in accordance with our site remediation plan. We have incurred $1.4 million of remediation costs on this site through July 31, 2011.

In September 2009, the NCDENR requested an investigation plan for the Reidsville, North Carolina MGP site. In June 2010, we conducted our initial investigation which consisted of digging test pits and completing soil and groundwater contamination testing. The site investigations are now complete and a draft remediation plan has been submitted to the NCDENR for review. Our estimate of the total cost to remediate the Reidsville site is $.8 million for which we have recorded a liability.

In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been completed, and a consent order imposing usage restrictions on the property was approved and signed by the TDEC in June 2010. The public comment period has ended, and we continue to conduct periodic groundwater monitoring at the site per the final consent order. We have incurred $1.5 million of remediation costs through July 31, 2011.

In connection with our 2003 acquisition of North Carolina Natural Gas Corporation (NCNG), 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.

At our Huntersville LNG facility, we are continuing to address any remaining remediation issues, including monitoring groundwater contamination. We have incurred $3.1 million through July 31, 2011. Additional facilities at our Huntersville LNG plant site are being evaluated for lead-based paint removal with work tentatively scheduled for our fiscal year 2012. Future remediation costs are not expected to have a material impact on our financial position, results of operations or cash flows.

During the nine months ended July 31, 2011, we assessed the cost to remove lead-based paint at our Nashville LNG facility. As of July 31, 2011, our estimate of the total cost to remediate the property is $.5 million and we have incurred $.4 million through July 31, 2011. The removal of lead-based paint at our Nashville LNG facility is scheduled to be completed in fiscal 2011.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina district continues to operate USTs. Our Greenville, SC district had their tanks removed in this fiscal quarter, and we do not anticipate significant environmental remediation with respect to the removal process. As of July 31, 2011, our estimated undiscounted environmental liability for USTs for which we retain remediation responsibility is $.3 million.

One of our operating districts has coatings containing asbestos on some of their pipelines. We have educated our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline. Lead-based paint is being removed at multiple LNG facilities that we own. Employees continue to be trained on the hazards of lead exposure, and we have engaged independent environmental contractors to remove and dispose of the lead-based paint at these facilities. Based on information we have to date, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.

As of July 31, 2011, our estimated undiscounted environmental liability totaled $1.8 million, and consisted of $1.4 million for the MGP sites for which we retain remediation responsibility, $.1 million for the LNG facilities and $.3 million for the USTs not yet remediated. Further evaluation of the MGP sites, the UST sites and removal of lead-based paint 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, results of operations or cash flows.

Additional information concerning commitments and contingencies is set forth in Note 7 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2010.

15. 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 have been evaluated. For information on subsequent event disclosure related to regulatory matters, see Note 2 to the consolidated financial statements in 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 retain and 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.

•

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 and the ability to complete these capital projects may be affected by the ability to obtain and the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, cost and timing of project development-related contracts, project development delays, federal and state tax policies, and the cost and availability of labor and materials. 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, in our financial condition or in the financial condition of our lenders or investors 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, regulatory 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. Since such risks may affect the availability and cost of natural gas, they also may affect the competitive position of natural gas relative to other energy sources.

•

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, tornadoes and floods, can impact our customers, our suppliers and the pipelines that deliver gas to our distribution system and our distribution and transmission assets. Weather conditions directly influence the supply, demand, distribution and cost of natural gas.

•

Changes in environmental, safety, system integrity, tax and other laws and regulations, including those related to carbon regulations, and the cost of compliance. We are subject to extensive federal, state and local laws and regulations. Compliance with such laws and regulations could increase capital or operating costs, affect our reported earnings or cash flows, increase our liabilities or change the way our business is conducted.

•

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.

•

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 new issuances or repurchases under our Common Stock Open Market Purchase Program.

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. 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 at www.piedmontng.com 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 52,000 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 the cities of Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to the cities of 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 operating 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, 2011, 89% 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 and regulated interstate natural gas

storage and intrastate natural gas transportation. For the nine months ended July 31, 2011, 11% of our earnings before taxes came from our non-utility activities segment, which consists of 3% from regulated non-utility activities and 8% from unregulated non-utility activities.

For further information on business segments, see Note 7 to the consolidated financial statements in this Form 10-Q. For information about our equity method investments, see Note 8 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. The NCUC also regulates us 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 U.S. Department of Transportation (DOT) that affect the design, 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 to earn a fair rate of return on invested capital for our shareholders. Our ability to earn our authorized rates of return is based primarily on our ability to reduce or eliminate regulatory lag and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation.

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 winter 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 increases revenues when weather is warmer than normal and decreases 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 alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy. We have been pursuing alternatives to the traditional utility rate design that provide for the collection of margin revenue based on volumetric throughput with new rate designs and incentives that allow utilities to encourage energy efficiency and conservation. By decoupling the link between energy consumption and margin revenues, our interests are aligned with our customers’ interests on conservation and energy efficiency. In North Carolina, we have decoupled residential and commercial rates. In South Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. For the nine months ended July 31, 2011, these rate designs stabilized our gas utility margin by providing fixed recovery of 69% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 19% of our utility margins, including the rate stabilization mechanism in South Carolina and WNA in South Carolina and Tennessee; and volumetric or periodic renegotiation of 12% of our utility margins. For the nine months ended July 31, 2011, the margin decoupling mechanism in North Carolina reduced margin by $11.1 million, and the WNA in South Carolina and Tennessee reduced margin by $4.7 million.

On September 2, 2011, we filed a general rate application with the TRA for an increase in rates and charges to all customers that would be effective March 1, 2012. We also requested a modification of the cost allocation and rate designs underlying our existing rates, approval to implement a school-based energy education program with appropriate cost recovery mechanisms, an amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs.

We have refined our strategic objectives to an approach centered on our customers and what we believe is the inherent benefit of natural gas compared to other types of energy. Our overall corporate focus is to expand our core natural gas and complementary energy-related businesses to enhance shareholder value. This focus includes traditional growth in the core residential, commercial and industrial markets, growth in the power generation market, supply diversity and complementary investments and natural gas end use technology. We want our customers to choose us because of the value of natural gas and the quality of our service to them. We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. We pursue business practices to promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and fostering increased awareness and use of natural gas. We support our employees with improved processes and technology to better serve our customers and to add value for our shareholders while continuing to build on our healthy, high performance culture in order to recruit, retain and motivate our workforce.

The safety of our system, the public and our employees is a critical component to our ongoing success as a company. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing programs to inspect our system for corrosion and leaks. Given an increased interest in pipeline safety and integrity in the wake of several serious pipeline incidents in the United States, we anticipate federal legislative and regulatory enactments that will add further requirements to our pipeline safety and integrity programs. We met an August 2011 deadline to evaluate any risks to our distribution pipeline system (such as corrosion, leak detection) and created an action plan to address those risks. Additionally, we execute transmission pipeline integrity programs with standard procedures and programs for pipeline safety that included leak detection surveys, periodic valve maintenance, periodic corrosion and atmospheric corrosion inspections, cathodic protection and hydrostatic and compressed air pressure testings and other evaluation methods. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third party excavation damage, by far the greatest cause of any pipeline incidents on our system. We welcome focused efforts to improve the safety of our industry as a whole.

We continue our efforts to promote the benefits of natural gas. Promotion efforts are led by educating consumers on the benefits of natural gas compared to other energy sources as well as advocating the benefits of natural gas to prospective customers in our communities. We continue our efforts to promote the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security. Price moderation and stability of natural gas continues, which has made natural gas more economical than many other fuels.

We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation and efficiency and environmental stewardship. We are executing on a plan to build more compressed natural gas fueling stations in our service area for use by our own vehicle fleet as well as the general public. State and federal governments continue working towards legislation in support of alternative vehicle incentives for owners of fleets, passenger vehicles and refueling stations.

Our financial strength and flexibility is critical to our success as a company. We will continue our stewardship to maintain our financial strength, which translates to continued access to capital markets. In June 2011, we replaced $196.8 million of notes with a 6.25% stated interest rate with $200 million of notes with a weighted interest rate of 4%. In July 2011, we filed a shelf registration statement that will allow for future issuances of debt or equity. Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of 45% to 50%. We will continue to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

We have completed two projects to date in fiscal year 2011 to provide long-term gas transportation service to power generation customers in our market area. We have three projects under construction to provide natural gas delivery service to power generation facilities currently under construction in North Carolina with targeted in service dates of November 2011, June 2012 and June 2013. In addition to the environmental benefits of using natural gas at these new power plants, the construction of the natural gas pipelines for these projects will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for economic growth and development. See the discussion of our anticipated capital investment related to the construction of the natural gas pipelines and compressor stations to serve these new power generation facilities in “Cash Flows from Investing Activities” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 2 in this Form 10-Q.

We continue to see challenging economic conditions in our market area as evidenced by high rates of unemployment and depressed housing and commercial development markets. As discussed above, we are positioning ourselves to capitalize on new opportunities as the economy slowly improves, and continue to focus on customer conversions to natural gas and power generation gas delivery service opportunities. As we seek to expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for energy consumers because of the comfort, affordability, and efficiency of natural gas, as well as remind our customers of our reliability and safety as a company. We forecast gross customer addition growth for fiscal 2011 of approximately 1%.

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 projected rates of return commensurate with the 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.

Several new laws were enacted in 2010 for health care reform and the regulation of U.S. financial markets. We continue to follow the progress of new regulations that will be issued by various regulatory agencies. While we are not able to assess the full impact of these laws until the implementing regulations have been adopted, based on the information available to us at this time, we do not expect these laws to have a material adverse impact on our financial position, results of operations or cash flows.

Also, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted in December 2010, extends the 50% “bonus depreciation” that expired December 31, 2009 and temporarily increases “bonus depreciation” for federal income tax purposes to 100% for certain qualified investments. These provisions may affect our fiscal year tax returns for 2010-2014. The Internal Revenue Service has issued regulations that are intended to provide guidance in interpreting the law. We are in the process of assessing the full impact of this law. Based on current capital projections and timelines, we are anticipating a benefit through 2014 of $130-170 million. We anticipate that the bonus depreciation allowance will have a material favorable impact on our cash flows in the near term by reducing cash needed to pay federal income taxes.

Results of Operations

We reported a net loss of $8.7 million for the three months ended July 31, 2011 compared to a net loss of $9.5 million for the same period in 2010. The following table sets forth a comparison of the components of our consolidated statements of operations for the three months ended July 31, 2011 as compared with the three months ended July 31, 2010.

Operating Statement Components


	Three Months Ended July 31
In thousands, except per share amounts	2011			2010			Variance			Percent Change
Operating Revenues	$	197,274		$	211,603		$	(14,329	)		(6.8	)%
Cost of Gas		115,311			133,706			(18,395	)		(13.8	)%

Margin		81,963			77,897			4,066			5.2	%

Operations and Maintenance		53,351			55,295			(1,944	)		(3.5	)%
Depreciation		26,128			24,691			1,437			5.8	%
General Taxes		9,206			8,753			453			5.2	%
Utility Income Taxes		(7,111	)		(7,371	)		260			3.5	%

Total Operating Expenses		81,574			81,368			206			0.3	%

Operating Income (Loss)		389			(3,471	)		3,860			111.2	%
Other Income (Expense), net of tax		2,286			1,791			495			27.6	%
Utility Interest Charges		11,378			7,838			3,540			45.2	%

Net Loss	$	(8,703	)	$	(9,518	)	$	815			8.6	%


Average Shares of Common Stock:
Basic		72,007			71,968			39			0.1	%
Diluted		72,007			71,968			39			0.1	%


Loss Per Share of Common Stock:
Basic	$	(0.12	)	$	(0.13	)	$	0.01			7.7	%
Diluted	$	(0.12	)	$	(0.13	)	$	0.01			7.7	%

We reported net income of $123.1 million for the nine months ended July 31, 2011 compared to $151.1 million for the same period in 2010. The following table sets forth a comparison of the components of our consolidated statements of operations for the nine months ended July 31, 2011 as compared with the nine months ended July 31, 2010.

Operating Statement Components


	Nine Months Ended July 31
In thousands, except per share amounts	2011		2010		Variance			Percent Change
Operating Revenues	$	1,241,897	$	1,358,185	$	(116,288	)		(8.6	)%
Cost of Gas		756,997		888,667		(131,670	)		(14.8	)%

Margin		484,900		469,518		15,382			3.3	%

Operations and Maintenance		163,344		164,838		(1,494	)		(0.9	)%
Depreciation		76,601		73,529		3,072			4.2	%
General Taxes		29,767		26,096		3,671			14.1	%
Utility Income Taxes		71,003		68,499		2,504			3.7	%

Total Operating Expenses		340,715		332,962		7,753			2.3	%

Operating Income		144,185		136,556		7,629			5.6	%
Other Income (Expense), net of tax		14,219		46,653		(32,434	)		(69.5	)%
Utility Interest Charges		35,259		32,152		3,107			9.7	%

Net Income	$	123,145	$	151,057	$	(27,912	)		(18.5	)%


Average Shares of Common Stock:
Basic		72,010		72,315		(305	)		(0.4	)%
Diluted		72,235		72,668		(433	)		(0.6	)%


Earnings Per Share of Common Stock:
Basic	$	1.71	$	2.09	$	(0.38	)		(18.2	)%
Diluted	$	1.70	$	2.08	$	(0.38	)		(18.3	)%

Key statistics are shown in the table below for the three months ended July 31, 2011 and 2010.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Three Months Ended July 31
	2011			2010		Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		8,602			9,395		(793	)	(8.4)%
Transportation Volumes		51,641			43,502		8,139		18.7%

Throughput		60,243			52,897		7,346		13.9%

Secondary Market Volumes		14,248			14,660		(412	)	(2.8)%

Customers Billed (at period end)		959,815			955,069		4,746		0.5%
Gross Customer Additions		2,245			2,679		(434	)	(16.2)%

Degree Days
Actual		58			24		34		141.7%
Normal		50			51		(1	)	(2.0)%
Percent colder (warmer) than normal		16.0	%		(52.9)%		n/a		n/a

Number of Employees (at period end)		1,801			1,803		(2	)	(0.1)%

Key statistics are shown in the table below for the nine months ended July 31, 2011 and 2010.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Nine Months Ended July 31
	2011			2010		Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		93,541			96,260		(2,719	)	(2.8)%
Transportation Volumes		130,122			108,046		22,076		20.4%

Throughput		223,663			204,306		19,357		9.5%

Secondary Market Volumes		39,509			35,001		4,508		12.9%

Customers Billed (at period end)		959,815			955,069		4,746		0.5%
Gross Customer Additions		7,243			8,107		(864	)	(10.7)%

Degree Days
Actual		3,410			3,393		17		0.5%
Normal		3,115			3,116		(1	)	(0.0)%
Percent colder than normal		9.5	%		8.9%		n/a		n/a

Number of Employees (at period end)		1,801			1,803		(2	)	(0.1)%

Operating Revenues

Operating revenues decreased $14.3 million for the three months ended July 31, 2011 compared with the same period in 2010 primarily due to the following:

•

$15 million of lower gas costs passed through to sales customers.

•

$4.3 million from lower revenues in secondary market transactions due to decreased activity and margins.

These decreases were partially offset by the following:

•

$2 million from increased revenues under the margin decoupling mechanism.

•

$1 million from increased volumes delivered to transportation customers.

Operating revenues decreased $116.3 million for the nine months ended July 31, 2011 compared with the same period in 2010 primarily due to $160.3 million of lower gas costs passed through to sales customers.

This decrease was partially offset by the following:

•

$29.9 million from higher revenues in secondary market transactions due to increased activity and margin.

•

$4.5 million from increased revenues under the WNA in South Carolina and Tennessee.

•

$4.1 million from increased revenues under the margin decoupling mechanism.

•

$3.4 million from increased volumes delivered to transportation customers.

Cost of Gas

Cost of gas decreased $18.4 million for the three months ended July 31, 2011 compared with the same period in 2010 primarily due to the following:

•

$9.5 million of decreased costs due to approved gas cost mechanisms.

•

$3.9 million decrease in commodity gas costs in secondary marketing transactions due to decreased activity.

•

$3 million decrease in commodity gas costs primarily from lower volumes sold and lower gas costs passed through to sales customers.

•

$2.1 million of decreased demand charges primarily due to the timing of asset manager payments, slightly offset by an increase in capacity release revenues.

Cost of gas decreased $131.7 million for the nine months ended July 31, 2011 compared with the same period in 2010 primarily due to the following:

•

$94.4 million of decreased costs due to approved gas cost mechanisms.

•

$75 million decrease in commodity gas costs primarily from lower gas costs passed through to sales customers, slightly offset by increased volumes.

These decreases were partially offset by the following:

•

$25 million increase in commodity gas costs in secondary marketing transactions due to increased activity and margins.

•

$12.7 million in increased demand charges primarily due to the timing of asset manager payments and an increase in capacity release revenues.

In all three states, we are authorized to recover from customers all prudently incurred gas costs. 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 reflected in a regulatory deferred account and are added to or deducted from cost of gas and are included in “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets.

Margin

Margin increased $4.1 million for the three months ended July 31, 2011 compared with the same period in 2010 primarily due to the following:

•

$2.8 million from increases in volumes and services to industrial and power generation customers.

•

$2.2 million in net gas cost adjustments.

These increases were partially offset by $1 million in decreased secondary market activity and margins.

Margin increased $15.4 million for the nine months ended July 31, 2011 compared with the same period in 2010 primarily due the following:

•

$6.4 million from increases in volumes and services to industrial and power generation customers.

•

$3.7 million in increased secondary market activity and margins.

•

$3.1 million from residential and commercial markets, primarily due to growth in residential customers.

•

$2.2 million in net gas cost adjustments.

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 passthrough of changes in wholesale commodity prices, which accounted for 48% of revenues for the nine months ended July 31, 2011, and transportation and storage costs, which accounted for 8%.

In general rate proceedings, state regulatory commissions authorize us to recover a margin, which is the applicable billing rate less cost of gas, on each unit of gas delivered. The commissions also authorize us to recover margin losses resulting from negotiating lower rates to industrial customers when necessary to remain competitive. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals.

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document and in our Form 10-K for the year ended October 31, 2010. 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 decreased $1.9 million for the three months ended July 31, 2011 compared with the same period in 2010 primarily due to lower payroll from decreases in long-term incentive plan accruals and contract labor expenses.

Operations and maintenance expenses decreased $1.5 million for the nine months ended July 31, 2011 compared with the same period in 2010 primarily due to lower payroll from decreases in long-term incentive plan accruals and utilities expenses, partially offset by increased vehicle and transportation expenses.

Depreciation

Depreciation expense increased $1.4 million and $3.1 million for the three months and nine months ended July 31, 2011 compared with the same periods in 2010, respectively, primarily due to increases in plant in service.

General Taxes

General taxes increased $.5 million and $3.7 million for the three months and nine months ended July 31, 2011 compared with the same periods in 2010. Changes in the quarter were insignificant. Changes in the current nine month period were primarily due to the accrual of an estimated liability for sales tax on certain customer accounts that may not qualify as exempt from sales tax.

Other Income (Expense)

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

The primary changes to Other Income (Expense) for the nine months ended July 31, 2011 compared with the same period in 2010 were from equity method investments, the gain on the sale of half of our ownership interest in SouthStar in the prior nine month period and non-operating income. All other changes were insignificant for the period.

On January 1, 2010, we sold half of our 30% membership interest in SouthStar to the other member of the joint venture and retained a 15% earnings and membership interest after the sale. The pre-tax gain on the sale was $49.7 million.

Income from equity method investments decreased $5.2 million for the nine months ended July 31, 2011 compared with the same period in 2010 due to a $5.1 million decrease in earnings from SouthStar primarily due to the recording of earnings at the new 15% ownership interest as of January 1, 2010 and SouthStar’s customer portfolio and pricing plan mix.

Non-operating income increased $1.1 million for the nine months ended July 31, 2011 compared with the same period in 2010 primarily due to increased revenues under our non-regulated warranty program, interest earned on installment loans made to our natural gas customers under our Third Party Financing Program and a state tax refund on behalf of a joint venture.

Utility Interest Charges

Utility interest charges increased $3.5 million for the three months ended July 31, 2011 compared with the same period in 2010 primarily due to the following changes:

•

$4.4 million increase in interest expense due to a decrease in interest in the borrowed allowance for funds used during construction, which is recorded as income, primarily due to $4.1 million of additional allowance for funds used during construction on several major projects in the prior year period.

•

$2 million decrease in interest expense on long-term debt primarily due to lower amounts of debt outstanding.

Utility interest charges increased $3.1 million for the nine months ended July 31, 2011 compared with the same period in 2010 primarily due to the following changes:

•

$2.2 million increase in interest related to North Carolina deferred income taxes and interest related to Tennessee sales taxes.

•

$2.1 million increase in net interest expense due to a decrease in interest charged on amounts due from customers (receivable) as those balances were lower in the current period. These receivable balances earn a carrying charge.

•

$2.1 million increase in interest expense due to a decrease in interest in the borrowed allowance for funds used during construction, which is recorded as income, primarily due to $4.1 million of additional allowance for funds used during construction on several major projects in the prior year period offset by less interest charged on lower capital expenditures and projects closed earlier in the current period.

•

$4.4 million decrease in interest expense on long-term debt primarily due to lower amounts of debt outstanding.

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. Our capital market strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities.

We believe the amounts available to us under our credit facility and the issuance of debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, pension plan contributions, common share repurchases and other cash needs.

Short-Term Borrowings . We have a $650 million three-year unsecured revolving syndicated credit facility. The facility expires in January 2014 and has an option to expand up to $850 million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. During the three months ended July 31, 2011, short-term bank borrowings ranged from $74 million to $296 million, and interest rates ranged from 1.09% to 1.12%. During the nine months ended July 31, 2011, short-term bank borrowings ranged from $74 million to $426 million, and interest rates ranged from .51% to 1.17%.

Our short-term borrowings, which consist only of the revolving syndicated credit facility, are vital in order to meet working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity, capital expenditures and approved investments. We rely on short-term borrowings along with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned capital expenditures, which are fundamental to support our system infrastructure and the growth in our customer base. We believe that our revolving syndicated credit facility, along with our access to capital markets, will allow us to meet the increased capital requirements anticipated of $392.8-$442.8 million to be spent over the next three years on the construction of facilities to provide natural gas service to various electric utility power generation customers in our service area.

Bank Borrowings

As of July 31, 2011


In thousands

End of period:
Amount outstanding	$	269,500
Weighted average interest rate		1.10	%

During the period:
Average amount outstanding	$	129,300
Weighted average interest rate		1.09	%

Maximum amount outstanding:
May	$	296,000
June		296,000
July		269,500

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

As of July 31, 2011, we had $10 million available for letters of credit under our three-year revolving syndicated credit facility, of which $3.5 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of July 31, 2011, unused lines of credit available under our three-year revolving syndicated credit facility, including the issuance of the letters of credit, totaled $377 million.

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. The major factors that affect our working capital are 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 November through March winter heating season. 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 changes in the price of natural gas, which is a function of market fluctuations in the commodity cost 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 in amounts due to or 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 bank borrowings to meet current cash requirements.

Because of the weak economy, including continued high unemployment, we may incur additional bad debt expense 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, are expected to significantly mitigate the impact these factors may have on our results of operations.

Net cash provided by operating activities was $280 million and $359.6 million for the nine months ended July 31, 2011 and 2010, respectively. Net cash provided by operating activities reflects a $27.9 million decrease in net income for 2011 compared with 2010, which included the gain on the sale of half of our interest in SouthStar as discussed in “Results of Operations” above. The effect of changes in working capital on net cash provided by operating activities is described below:

•

Trade accounts receivable and unbilled utility revenues increased $10.1 million in the current period primarily due to total throughput which increased 19.4 million dekatherms as compared with the same prior period, largely from the transportation of gas for industrial customers and for power generation, slightly offset by lower gas costs in 2011 compared with 2010 and a decrease in unbilled volumes. Weather during the current period was .5% colder than the same prior period. Volumes sold to residential and commercial customers decreased 1.9 million dekatherms.

•

Net amounts due from customers decreased $48.2 million primarily due to the collection of deferred gas costs through rates.

•

Gas in storage decreased $10 million in the current period primarily due to a decrease in the weighted average cost of gas purchased for injections and increased withdrawals from gas in storage.

•

Prepaid gas costs decreased $10.3 million in the current period primarily due to gas sold during the past winter heating season, partially offset by purchases during the summer for the next winter heating season. 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 start of the winter heating season.

•

Trade accounts payable increased $6.7 million in the current period primarily due to gas purchases for storage to meet customer demand for the next winter heating season.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and 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 $4.7 million and $9.2 million in the nine months ended July 31, 2011 and 2010, 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 “Amounts due from customers” or “Amounts due to customers” in the consolidated balance sheets for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism reduced margin by $11.1 million and $15.1 million in the nine months ended July 31, 2011 and 2010, 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, as well as the value of the US dollar versus other currencies. 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 and maintaining a safe and reliable system.

Cash Flows from Investing Activities . Net cash used in investing activities was $138 million and $83.7 million for the nine months ended July 31, 2011 and 2010, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures of $137.6 million for the nine months ended July 31, 2011 were comparable with the same prior period of $141.7 million.

We have a substantial capital expansion program for the construction of transmission and distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Significant utility construction expenditures are expected to meet long-term growth, including the power generation market, and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed.

In October 2009, we reached an agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. The agreement, approved by the NCUC in May 2010, calls for us to construct 38 miles of 20-inch transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2012. We began construction in February 2010. Our investment in the pipeline and compression facilities is currently estimated at $110-$125 million and is supported by a long-term service agreement. We have incurred $15.6 million on this project as of July 31, 2011. To provide the additional delivery service, we have executed an agreement with Cardinal to expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This will require Cardinal to spend an estimated $48 million to expand its system. As a 21.49% equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of July 31, 2011, our contributions to date related to this system expansion were $6.2 million. For further information regarding this agreement, see Note 8 to the consolidated financial statements.

In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement, also approved by the NCUC in May 2010, calls for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2013. We began construction in May 2010. Our investment in the pipeline and compression facilities is currently estimated at $300-$335 million, and our service to Progress Energy Carolinas is supported by a long-term service agreement. A portion of the cost of this project will serve our other customers and will be included in our rate base. We have incurred $16.5 million on this project as of July 31, 2011.

The Sutton facilities will also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. At the present time with the timing and design scope of the Sutton facilities, there is no current need to proceed with our previously announced Robeson LNG peak storage project. The timing and design scope of the expansion of our facilities in Robeson County will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate.

During the first quarter of fiscal 2011, we placed into service natural gas delivery pipeline and compression facilities for natural gas delivery service to a Progress Energy Carolinas power generation facility located in Richmond County, North Carolina. As of July 31, 2011, we have incurred $24.9 million on this project.

During the first quarter of fiscal 2011, we also placed into service natural gas delivery pipeline facilities for natural gas delivery service to a Duke Energy Carolinas power generation facility located in Rowan County, North Carolina. As of July 31, 2011, we have incurred $30 million on this project. We have a second agreement with Duke Energy Carolinas to construct natural gas delivery pipeline facilities to provide delivery service to their Rockingham County, North Carolina power generation facility scheduled for service in November 2011. As of July 31, 2011, we have incurred $.6 million on this project and expect to incur an additional $5.7 million to complete it.

On January 1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC. For further information regarding the sale, see Note 8 to the consolidated financial statements.

Cash Flows from Financing Activities . Net cash used in financing activities was $42.9 million and $278.3 million for the nine months ended July 31, 2011 and 2010, respectively. Funds are primarily provided from bank borrowings and the issuance of common stock through our DRIP and our ESPP, 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 retire long-term debt, pay down outstanding short-term bank borrowings, repurchase common stock under the common stock repurchase program and pay quarterly dividends on our common stock. As of July 31, 2011, our current assets were $358.9 million and our current liabilities were $488.3 million primarily due to seasonal requirements as discussed above and the draw of an additional $100 million under our revolving syndicated credit facility due to the state of the financial markets.

Outstanding short-term bank borrowings increased from $242 million as of October 31, 2010 to $269.5 million as of July 31, 2011. For further information on bank borrowings, see the previous discussion of “Short-Term Borrowings” in Financial Condition and Liquidity.

On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes with an aggregate principal balance of $196.8 million with short-term bank borrowings under the revolving syndicated credit facility. On June 6, 2011, we issued $40 million of unsecured senior notes maturing in 2016 at an interest rate of 2.92% and $160 million of unsecured senior notes maturing in 2021 at an interest rate of 4.24%. We used the proceeds from the sale of the senior notes to reduce our short-term borrowings as well as for other general corporate purposes and working capital needs. The replacement of this higher rate debt with lower rate debt will provide annual interest savings of $4.3 million. We do not anticipate issuing any other long-term debt in fiscal 2011.

We may issue approximately $225 million of long-term debt in our fiscal year 2012 for general corporate purposes, including pipeline and compression facilities to serve power generation projects. We continually monitor customer growth trends and opportunities in our markets along with the economic recovery of our service area for the timing of any infrastructure investments that would require the need for additional long-term debt.

The balance of $60 million of our 6.55% medium-term notes becomes due in September 2011 and will be paid from working capital and short-term borrowings.

During the nine months ended July 31, 2011 and 2010, we issued $15.4 million and $14.3 million, respectively, of common stock through DRIP and ESPP. From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2 in this Form 10-Q. Upon repurchase, such shares are cancelled and become authorized shares available for issuance. During the nine months ended July 31, 2011, we repurchased and retired .8 million shares for $23 million under our Common Stock Open Market Purchase Program, leaving a balance of 3,710,074 shares available for repurchase under the program. During the nine months ended July 31, 2010, we repurchased 1.8 million shares for $47.3 million under the program.

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, 2011, our retained earnings were not restricted. On September 8, 2011, the Board of Directors declared a quarterly dividend on common stock of $.29 per share, payable October 14, 2011 to shareholders of record at the close of business on September 23, 2011.

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, 2011, our capitalization, including current maturities of long-term debt, consisted of 42% in long-term debt and 58% 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, 2011 and 2010, and October 31, 2010, are summarized in the table below.


	July 31					October 31					July 31
In thousands	2011		Percentage			2010		Percentage			2010		Percentage
Short-term debt	$	269,500		13	%	$	242,000		12	%	$	122,000		6	%
Current portion of long-term debt		60,000		3	%		60,000		3	%		60,000		3	%
Long-term debt		675,000		34	%		671,922		35	%		732,010		39	%

Total debt		1,004,500		50	%		973,922		50	%		914,010		48	%
Common stockholders’ equity		1,022,238		50	%		964,941		50	%		988,815		52	%

Total capitalization (including short-term debt)	$	2,026,738		100	%	$	1,938,863		100	%	$	1,902,825		100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flows relative to average total debt, net cash flow to capital expenditures, pre-tax interest coverage, 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 business strategy and management, corporate governance guidelines and practices, stability of regulation in the jurisdictions in which we operate, risks and controls inherent in the distribution of natural gas, industry position, predictability of cash flows and contingencies.

As of July 31, 2011, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. Credit ratings and outlooks are opinions of the rating agency and are subject to their ongoing review. A significant decline in our operating performance or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit

ratings by our rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. 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 bank 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 of our debt agreements. As of July 31, 2011, 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, 2011, there were no material changes to our estimated future contractual obligations in Management’s Discussion and Analysis in this Form 10-Q compared to what we disclosed in our Form 10-K for the year ended October 31, 2010.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than letters of credit and operating leases. The letters of credit and operating leases were discussed in Note 4 and Note 7, respectively, to the consolidated financial statements in our Form 10-K for the year ended October 31, 2010.

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 these critical accounting estimates presented in our Form 10-K for the year ended October 31, 2010 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, 2010.

Accounting Guidance

For information regarding recently issued accounting guidance, see Note 1 to the consolidated financial statements in this Form 10-Q.

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 program and with the direction of the EPRMC. 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.

During the nine months ended July 31, 2011, there were no material changes in the way that we monitor and manage market risk and credit risk in accordance with our policies and procedures. Our exposure to and management of interest rate risk, commodity price risk and weather risk has remained the same during the nine months ended July 31, 2011. Our annual discussion of market risk was set forth in Item 7A of our Form 10-K as of October 31, 2010.

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 in this Form 10-Q.

As of July 31, 2011, we had $269.5 million of bank debt outstanding under our syndicated revolving credit facility at an interest rate of 1.10%. The carrying amount of our bank debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our bank debt would have caused a change in interest expense of approximately $1.4 million during the nine months ended July 31, 2011.

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 2011 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, 2011, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2010.

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

a) Sale of Unregistered Equity Securities.

None.

c) Issuer Purchases of Equity Securities.

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended July 31, 2011.


Period	Total Number of Shares Purchased	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet be Purchased Under the Program (1)
Beginning of the period				3,710,074
05/01/11 - 05/31/11	—	$—	—	3,710,074
06/01/11 - 06/30/11	—	$—	—	3,710,074
07/01/11 - 07/31/11	—	$—	—	3,710,074

Total	—	$—	—

(1)

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 and stock purchase, employee 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. The additional four million shares were referred to as our accelerated share repurchase (ASR) 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, 2011, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 6. Exhibits

Compensatory Contract:


10.1		Resolution of Board of Directors, June 3, 2011, establishing compensation for non-management directors


Other:

4.1		Form of 2.92% Series A Senior Notes due June 6, 2016 (Exhibit 4.1, Form 8-K dated May 12, 2011)

4.2		Form of 4.24% Series B Senior Notes due June 6, 2021 (Exhibit 4.2, Form 8-K dated May 12, 2011)

4.3		Fourth Supplemental Indenture, dated as of May 6, 2011, between Piedmont Natural Gas Company, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.2, Form S-3-ASR Registration Statement No. 333-175386)

10.2		Note Purchase Agreement, dated as of May 6, 2011, among Piedmont Natural Gas Company, Inc. and the Purchasers party thereto (Exhibit 10, Form 8-K dated May 12, 2011)

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

101.INS		XBRL Instance Document (1)

101.SCH		XBRL Taxonomy Extension Schema (1)

101.CAL		XBRL Taxonomy Calculation Linkbase (1)

101.DEF		XBRL Taxonomy Definition Linkbase (1)

101.LAB		XBRL Taxonomy Extension Label Linkbase (1)

101.PRE		XBRL Taxonomy Extension Presentation Linkbase (1)

(1)	Furnished, not filed.

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at July 31, 2011 and October 31, 2010; (3) Consolidated Statements of Operations for the three months and nine months ended July 31, 2011 and 2010; (4) Consolidated Statements of Cash Flows for the nine months ended July 31, 2011 and 2010; (5) Consolidated Statements of Comprehensive Income for the three months and nine months ended July 31, 2011 and 2010; and (6) Notes to Consolidated Financial Statements.

Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed as part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				Piedmont Natural Gas Company, Inc.
				(Registrant)

Date September 9, 2011				/s/ David J. Dzuricky
				David J. Dzuricky
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)

Date September 9, 2011				/s/ Jose M. Simon
				Jose M. Simon
				Vice President and Controller
				(Principal Accounting Officer)