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

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

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No

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

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(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). o Yes þ No

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

Class		Outstanding at May 31, 2011
Common Stock, no par value		71,977,343

 

 

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

April 30, 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			42
Item 4.		Controls and Procedures			43
Part II.		Other Information
Item 1.		Legal Proceedings			43
Item 1A.		Risk Factors			43
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			43
Item 6.		Exhibits			44
		Signatures			46
EX-10.1
EX-10.2
EX-10.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

Part I. Financial Information

Item 1. Financial Statements

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

		April 30,				October 31,
		2011				2010
ASSETS
Utility Plant:
Utility plant in service		$	3,332,302			$	3,176,312
Less accumulated depreciation			948,926				917,300
Utility plant in service, net			2,383,376				2,259,012
Construction work in progress			94,724				171,901
Plant held for future use			6,751				6,751
Total utility plant, net			2,484,851				2,437,664
Other Physical Property, at cost (net of accumulated depreciation of $768 in 2011 and $729 in 2010)			490				528
Current Assets:
Cash and cash equivalents			9,326				5,619
Trade accounts receivable (less allowance for doubtful accounts of $4,696 in 2011 and $929 in 2010)			112,450				62,370
Income taxes receivable			—				24,856
Other receivables			2,344				2,289
Unbilled utility revenues			21,588				21,337
Inventories:
Gas in storage			79,615				101,734
Materials, supplies and merchandise			2,807				4,547
Gas purchase derivative assets, at fair value			5,599				2,819
Amounts due from customers			1,834				62,336
Prepayments			15,228				39,832
Other current assets			103				101
Total current assets			250,894				327,840
Noncurrent Assets:
Equity method investments in non-utility activities			83,097				80,287
Goodwill			48,852				48,852
Marketable securities, at fair value			1,571				997
Overfunded postretirement asset			39,792				17,342
Regulatory asset for postretirement benefits			63,961				64,775
Unamortized debt expense			10,262				8,576
Regulatory cost of removal asset			18,571				17,825
Other noncurrent assets			55,459				48,589
Total noncurrent assets			321,565				287,243
Total		$	3,057,800			$	3,053,275

See notes to consolidated financial statements.

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

		April 30,				October 31,
		2011				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: 71,961 in 2011 and 72,282 in 2010			436,293				445,640
Retained earnings			610,620				519,831
Accumulated other comprehensive income (loss)			31				(530	)
Total stockholders’ equity			1,046,944				964,941
Long-term debt			475,000				671,922
Total capitalization			1,521,944				1,636,863
Current Liabilities:
Current maturities of long-term debt			256,843				60,000
Bank debt			103,500				242,000
Trade accounts payable			63,965				66,019
Other accounts payable			32,283				49,645
Income taxes accrued			15,989				—
Accrued interest			20,494				20,134
Customers’ deposits			28,118				25,631
Deferred income taxes			124				4,933
General taxes accrued			9,815				20,100
Amounts due to customers			18,733				—
Other current liabilities			5,696				10,098
Total current liabilities			555,560				498,560
Noncurrent Liabilities:
Deferred income taxes			477,270				429,225
Unamortized federal investment tax credits			1,960				2,145
Accumulated provision for postretirement benefits			15,190				14,805
Cost of removal obligations			449,800				436,072
Other noncurrent liabilities			36,076				35,605
Total noncurrent liabilities			980,296				917,852
Commitments and Contingencies (Note 14)
Total		$	3,057,800			$	3,053,275

See notes to consolidated financial statements.

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

		Three Months Ended								Six Months Ended
		April 30								April 30
		2011				2010				2011				2010
Operating Revenues		$	392,567			$	472,846			$	1,044,623			$	1,146,582
Cost of Gas			219,636				304,168				641,686				754,962
Margin			172,931				168,678				402,937				391,620
Operating Expenses:
Operations and maintenance			58,936				57,503				109,994				109,542
Depreciation			25,425				24,483				50,472				48,838
General taxes			9,464				8,758				20,561				17,343
Utility income taxes			26,179				25,709				78,114				75,871
Total operating expenses			120,004				116,453				259,141				251,594
Operating Income			52,927				52,225				143,796				140,026
Other Income (Expense):
Income from equity method investments			12,384				13,309				20,140				25,142
Gain on sale of interest in equity method investment			—				—				—				49,674
Non-operating income			470				221				638				315
Non-operating expense			(794	)			(1,013	)			(1,179	)			(1,376	)
Income taxes			(4,716	)			(4,906	)			(7,667	)			(28,892	)
Total other income (expense)			7,344				7,611				11,932				44,863
Utility Interest Charges:
Interest on long-term debt			12,071				13,251				24,171				26,526
Allowance for borrowed funds used during construction			(1,341	)			(782	)			(3,675	)			(1,302	)
Other			2,133				542				3,384				(909	)
Total utility interest charges			12,863				13,011				23,880				24,315
Net Income		$	47,408			$	46,825			$	131,848			$	160,574
Average Shares of Common Stock:
Basic			71,824				71,788				72,012				72,492
Diluted			72,061				72,118				72,279				72,842
Earnings Per Share of Common Stock:
Basic		$	0.66			$	0.65			$	1.83			$	2.22
Diluted		$	0.66			$	0.65			$	1.82			$	2.20
Cash Dividends Per Share of Common Stock		$	0.29			$	0.28			$	0.57			$	0.55

See notes to consolidated financial statements.

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

		Six Months Ended
		April 30
		2011				2010
Cash Flows from Operating Activities:
Net income		$	131,848			$	160,574
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			52,481				51,231
Amortization of investment tax credits			(185	)			(181	)
Allowance for doubtful accounts			3,767				3,912
Gain on sale of interest in equity method investment, net of tax			—				(30,222	)
Net gain on sale of property			—				(133	)
Income from equity method investments			(20,140	)			(25,142	)
Distributions of earnings from equity method investments			13,177				27,433
Deferred income taxes			42,873				(4,447	)
Changes in assets and liabilities:
Gas purchase derivatives, at fair value			(2,780	)			(7,736	)
Receivables			(54,276	)			(52,561	)
Inventories			23,859				20,902
Amounts due from/to customers			79,235				147,575
Settlement of legal asset retirement obligations			(1,113	)			(634	)
Overfunded postretirement asset			(22,450	)			(10,598	)
Regulatory asset for postretirement benefits			814				466
Other assets			43,825				71,578
Accounts payable			(14,374	)			(18,610	)
Provision for postretirement benefits			385				(10,493	)
Other liabilities			7,903				37,664
Net cash provided by operating activities			284,849				360,578
Cash Flows from Investing Activities:
Utility construction expenditures			(89,428	)			(70,039	)
Allowance for funds used during construction			(3,675	)			(1,302	)
Contributions to equity method investments			(3,892	)			—
Distributions of capital from equity method investments			8,968				701
Proceeds from sale of interest in equity method investment			—				57,500
Proceeds from sale of property			765				1,210
Investments in marketable securities			(450	)			(468	)
Other			992				204
Net cash used in investing activities			(86,720	)			(12,194	)

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

		Six Months Ended
		April 30
		2011				2010
Cash Flows from Financing Activities:
Borrowings under bank debt		$	944,000			$	558,000
Repayments under bank debt			(1,082,500	)			(828,500	)
Retirement of long-term debt			(79	)			(384	)
Expenses related to issuance of credit facility			(2,155	)			—
Issuance of common stock through dividend reinvestment and employee stock plans			10,426				9,817
Repurchases of common stock			(23,004	)			(47,282	)
Dividends paid			(41,104	)			(39,909	)
Other			(6	)			(694	)
Net cash used in financing activities			(194,422	)			(348,952	)
Net Increase (Decrease) in Cash and Cash Equivalents			3,707				(568	)
Cash and Cash Equivalents at Beginning of Period			5,619				7,558
Cash and Cash Equivalents at End of Period		$	9,326			$	6,990
Noncash Investing and Financing Activities:
Accrued construction expenditures		$	5,045			$	819
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								Six Months Ended
		April 30								April 30
		2011				2010				2011				2010
Net Income		$	47,408			$	46,825			$	131,848			$	160,574
Other Comprehensive Income:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($66) and ($540) for the three months ended April 30, 2011 and 2010, respectively, and $55 and ($171) for the six months ended April 30, 2011 and 2010, respectively			(104	)			(838	)			81				(265	)
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $56 and $456 for the three months ended April 30, 2011 and 2010, respectively, and $308 and $884 for the six months ended April 30, 2011 and 2010, respectively			87				708				480				1,372
Total Comprehensive Income		$	47,391			$	46,695			$	132,409			$	161,681

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 April 30, 2011 and October 31, 2010, the results of operations for the three months and six months ended April 30, 2011 and 2010, and cash flows for the six months ended April 30, 2011 and 2010. Our business is seasonal in nature. The results of operations for the three months and six months ended April 30, 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 six months ended April 30, 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 April 30, 2011 and October 31, 2010 are as follows.

		April 30,				October 31,
In thousands		2011				2010
Regulatory assets		$	141,810			$	197,772
Regulatory liabilities			470,654				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 into 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 April 30, 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 April 30, 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.

		April 30,
In thousands		2011
Third party financing program loans outstanding		$	6,432

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

		Three Months
		Ended
In thousands		April 30, 2011
Balance at beginning of period		$	187
Additions charged to uncollectibles expense			56
Accounts written off, net of recoveries			(3	)
Balance at end of period		$	240

     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 July 2010, the FASB issued accounting guidance to improve disclosures about the credit quality of an entity’s financing receivables and the reserves held against them. End of reporting period disclosures are required for the reporting period ending on or after December 15, 2010. The disclosures about activity that occurred during a reporting period were effective for interim and annual periods beginning on or after December 15, 2010. We adopted the guidance for the end of period disclosures as of January 31, 2011, and the guidance for the disclosures related to activity in the reporting period during our fiscal second quarter beginning February 1, 2011. The disclosure is set forth above in “Financing Receivables.” Since the guidance addresses only disclosures related to credit quality of financing receivables and the allowance for credit losses, the adoption of this guidance did not 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.

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 April 20, 2011, the TRA staff filed their compliance audit report that recommended approval of our TIP account balances. On May 9, 2011, the TRA passed a motion approving the findings and recommendations of the TRA staff’s compliance audit report.

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. 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 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. We are unable to predict the outcome of this proceeding at this time.

On February 24, 2011, the Office of Regulatory Staff requested that the PSCSC suspend the commission-approved gas hedging programs operated by the regulated gas utilities in South Carolina due to more moderate market conditions currently existing for the cost of natural gas. This suspension of the hedging program is 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 purchased gas adjustment (PGA) proceedings. 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 May 25, 2011, the PSCSC voted to open a new, generic docket on this issue to expand the discussion to include the state’s regulated electric utilities as well. 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.

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 six months ended April 30, 2011 and 2010 is presented below.

		Three Months								Six Months
In thousands except per share amounts		2011				2010				2011				2010
Net Income		$	47,408			$	46,825			$	131,848			$	160,574
Average shares of common stock outstanding for basic earnings per share			71,824				71,788				72,012				72,492
Contingently issuable shares under incentive compensation plans			237				330				267				350
Average shares of dilutive stock			72,061				72,118				72,279				72,842
Earnings Per Share of Common Stock:
Basic		$	0.66			$	0.65			$	1.83			$	2.22
Diluted		$	0.66			$	0.65			$	1.82			$	2.20

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 April 30, 2011 and October 31, 2010 is as follows.

		April 30, 2011								October 31, 2010
						Fair								Fair
In thousands		Cost				Value				Cost				Value
Current trading securities:
Money markets		$	—			$	—			$	—			$	—
Mutual funds			6				7				4				5
Total current trading securities			6				7				4				5
Noncurrent trading securities:
Money markets			218				218				254				254
Mutual funds			1,105				1,353				618				743
Total noncurrent trading securities			1,323				1,571				872				997
Total trading securities		$	1,329			$	1,578			$	876			$	1,002

5. Capital Stock

On January 10, 2011, we entered into an accelerated share repurchase (ASR) agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $27.79 per share. The settlement and retirement of those shares occurred on January 11, 2011. Total consideration paid to purchase the shares of $22.2 million was recorded in “Stockholders’ equity” as a reduction in “Common stock.”

As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that was expected to mature in approximately 48 trading days, or March 18, 2011. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, were required to either pay cash or issue registered or unregistered shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.10 discount, was higher than the initial purchase closing price. The investment bank was required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.10 discount, for the shares purchased was lower than the initial purchase closing price. At settlement on March 21, 2011, we paid cash of $.8 million to the investment bank and recorded this amount in “Stockholders’ equity” as a reduction of “Common Stock” in the consolidated balance sheets. The $.8 million was the difference between the investment bank’s weighted average purchase price of $28.8551 less a discount of $.10 for a settlement price of $28.7551 and the initial purchase closing price of $27.79 per share multiplied by 800,000 shares.

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 April 30, 2011 and 2010 are presented below.

		Qualified Pension								Nonqualified Pension								Other Benefits
In thousands		2011				2010				2011				2010				2011				2010
Service cost		$	2,225			$	2,100			$	11			$	10			$	350			$	334
Interest cost			2,700				2,850				52				61				374				476
Expected return on plan assets			(5,150	)			(4,775	)			—				—				(384	)			(345	)
Amortization of transition obligation			—				—				—				—				167				167
Amortization of prior service (credit) cost			(550	)			(550	)			5				5				—				—
Amortization of actuarial loss			775				550				11				2				—				59
Total		$	—			$	175			$	79			$	78			$	507			$	691

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the six months ended April 30, 2011 and 2010 are presented below.

		Qualified Pension								Nonqualified Pension								Other Benefits
In thousands		2011				2010				2011				2010				2011				2010
Service cost		$	4,450			$	4,200			$	23			$	19			$	699			$	669
Interest cost			5,400				5,700				104				121				747				953
Expected return on plan assets			(10,300	)			(9,550	)			—				—				(767	)			(691	)
Amortization of transition obligation			—				—				—				—				334				334
Amortization of prior service (credit) cost			(1,100	)			(1,100	)			10				10				—				—
Amortization of actuarial loss			1,550				1,100				21				5				—				118
Total		$	—			$	350			$	158			$	155			$	1,013			$	1,383

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 six months ended April 30, 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; we make no contributions to this plan. Both deferred compensation plans are funded through a rabbi trust with a bank as the trustee. As of April 30, 2011, we have a liability of $1.7 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” in the consolidated statements of income. Operations of the non-utility activities segment are included in the consolidated statements of income in “Income from equity method investments” and “Non-operating income.”

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the consolidated financial statements in our Form 10-K for the year ended October 31, 2010.

Operations by segment for the three months and six months ended April 30, 2011 and 2010 are presented below.

		Regulated								Non-utility
In thousands		Utility								Activities								Total
		2011				2010				2011				2010				2011				2010
Three Months
Revenues from external customers		$	392,567			$	472,846			$	—			$	—			$	392,567			$	472,846
Margin			172,931				168,678				—				—				172,931				168,678
Operations and maintenance expenses			58,936				57,503				17				111				58,953				57,614
Gain from sale of interest in equity method investment			—				—				—				—				—				—
Income from equity method investments			—				—				12,384				13,309				12,384				13,309
Operating income (loss) before income taxes			79,106				77,934				(24	)			(118	)			79,082				77,816
Income before income taxes			65,932				64,250				12,371				13,190				78,303				77,440
Six Months
Revenues from external customers		$	1,044,623			$	1,146,582			$	—			$	—			$	1,044,623			$	1,146,582
Margin			402,937				391,620				—				—				402,937				391,620
Operations and maintenance expenses			109,994				109,542				47				234				110,041				109,776
Gain from sale of interest in equity method investment			—				—				—				49,674				—				49,674
Income from equity method investments			—				—				20,140				25,142				20,140				25,142
Operating income (loss) before income taxes			221,910				215,897				(143	)			(330	)			221,767				215,567
Income before income taxes			197,621				190,849				20,008				74,488				217,629				265,337

Reconciliations to the consolidated statements of income for the three months and six months ended April 30, 2011 and 2010 are presented below.

		Three Months								Six Months
In thousands		2011				2010				2011				2010
Operating Income:
Segment operating income before income taxes		$	79,082			$	77,816			$	221,767			$	215,567
Utility income taxes			(26,179	)			(25,709	)			(78,114	)			(75,871	)
Non-utility activities before income taxes			24				118				143				330
Operating income		$	52,927			$	52,225			$	143,796			$	140,026
Net Income:
Income before income taxes for reportable segments		$	78,303			$	77,440			$	217,629			$	265,337
Income taxes			(30,895	)			(30,615	)			(85,781	)			(104,763	)
Net income		$	47,408			$	46,825			$	131,848			$	160,574

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 income.

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 North Carolina Utilities Commission (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 as much as $53.1 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 as much as $11.4 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 April 30, 2011, our contributions to date related to this expansion were $3.9 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 July 1, 2012. In addition, 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 six months ended April 30, 2011 and 2010, these transportation costs and the amounts we owed Cardinal as of April 30, 2011 and October 31, 2010 are as follows.

		Three Months								Six Months
In thousands		2011				2010				2011				2010
Transportation costs		$	1,001			$	1,001			$	2,035			$	2,035

		April 30,				October 31,
		2011				2010
Trade accounts payable		$	337			$	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 six months ended April 30, 2011 and 2010, these gas storage costs and the amounts we owed Pine Needle as of April 30, 2011 and October 31, 2010 are as follows.

		Three Months								Six Months
In thousands		2011				2010				2011				2010
Gas storage costs		$	2,714			$	3,104			$	5,641			$	6,313

		April 30,				October 31,
		2011				2010
Trade accounts payable		$	840			$	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 six months ended April 30, 2011 and 2010, our operating revenues from these sales and the amounts SouthStar owed us as of April 30, 2011 and October 31, 2010 are as follows.

		Three Months								Six Months
In thousands		2011				2010				2011				2010
Operating revenues		$	666			$	1,124			$	635			$	1,061

		April 30,				October 31,
		2011				2010
Trade accounts receivable		$	744			$	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. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia that is regulated by the FERC.

We have related party transactions as a customer of Hardy Storage and record in cost of gas the storage costs charged by Hardy Storage. For each period of the three months and six months ended April 30, 2011 and 2010, these gas storage costs and the amounts we owed Hardy Storage as of April 30, 2011 and October 31, 2010 are as follows.

		Three Months								Six Months
In thousands		2011				2010				2011				2010
Gas storage costs		$	2,425			$	2,300			$	4,851			$	4,535

		April 30,				October 31,
		2011				2010
Trade accounts payable		$	780			$	808

9. Variable Interest Entities

Effective November 1, 2010, we adopted the 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 April 30, 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. As of April 30, 2011, our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. Our investment balances are as follows.

		April 30,				October 31,
In thousands		2011				2010
Cardinal		$	15,770			$	11,837
Pine Needle			19,263				21,810
SouthStar			17,919				17,146
Hardy Storage			30,145				29,494
Total equity method investments in non-utility activities		$	83,097			$	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. The adoption of this guidance on November 1, 2010 for these arrangements, contracts and other agreements did not have a material impact on our financial position, results of operations or cash flows.

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 April 30, 2011 and October 31, 2010, we had long gas purchase options providing total coverage of 26.5 million dekatherms and 33.5 million dekatherms, respectively. The long gas purchase options held at April 30, 2011 are for the period from June 2011 through April 2012.

     Fair Value Measurements

In developing our fair value measurements of our 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 April 30, 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 April 30, 2011 and 2010.

Recurring Fair Value Measurements as of April 30, 2011

						Significant
		Quoted Prices				Other				Significant
		in Active				Observable				Unobservable				Total
		Markets				Inputs				Inputs				Carrying
In thousands		(Level 1)				(Level 2)				(Level 3)				Value
Assets:
Derivatives held for distribution operations		$	5,599			$	—			$	—			$	5,599
Debt and equity securities held as trading securities:
Money markets			218				—				—				218
Mutual funds			1,360				—				—				1,360
Total fair value assets		$	7,177			$	—			$	—			$	7,177

Recurring Fair Value Measurements as of October 31, 2010

						Significant
		Quoted Prices				Other				Significant
		in Active				Observable				Unobservable				Total
		Markets				Inputs				Inputs				Carrying
In thousands		(Level 1)				(Level 2)				(Level 3)				Value
Assets:
Derivatives held for distribution operations		$	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 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.

		Carrying
In thousands		Amount				Fair Value
As of April 30, 2011		$	731,843			$	828,297
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 April 30, 2011 and October 31, 2010.

Fair Value of Derivative Instruments

		Fair Value				Fair Value
In thousands		April 30, 2011				October 31, 2010
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets — Gas purchase derivative assets (June 2011-April 2012)		$	5,599
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 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 income for the three months and six months ended April 30, 2011 and 2010, absent the regulatory treatment under our approved PGA procedures.

																		Location of Loss
																		Recognized through
		Amount of Loss Recognized on Derivatives and Deferred Under PGA Procedures																PGA Procedures
		Three Months Ended								Six Months Ended
		April 30								April 30
In thousands		2011				2010				2011				2010
Gas purchase options		$	1,903			$	17,126			$	6,125			$	33,776			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 pre-approved by the PSCSC for recovery from customers subject to the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are not pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding by the NCUC.

     Risk Management

Our 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 six months ended April 30, 2011 and 2010, we paid principal amounts of $.1 million and $.4 million, respectively, to noteholders of the 6.25% insured quarterly notes. These notes have a redemption right upon the death of the owner of the notes, within specified limitations.

On April 25, 2011, at our direction, the Trustee notified the noteholders of the 6.25% insured quarterly notes that we will redeem all of the notes on June 1, 2011, which have an aggregate principal balance of $196.8 million. As we have notified the noteholders of the redemption, we have reclassified the principal balance to “Current maturities of long-term debt” in the consolidated balance sheets.

On June 6, 2011, we intend to issue 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%. For information on the issuance of this debt, see Note 15 to the consolidated financial statements in this Form 10-Q.

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 April 30, 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 $103.5 million, as of April 30, 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 April 30, 2011, short-term bank borrowings ranged from $87 million to $306 million, and interest rates ranged from 1.12% to 1.17% (weighted average of 1.16%). During the six months ended April 30, 2011, short-term bank borrowings ranged from $87 million to $426 million, and interest rates ranged from .51% to 1.17% (weighted average of .78%). 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 45% at April 30, 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 six months ended April 30, 2011 and 2010, we recorded compensation expense, and as of April 30, 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 six months ended April 30, 2011, we recorded compensation expense, and as of April 30, 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% and 30% of the shares vested on September 1, 2009 and 2010, respectively. The remaining 50% of the shares will vest on September 1, 2011. For the three months and six months ended April 30, 2011 and 2010, we recorded compensation expense, and as of April 30, 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 six months ended April 30, 2011 and 2010, and the amounts recorded as liabilities as of April 30, 2011 and October 31, 2010 are presented below.

		Three Months								Six Months
In thousands		2011				2010				2011				2010
Compensation expense		$	1,244			$	1,955			$	2,166			$	4,729

		April 30,				October 31,
		2011				2010
Liability		$	5,932			$	9,914

On a quarterly basis, we issue shares of common stock under the employee stock purchase plan (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 21 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 income as part of gas purchases and included in cost of gas.

     Leases

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

     Legal

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 April 30, 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 and paid $5.3 million, charged to the estimated environmental liability, that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.

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. Although the soil and groundwater remediation report was approved by NCDENR, we will continue to and are currently conducting periodic groundwater monitoring at this site. We have incurred $1.4 million on this site through April 30, 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 are currently conducting periodic groundwater monitoring at the site per the final consent order. We have incurred $1.5 million through April 30, 2011 for this remediation.

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

At our Huntersville LNG facility, we are continuing to address the remaining remediation issues, including monitoring groundwater contamination and removing lead-based paint, with the latter scheduled to be finished in our fiscal year 2011. As of April 30, 2011, our estimate of the total cost to remediate the property is $3.1 million and we have incurred $2.9 million through April 30, 2011.

During the six months ended April 30, 2011, we assessed the cost to remove lead-based paint at our Nashville LNG facility, and we increased our reserve by $.5 million. 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). Only our districts in Charlotte, North Carolina and Greenville, South Carolina continue to operate USTs. Our Greenville district has begun plans to have its USTs removed in our third fiscal quarter 2011. As of April 30, 2011, our undiscounted environmental liability for USTs for which we retain remediation responsibility is $.4 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 small portions of the pipeline. Lead-based paint is being removed at multiple LNG facilities that we own. Employees have been 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 April 30, 2011, our undiscounted environmental liability totaled $2.3 million, and consisted of $1.5 million for the four MGP sites for which we retain remediation responsibility, $.4 million for the LNG facilities and $.4 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.

On June 1, 2011, we redeemed all of the 6.25% insured quarterly notes with an aggregate principal balance of $196.8 million. We financed the debt redemption with short-term bank borrowings under the revolving syndicated credit facility.

On June 6, 2011, we issued $40 million unsecured senior notes maturing in 2016 that bear an interest rate of 2.92% and $160 million unsecured senior notes maturing in 2021 that bear 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.

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. Please reference our website at www.piedmontng.com

for current information. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website as soon as reasonably practicable after the report is filed with or furnished to the SEC.

Executive Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 53,000 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 six months ended April 30, 2011, 91% 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 six months ended April 30, 2011, 9% of our earnings before taxes came from our non-utility activities segment, which consists of 2% from regulated non-utility activities and 7% 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 breaking the link between energy consumption and margin revenues, or decoupling as we say, 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. We are evaluating our current rate structures in Tennessee. For the fiscal year ended October 31, 2010, these rate designs stabilized our gas utility margin by providing fixed recovery of 71% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 18% 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 11% of our utility margins. For the six months ended April 30, 2011, the margin decoupling mechanism in North Carolina reduced margin by $16.2 million, and the WNA in South Carolina and Tennessee reduced margin by $4.7 million.

Our strategic focus is on our core business of providing safe, reliable and quality natural gas distribution service to our customers in the growing Southeast market area. Part of our strategic plan is to responsibly manage our gas distribution business through control of our operating costs, implementation of new technologies and sound rate and regulatory initiatives. To enhance the value and growth of our utility assets, we focus on the sound management of our capital spending, looking at projects and initiatives that will improve service for current customers and provide profitable customer growth opportunities in our service areas with an appropriate return on invested capital. We work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders. Our goal is to develop, integrate, consolidate and streamline operations and support our employees with new processes and technology to better serve our customers and to add value for our shareholders.

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

We 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 continually reviewing our business processes for quality and efficiency with a concentration on customer-oriented process improvements.

We will continue our efforts to promote the direct use of natural gas in more homes, businesses, industries and vehicles. We continue to believe that the expanded use of domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall greenhouse gas emissions and energy consumption and enhance our national energy security. Price moderation and stability of natural gas continues, which has made natural gas more competitive against other fuels.

The continued 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 for example, have historically inspected 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 likely add further requirements to our already active pipeline safety and integrity program. Currently, for example, and as one part of a holistic federal and state regulatory regime, we are on track to meet an August 2011 deadline to evaluate any risks to our distribution pipeline system (such as corrosion, leak detection) and create an action plan to address those risks. Additionally, we have transmission pipeline integrity programs composed of standard procedures and programs for pipeline safety that include 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 our greatest cause of any pipeline incidents on our system. We welcome focused efforts to improve the safety of our industry as a whole.

We have completed two projects to date in fiscal year 2011 to provide long-term gas transportation service to power generation projects in our market area. We have three projects under construction for two electric utilities in North Carolina to provide natural gas delivery service to power generation facilities currently under construction with targeted in service dates of November 2011, June 2012 and June 2013. We do not believe the planned merger of these two electric utilities will affect these projects. In addition to the environmental benefits of using natural gas at these new plants instead of coal, 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, a depressed housing market, significantly reduced new home construction and slower new commercial development. 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 customers, including the comfort, affordability, reliability 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 a projected rate of return greater than the returns allowed in our utility operations based on 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 will 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, but our initial assessment is that there will be a $130-$170 million benefit through 2014. 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 net income of $47.4 million for the three months ended April 30, 2011 as compared to $46.8 million for the same period in 2010. The following table sets forth a comparison of the components of our consolidated statements of income for the three months ended April 30, 2011 as compared with the three months ended April 30, 2010.

Income Statement Components

		Three Months Ended April 30
In thousands, except per share amounts		2011				2010				Variance				Percent Change
Operating Revenues		$	392,567			$	472,846			$	(80,279	)			(17.0	)%
Cost of Gas			219,636				304,168				(84,532	)			(27.8	)%
Margin			172,931				168,678				4,253				2.5	%
Operations and Maintenance			58,936				57,503				1,433				2.5	%
Depreciation			25,425				24,483				942				3.8	%
General Taxes			9,464				8,758				706				8.1	%
Utility Income Taxes			26,179				25,709				470				1.8	%
Total Operating Expenses			120,004				116,453				3,551				3.0	%
Operating Income			52,927				52,225				702				1.3	%
Other Income (Expense), net of tax			7,344				7,611				(267	)			(3.5	)%
Utility Interest Charges			12,863				13,011				(148	)			(1.1	)%
Net Income		$	47,408			$	46,825			$	583				1.2	%
Average Shares of Common Stock:
Basic			71,824				71,788				36				0.1	%
Diluted			72,061				72,118				(57	)			(0.1	)%
Earnings Per Share of Common Stock:
Basic		$	0.66			$	0.65			$	0.01				1.5	%
Diluted		$	0.66			$	0.65			$	0.01				1.5	%