10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended April 30, 2013

or

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

For the transition period from                                  to                                 

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

North Carolina	56-0556998
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
4720 Piedmont Row Drive, Charlotte, North Carolina	28210
(Address of principal executive offices)	(Zip Code)

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨Yes    xNo

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

Class	Outstanding at June 4, 2013
Common Stock, no par value	75,746,114

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

April 30, 2013

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		29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		50
Item 4.	Controls and Procedures		51
Part II.	Other Information
Item 1.	Legal Proceedings		51
Item 1A.	Risk Factors		51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		52
Item 6.	Exhibits		52
	Signatures		54

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)

	April 30, 2013		October 31, 2012
ASSETS
Utility Plant:
Utility plant in service	$	3,834,061	$	3,746,178
Less accumulated depreciation		1,053,073		1,036,814
Utility plant in service, net		2,780,988		2,709,364
Construction work in progress		579,035		388,979
Plant held for future use		6,743		6,743
Total utility plant, net		3,366,766		3,105,086
Other Physical Property, at cost (net of accumulated depreciation of $860 in 2013 and $843 in 2012)		399		415
Current Assets:
Cash and cash equivalents		14,901		1,959
Trade accounts receivable (less allowance for doubtful accounts of $4,427 in 2013 and $1,579 in 2012)		142,721		56,700
Income taxes receivable		29,972		31,606
Other receivables		2,086		2,104
Unbilled utility revenues		20,397		24,012
Inventories:
Gas in storage		48,557		72,661
Materials, supplies and merchandise		867		934
Gas purchase derivative assets, at fair value		4,091		3,153
Amounts due from customers		29,858		81,626
Prepayments		13,096		30,600
Other current assets		292		287
Total current assets		306,838		305,642
Noncurrent Assets:
Equity method investments in non-utility activities		94,766		87,867
Goodwill		48,852		48,852
Marketable securities, at fair value		2,806		2,131
Regulatory asset for postretirement benefits		118,435		123,290
Unamortized debt expense		12,975		13,583
Regulatory cost of removal asset		22,040		21,129
Other noncurrent assets		64,064		61,944
Total noncurrent assets		363,938		358,796
Total	$	4,037,941	$	3,769,939

See notes to consolidated financial statements.

1

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)

	April 30, 2013			October 31, 2012
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: 75,720 in 2013 and 72,250 in 2012		549,383			442,461
Retained earnings		681,497			584,848
Accumulated other comprehensive loss		(149	)		(305	)
Total stockholders’ equity		1,230,731			1,027,004
Long-term debt		875,000			975,000
Total capitalization		2,105,731			2,002,004
Current Liabilities:
Current maturities of long-term debt		100,000			-
Short-term debt		345,000			365,000
Trade accounts payable		113,101			94,269
Other accounts payable		35,010			47,699
Income taxes accrued		995			-
Accrued interest		24,741			21,450
Customers’ deposits		21,584			21,739
Deferred income taxes		994			13,542
General taxes accrued		9,283			21,504
Amounts due to customers		-			28
Other current liabilities		7,620			7,320
Total current liabilities		658,328			592,551
Noncurrent Liabilities:
Deferred income taxes		699,679			597,211
Unamortized federal investment tax credits		1,536			1,669
Accumulated provision for postretirement benefits		17,872			37,299
Cost of removal obligations		508,757			492,963
Other noncurrent liabilities		46,038			46,242
Total noncurrent liabilities		1,273,882			1,175,384
Commitments and Contingencies (Note 9)
Total	$	4,037,941		$	3,769,939

See notes to consolidated financial statements.

2

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (Unaudited)

(In thousands except per share amounts)

	Three Months Ended April 30						Six Months Ended April 30
	2013			2012			2013			2012
Operating Revenues	$	399,411		$	308,432		$	915,286		$	780,272
Cost of Gas		215,555			136,481			499,806			388,085
Margin		183,856			171,951			415,480			392,187
Operating Expenses:
Operations and maintenance		65,037			60,511			120,919			118,908
Depreciation		26,867			25,269			53,569			51,447
General taxes		9,068			9,299			18,596			17,920
Utility income taxes		31,380			28,090			84,679			75,311
Total operating expenses		132,352			123,169			277,763			263,586
Operating Income		51,504			48,782			137,717			128,601
Other Income (Expense):
Income from equity method investments		12,437			11,652			19,592			17,944
Non-operating income		742			581			1,190			641
Non-operating expense		(696	)		(626	)		(1,458	)		(1,047	)
Income taxes		(4,875	)		(4,534	)		(7,549	)		(6,852	)
Total other income (expense)		7,608			7,073			11,775			10,686
Utility Interest Charges:
Interest on long-term debt		12,652			10,005			25,327			20,028
Allowance for borrowed funds used during construction		(9,938	)		(6,053	)		(18,251	)		(10,476	)
Other		608			1,711			703			3,316
Total utility interest charges		3,322			5,663			7,779			12,868
Net Income		55,790			50,192			141,713			126,419
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $152 and ($267) for the three months ended April 30, 2013 and 2012, respectively, and $38 and ($545) for the six months ended April 30, 2013 and 2012, respectively		238			(419	)		59			(855	)
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of $49 and ($7) for the three months ended April 30, 2013 and 2012, respectively, and $63 and $265 for the six months ended April 30, 2013 and 2012, respectively		76			(11	)		97			415
Total other comprehensive income (loss)		314			(430	)		156			(440	)
Comprehensive Income	$	56,104		$	49,762		$	141,869		$	125,979
Average Shares of Common Stock:
Basic		75,463			71,731			73,884			71,931
Diluted		75,904			72,026			74,301			72,226
Earnings Per Share of Common Stock:
Basic	$	0.74		$	0.70		$	1.92		$	1.76
Diluted	$	0.74		$	0.70		$	1.91		$	1.75
Cash Dividends Per Share of Common Stock	$	0.31		$	0.30		$	0.61		$	0.59

See notes to consolidated financial statements.

3

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Six Months Ended April 30
	2013			2012
Cash Flows from Operating Activities:
Net income	$	141,713		$	126,419
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		56,954			53,727
Allowance for doubtful accounts		2,848			2,447
Net gain on sale of property		(18	)		-
Income from equity method investments		(19,592	)		(17,944	)
Distributions of earnings from equity method investments		16,276			12,164
Deferred income taxes, net		89,685			85,907
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		(938	)		166
Receivables		(85,257	)		(11,488	)
Inventories		24,171			18,685
Amounts due from/to customers		51,740			(8,931	)
Settlement of legal asset retirement obligations		(1,127	)		(637	)
Regulatory asset for postretirement benefits		4,855			2,049
Other assets		16,314			13,101
Accounts payable		(4,363	)		(22,632	)
Provision for postretirement benefits		(19,427	)		72
Other liabilities		(5,609	)		(8,632	)
Net cash provided by operating activities		268,225			244,473
Cash Flows from Investing Activities:
Utility capital expenditures		(274,895	)		(220,256	)
Allowance for funds used during construction		(18,251	)		(10,476	)
Contributions to equity method investments		(8,748	)		(3,356	)
Distributions of capital from equity method investments		5,422			4,850
Proceeds from sale of property		614			409
Investments in marketable securities		(445	)		(701	)
Other		1,513			350
Net cash used in investing activities		(294,790	)		(229,180	)

4

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Six Months Ended April 30
	2013			2012
Cash Flows from Financing Activities:
Borrowings under credit facility	$	10,000		$	345,000
Repayments under credit facility		(10,000	)		(676,000	)
Net borrowings (repayments) – commercial paper		(20,000	)		380,000
Expenses related to issuance of debt		(12	)		(2,448	)
Proceeds from issuance of common stock, net of expenses		92,286			-
Issuance of common stock through dividend reinvestment and employee stock plans		12,338			10,802
Repurchases of common stock		-			(26,528	)
Dividends paid		(45,123	)		(42,494	)
Other		18			(33	)
Net cash provided by (used in) financing activities		39,507			(11,701	)
Net Increase in Cash and Cash Equivalents		12,942			3,592
Cash and Cash Equivalents at Beginning of Period		1,959			6,777
Cash and Cash Equivalents at End of Period	$	14,901		$	10,369
Cash Paid During the Year for:
Interest	$	23,720		$	22,878
Income Taxes:
Income taxes paid	$	1,352		$	3,344
Income taxes refunded		-			-
Income taxes, net	$	1,352		$	3,344
Noncash Investing and Financing Activities:
Accrued capital expenditures	$	54,120		$	3,776

See notes to consolidated financial statements.

5

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands except per share amounts)

										Accumulated Other Comprehensive Income (Loss)
	Common Stock						Retained Earnings						Total
	Shares			Amount
Balance, October 31, 2011		72,318		$	446,791		$	550,584		$	(452	)	$	996,923
Net Income								126,419						126,419
Other Comprehensive Loss											(440	)		(440	)
Common Stock Issued		361			10,877									10,877
Common Stock Repurchased		(800	)		(26,528	)								(26,528	)
Tax Benefit from Dividends Paid on ESOP Shares								54						54
Dividends Declared ($.59 per share)								(42,494	)					(42,494	)
Balance, April 30, 2012		71,879		$	431,140		$	634,563		$	(892	)	$	1,064,811
Balance, October 31, 2012		72,250		$	442,461		$	584,848		$	(305	)	$	1,027,004
Net Income								141,713						141,713
Other Comprehensive Income											156			156
Common Stock Issued		3,470			107,280									107,280
Expenses from Issuance of Common Stock					(358	)								(358	)
Tax Benefit from Dividends Paid on ESOP Shares								59						59
Dividends Declared ($.61 per share)								(45,123	)					(45,123	)
Balance, April 30, 2013		75,720		$	549,383		$	681,497		$	(149	)	$	1,230,731

See notes to consolidated financial statements.

6

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, 2012.

Seasonality and Use of Estimates

The unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of the statement of financial position at April 30, 2013 and October 31, 2012, the results of operations for the three months and six months ended April 30, 2013 and 2012, and cash flows and stockholders’ equity for the six months ended April 30, 2013 and 2012. Our business is seasonal in nature. The results of operations for the three months and six months ended April 30, 2013 do not necessarily reflect the results to be expected for the full year.

In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the periods reported. 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 these estimates and assumptions.

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, 2012. There were no significant changes to those accounting policies during the six months ended April 30, 2013.

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 commissions 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

7

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 regulatory assets are recoverable in current rates or future rate proceedings.

Regulatory assets and liabilities in the Consolidated Balance Sheets as of April 30, 2013 and October 31, 2012 are as follows.

In thousands	April 30, 2013		October 31, 2012
Regulatory assets	$	239,106	$	293,104
Regulatory liabilities		504,470		489,692

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 12 to the consolidated financial statements in this Form 10-Q.

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, short-term debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the Consolidated Balance Sheets in accordance with derivative accounting standards and marketable securities that are held in rabbi trusts established for our deferred compensation plans and are classified as trading securities. Our qualified pension and postretirement plan assets and liabilities are recorded at fair value in the Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for 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 at the lowest level that is significant to the fair value measurement, in its entirety, in the fair value hierarchy levels as set forth in the fair value guidance.

For the fair value measurements of our derivatives and marketable securities, see Note 8 to the consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2012. For further information on our fair value methodologies, see “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2012. There were no significant changes to these fair value methodologies during the three months ended April 30, 2013.

8

Recently Issued Accounting Guidance

In December 2011, the Financial Accounting Standards Board (FASB) issued accounting guidance to improve disclosures and make information more comparable to International Financial Reporting Standards regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements in tabular format to enable users of financial statements to understand the effect of those arrangements on the entity’s financial position. The new disclosure requirements are effective for annual periods beginning after January 1, 2013 and interim periods therein and require retrospective application in all periods presented. We will adopt this offsetting disclosure guidance for the first quarter of our fiscal year ending October 31, 2014. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.

In November 2012, the FASB finalized the presentation disclosures on items reclassified from other comprehensive income. In February 2013, the FASB further clarified the presentation disclosures. This disclosure guidance, which we adopted this quarter, is effective for interim and annual periods beginning after December 15, 2012. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.

2. Regulatory Matters

In October 2012, we filed a petition with the North Carolina Utility Commission (NCUC) seeking authority to transfer $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” relates to the development of the liquefied natural gas (LNG) facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In January 2013, we filed a motion to suspend this filing in order to incorporate it into a future regulatory proceeding. On April 30, 2013, we withdrew the petition, citing our intent to file a general rate application and address the appropriate treatment of the Robeson County LNG costs in that general rate application.

On May 31, 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges for all customers to produce overall increased annual revenues of $79.8 million, or 9.3% above the current annual revenues. This represents an annual average cost increase of 1.86% since our last general rate proceeding in 2008. In this proceeding, we are seeking authorization from the NCUC to:

• Update and increase our rates and charges based on an overall rate base of $1.9 billion, an equity capital structure component of 50.7% and a return on common equity of 11.3%,

• Increase total revenues by $79.8 million, including $66.2 million related to gas utility margin and $13.6 million related to increased fixed gas costs,

• Implement a new integrity rider designed to separately track and recover the costs associated with significant levels of capital expenditures projected to be incurred to comply with federal pipeline safety and integrity requirements,

• Implement new depreciation rates to amortize the costs of assets, net of salvage value, over the estimated useful life of the assets,

• Update and revise our existing service regulations and tariffs,

• Amortize and collect certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above,

• Amortize and collect certain environmental expenses and pipeline safety and integrity compliance expenses that have been deferred in the period since our last general rate case, and

9

• Provide for ongoing annual contributions to help fund pipeline safety and integrity research.

New rates are proposed to be effective January 1, 2014. We are waiting on a hearing date to be set by the NCUC for this general rate proceeding at this time.

On February 7, 2013, the Public Service Commission of South Carolina (PSCSC) set a hearing date of July 11, 2013 for our annual review of purchased gas adjustment (PGA) and gas purchasing policies for the twelve months ended March 31, 2013. We filed our testimony in this proceeding on June 4, 2013.

In August 2012, we filed an annual report with the Tennessee Regulatory Authority (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, 2012 under the Tennessee Incentive Plan (TIP). On February 27, 2013, the TRA Utilities Division Audit Staff (Staff) submitted their Audit Report with which we concurred. On March 13, 2013, the TRA approved and adopted the Staff’s Audit Report and issued its written order on March 26, 2013.

In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. On February 26, 2013, the Staff submitted their ACA Compliance Audit Report with which we concurred. On March 13, 2013, the TRA approved and adopted the Staff’s ACA Compliance Audit Report and issued its written order on March 26, 2013.

3. Earnings per Share

We compute basic earnings per share (EPS) using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are included in our calculation of fully diluted EPS.

A reconciliation of basic and diluted EPS for the three months and six months ended April 30, 2013 and 2012 is presented below.

	Three Months				Six Months
In thousands except per share amounts	2013		2012		2013		2012
Net Income	$	55,790	$	50,192	$	141,713	$	126,419
Average shares of common stock outstanding for basic earnings per share		75,463		71,731		73,884		71,931
Contingently issuable shares under incentive compensation plans		314		295		333		295
Contingently issuable shares under forward sale agreements		127		-		84		-
Average shares of dilutive stock		75,904		72,026		74,301		72,226
Earnings Per Share of Common Stock:
Basic	$	0.74	$	0.70	$	1.92	$	1.76
Diluted	$	0.74	$	0.70	$	1.91	$	1.75

10

4. Long-Term Debt Instruments

We have an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that is available for future use until its expiration date of July 6, 2014. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for or investments in our subsidiaries, and for repurchases of shares of our common stock. On January 29, 2013, we entered into an underwriting agreement to sell shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements in this Form 10-Q.

5. Short-Term Debt Instruments

We have a $650 million five-year revolving syndicated credit facility that expires on October 1, 2017. The credit facility has an option to request an expansion up to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $650 million. The facility provides a line of credit for letters of credit of $10 million, of which $2.1 million and $3.6 million were issued and outstanding as of April 30, 2013 and October 31, 2012, respectively. 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 London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the period.

We have a $650 million unsecured commercial paper (CP) program that is backstopped by the revolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million unless the option to expand the credit facility is exercised as discussed above. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt. The notes under the CP program are not registered and are being offered and issued pursuant to an exemption from registration.

As of April 30, 2013, we have $345 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets with original maturities ranging from 8 to 14 days from their dates of issuance at a weighted average interest rate of .30%. As of October 31, 2012, our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were $365 million.

A summary of the short-term debt activity for the three months and six months ended April 30, 2013 is as follows.

11

	Credit Facility						Commercial Paper						Total Borrowings  (3)
In millions	Three Months			Six Months			Three Months			Six Months			Three Months			Six Months
Minimum amount outstanding during period (1)	$	-		$	-		$	315		$	315		$	315		$	315
Maximum amount outstanding during period (1)		-			10			525			555			525			555
Minimum interest rate during period (2)		-	%		1.12	%		.28	%		.28	%		.28	%		.28	%
Maximum interest rate during period		-	%		1.12	%		.37	%		.45	%		.37	%		1.12	%
Weighted average interest rate during period		-	%		1.12	%		.33	%		.36	%		.33	%		.36	%

⁽¹⁾ During December 2012, we were borrowing under both the credit facility and CP program for a portion of the month.

⁽²⁾ This is the minimum rate when we were borrowing under the credit facility and/or CP program.

⁽³⁾ The minimum and maximum balances outstanding for each short-term debt instrument occurred at different times during the period; therefore, the total balances may not be indicative of actual borrowings on any one day during the period.

Our five-year revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 52% at April 30, 2013.

6. Stockholders’ Equity

Capital Stock

Changes in common stock for the six months ended April 30, 2013 are as follows.

In thousands	Shares		Amount
Balance, October 31, 2012		72,250	$	442,461
Issued to participants in the Employee Stock Purchase Plan (ESPP)		16		505
Issued to the Dividend Reinvestment and Stock Purchase Plan		360		11,136
Issued to participants in the Incentive Compensation Plan (ICP)		94		2,999
Issuance of common stock through public share offering, net of underwriting fees		3,000		92,640
Costs from issuance of common stock		-		(358	)
Balance, April 30, 2013		75,720	$	549,383

On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stock as follows.

• Direct shares – 3 million shares were issued by us and delivered directly to the underwriters with settlement on February 4, 2013. We received $92.6 million from the underwriters and recorded this amount in “Stockholders’ equity” as an addition to “Common Stock” in the Consolidated Balance Sheets. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share. The net proceeds from this sale of our common stock were used to repay outstanding short-term, unsecured notes under our CP program.

• Forward shares – 1 million shares were borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013. Under this initial forward sale agreement (FSA) that we executed with the forward counterparty on January 29, 2013, we agreed to sell 1 million shares to the forward counterparty at the same price as the direct shares to be settled no later than December 15, 2013. Under the terms of this FSA, at our election, we may physically settle in shares, cash or net share settle

12

for all or a portion of our obligation under the agreement. We expect to settle by delivering shares. If we physically settle by issuing 1 million shares of our common stock to the forward counterparty, the forward counterparty will, at settlement, pay us the proceeds of $30.88 per share less certain adjustments from its sale of the borrowed shares to the underwriters.

• Additional shares – Up to .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock at the net price described above of $30.88 per share with settlement on February 22, 2013. We elected to place the .6 million shares under an additional FSA having substantially similar terms as the original FSA, including settlement options at our election as described above. In connection with the additional FSA, the .6 million shares were borrowed from third parties and sold to the underwriters by the forward counterparty. We expect to settle by delivering shares. Under the terms of the additional FSA, to the extent that the transaction is physically settled, we will be required to issue and deliver an equivalent number of shares of our common stock to the forward counterparty at the then applicable forward sale price, which will be the net price described above of $30.88 per share less certain adjustments.

In accordance with ASC 815-40, Derivatives and Hedging- Contracts in Entity’s Own Equity, we have classified the FSAs as equity transactions because the forward sale transactions are indexed to our own stock and physical settlement is within our control. As a result of this classification, no amounts will be recorded in the consolidated financial statements until settlement of each FSA.

Upon physical settlement of the FSAs, delivery of our shares will result in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS could occur during periods when the average market price per share of our common stock is above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements in this Form 10-Q for the dilutive effect of the FSAs on our EPS at April 30, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

If we had settled the FSAs by delivery of 1.6 million shares of our common stock to the forward counterparty at April 30, 2013, we would have received net proceeds of approximately $48.8 million based on the net settlement price of $30.88 per share described above less certain adjustments. Upon settlement, the net proceeds from these FSA transactions will be used to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

Other Comprehensive Income (Loss)

Our other comprehensive income (loss) (OCIL) is a part of our accumulated OCIL and is comprised of hedging activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 12 to the consolidated financial statements in this Form 10-Q. Changes of each component of accumulated OCIL are presented below for the three months and six months ended April 30, 2013.

13

	Changes in Accumulated  OCIL (1)
In thousands	Three Months			Six Months
Accumulated OCIL beginning balance, net of tax	$	(463	)	$	(305	)
OCIL before reclassifications, net of tax		238			59
Amounts reclassified from accumulated OCIL, net of tax		76			97
Total current period activity, net of tax		314			156
Accumulated OCIL ending balance, net of tax	$	(149	)	$	(149	)

⁽¹⁾ Amounts in parentheses indicate debits to accumulated OCIL.

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the three months and six months ended April 30, 2013.

	Reclassifications Out of Accumulated OCIL (1)						Affected Line Items on Statement of Comprehensive Income
In thousands	Three Months			Six Months
Hedging activities of equity method investments	$	(125	)	$	(160	)	Income from equity method investments
Income tax expense		49			63		Income taxes
Total reclassification for the period, net of tax	$	(76	)	$	(97	)

⁽¹⁾ Amounts in parentheses indicate credits to accumulated OCIL.

7. 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 rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 10 to the consolidated financial statements in this Form 10-Q.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value in the Consolidated Balance Sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their investments at any time. 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 is included in “Other current assets” in “Current Assets” in the Consolidated Balance Sheets.

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. The composition of these securities as of April 30, 2013 and October 31, 2012 is as follows.

14

	April 30, 2013				October 31, 2012
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	-	$	-	$	-	$	-
Mutual funds		134		180		134		157
Total current trading securities		134		180		134		157
Noncurrent trading securities:
Money markets		335		335		243		243
Mutual funds		2,045		2,471		1,668		1,888
Total noncurrent trading securities		2,380		2,806		1,911		2,131
Total trading securities	$	2,514	$	2,986	$	2,045	$	2,288

8. 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 of 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, 2013 and October 31, 2012, we had long gas purchase options providing total coverage of 14.9 million dekatherms and 35.8 million dekatherms, respectively. The long gas purchase options held at April 30, 2013 are for the period from June 2013 through January 2014.

Fair Value Measurements

We use financial instruments that are not designated as hedges to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain of our deferred compensation plans. In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2012.

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, 2013 and October 31, 2012. 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, 2013 and 2012.

15

Recurring Fair Value Measurements as of April 30, 2013

In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	4,091	$	-	$	-	$	4,091
Debt and equity securities held as trading securities:
Money markets		335		-		-		335
Mutual funds		2,651		-		-		2,651
Total recurring fair value assets	$	7,077	$	-	$	-	$	7,077

Recurring Fair Value Measurements as of October 31, 2012

In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	3,153	$	-	$	-	$	3,153
Debt and equity securities held as trading securities:
Money markets		243		-		-		243
Mutual funds		2,045		-		-		2,045
Total recurring fair value assets	$	5,441	$	-	$	-	$	5,441

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 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 to customers” in “Current Liabilities” or “Amounts due from customers” in “Current Assets” in the Consolidated Balance Sheets. These derivative instruments are 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 rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” 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 benchmark 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, which is classified within Level 2, are shown below.

16

In thousands	Carrying Amount		Fair Value
As of April 30, 2013	$	975,000	$	1,165,585
As of October 31, 2012		975,000		1,163,227

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 designated 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, 2013 and October 31, 2012.

Fair Value of Derivative Instruments

In thousands	Fair Value April 30, 2013		Fair Value October 31, 2012
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets – Gas purchase derivative assets (June 2013-January 2014)	$	4,091
Current Assets – Gas purchase derivative assets (December 2012-October 2013)			$	3,153

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide some level of protection against significant price increases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due to/from customers in the Consolidated Balance Sheets and recognized in the Consolidated Statements of Comprehensive Income as a component of cost of gas when the related costs are recovered through our rates.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Consolidated Statements of Comprehensive Income for the three months and six months ended April 30, 2013 and 2012, absent the regulatory treatment under our approved PGA procedures.

17

In thousands	Amount of Loss Recognized on Derivatives and Deferred Under  PGA Procedures								Location of Loss Recognized through PGA Procedures
	Three Months Ended April 30				Six Months Ended April 30
	2013		2012		2013		2012
Gas purchase options	$	1,816	$	2,365	$	4,291	$	5,288		Cost of Gas

In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Credit and Counterparty Risk

We are exposed to credit risk as a result of transactions for the purchase and sale of products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.

We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with (or are associated with) energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $11.3 million, or approximately 8% of our gross trade accounts receivable at April 30, 2013. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of April 30, 2013, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas

18

costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.

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 that monitors compliance with our hedging programs, policies and procedures.

9. 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. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for pipeline and storage capacity contracts are up to twenty-two years. The time periods for gas supply contracts are up to eleven months. 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 are up to four years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (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 Comprehensive 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. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

Legal

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

19

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $2.1 million in letters of credit that were issued and outstanding as of April 30, 2013. Additional information concerning letters of credit is included in Note 5 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.

We are responsible for any third-party claims for personal injury, death, property damage and diminution of property value or natural resources regarding nine manufactured gas plant (MGP) sites that were a part of a 1997 settlement with a third party and several MGP sites retained by Progress Energy, Inc., now a subsidiary of Duke Energy Corporation, in connection with our 2003 acquisition of North Carolina Natural Gas Corporation. We know of no such pending or threatened claims.

There are four other MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated and for which we have an investigation and remediation liability. In fiscal year 2012, we performed soil remediation work at our Reidsville site. In July 2012, the North Carolina Department of Environment and Natural Resources (NCDENR) approved our proposed groundwater investigation work plan, which included installing five monitoring wells in September 2012. Although the water samples from these wells yielded uncontaminated groundwater, NCDENR is requesting a groundwater remedial action plan requiring additional sampling activities to be conducted for one year. We have incurred $.6 million of remediation costs at the Reidsville site through April 30, 2013.

As part of a voluntary agreement with the NCDENR, we conducted and completed soil remediation for the Hickory, North Carolina MGP site in 2010. A Phase II groundwater investigation was conducted in 2011. A groundwater remedial action plan was submitted and approved by the NCDENR in 2012. We continue to conduct quarterly groundwater monitoring at this site in accordance with our site remediation plan. We have incurred $1.5 million of remediation costs at this site through April 30, 2013.

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 final consent order imposing land usage restrictions on the property was approved and signed by the TDEC in June 2010. The final consent order required two years of semi-annual groundwater monitoring, which has been completed. In February 2013, we received a letter from the TDEC certifying completion of the actions agreed to be taken in the consent order. We have incurred $1.5 million of remediation costs at this site through April 30, 2013.

During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville LNG facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required at the site for this issue. In September 2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site. In April 2012, we entered into a no admit/no deny ACO that imposed a fine of $40,000, unpaid annual fees totaling $18,000 and $1,860 for investigative and administrative costs. As part of the ACO, we were required to develop a site assessment plan to determine the extent of the groundwater contamination related to the sieve burial, a groundwater remediation strategy and a groundwater and surface

20

water site-wide monitoring program. A site assessment plan was accepted by the NCDENR, and we began groundwater sampling in July 2012. We performed an initial round of sampling in our first quarter, and additional groundwater monitoring wells were installed during our second quarter to aid in determining the extent of the groundwater contamination. The groundwater sampling results will be submitted to the NCDENR, and based on their response, we may be required to submit additional plan(s) to remediate and/or monitor the groundwater. These plan(s) are due within thirty days of the completion of the site assessment.

The Huntersville LNG facility was originally coated with lead-based paint. To avoid lead-based paint exposure, removal of lead-based paint from the site was initiated in spring 2010. The last phase of the lead-based paint removal began in July 2012 on the LNG tank, and the remediation of rafters in a nearby building will begin in mid-2013 with completion anticipated for both projects by the end of fiscal 2014. We have incurred $4.3 million of remediation costs through April 30, 2013 for all issues at the Huntersville LNG plant site. Once the lead-based paint is removed at our Huntersville LNG facility, we expect there will be no potential environmental or employee exposures.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina resource center is the only location that continues to operate USTs.

For all matters discussed above, as of April 30, 2013, our estimated undiscounted environmental liability totaled $1.8 million and consisted of $1.1 million for the MGP sites for which we retain remediation responsibility, $.2 million for the LNG facilities, $.2 million for the groundwater remediation at the Huntersville LNG site and $.3 million for the USTs not yet remediated. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others.

As of April 30, 2013, our regulatory assets for unamortized environmental costs in our three-state territory totaled $10.2 million. We received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the recent general rate case proceeding in Tennessee. We will seek recovery of the remaining balance in future rate proceedings. For further information on regulatory matters, see Note 2 to the consolidated financial statements in this Form 10-Q.

Further evaluation of the MGP, LNG and UST sites and removal of lead-based paint at our LNG site could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.

Additional information concerning commitments and contingencies is set forth in Note 8 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2012.

10. 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, 2013 and 2012 are presented below.

21

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2013			2012			2013		2012		2013			2012
Service cost	$	3,150		$	2,475		$	-	$	10	$	332		$	347
Interest cost		2,475			2,650			40		51		282			337
Expected return on plan assets		(5,300	)		(5,125	)		-		-		(416	)		(388	)
Amortization of transition obligation		-			-			-		-		167			167
Amortization of prior service (credit) cost		(550	)		(550	)		20		20		-			-
Amortization of actuarial loss		2,750			1,375			40		12		-			-
Total	$	2,525		$	825		$	100	$	93	$	365		$	463

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the six months ended April 30, 2013 and 2012 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2013			2012			2013		2012		2013			2012
Service cost	$	6,300		$	4,950		$	-	$	20	$	663		$	693
Interest cost		4,950			5,300			79		102		565			674
Expected return on plan assets		(10,600	)		(10,250	)		-		-		(832	)		(776	)
Amortization of transition obligation		-			-			-		-		334			334
Amortization of prior service (credit) cost		(1,100	)		(1,100	)		40		40		-			-
Amortization of actuarial loss		5,500			2,750			80		24		-			-
Total	$	5,050		$	1,650		$	199	$	186	$	730		$	925

In November 2012, we contributed $20 million to the qualified pension plan, and in January 2013, we contributed $.7 million to the money purchase pension plan. We anticipate that we will contribute the following amounts to our other plans in 2013.

In thousands
Nonqualified pension plans	$	502
OPEB plan		1,500

We have a non-qualified 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, 2013, 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, where we make no contributions to this plan. Both deferred compensation plans are funded through rabbi trusts with a bank as the trustee. As of April 30, 2013, we have a liability of $3.1 million for these plans.

See Note 7 and Note 8 to the consolidated financial statements in this Form 10-Q for information on the investments in marketable securities that are held in the trusts.

22

11. Employee Share-Based Plans

Under our shareholder approved ICP, 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, 2013 and 2012, we recorded compensation expense, and as of April 30, 2013 and October 31, 2012, 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 stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award will vest for 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. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of all or a portion of a participant’s units. For the three months and six months ended April 30, 2013 and 2012, we recorded compensation expense, and as of April 30, 2013 and October 31, 2012, we have accrued a liability for this award 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 ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vest on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the three months and six months ended April 30, 2013, we recorded compensation expense, and as of April 30, 2013, we have accrued a liability for this award 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.

At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issued in the Consolidated Statements of Stockholders’ Equity.

The compensation expense related to the incentive compensation plans for the three months and six months ended April 30, 2013 and 2012, and the amounts recorded as liabilities as of April 30, 2013 and October 31, 2012 are presented below.

23

	Three Months				Six Months
In thousands	2013		2012		2013		2012
Compensation expense	$	1,801	$	501	$	3,657	$	2,075
	April 30, 2013		October 31, 2012
Liability	$	10,228	$	10,631

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

12. 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 “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Consolidated Statements of Comprehensive Income.

Cardinal Pipeline Company, L.L.C.

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC.

Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of April 30, 2013 and October 31, 2012 are as follows.

24

	Three Months				Six Months
In thousands	2013		2012		2013		2012
Transportation costs	$	2,155	$	1,012	$	4,294	$	2,047

	April 30, 2013		October 31, 2012
Trade accounts payable	$	730	$	855

Pine Needle LNG Company, L.L.C.

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 LNG storage facility in North Carolina and is regulated by the FERC.

Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the members.

We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of April 30, 2013 and October 31, 2012 are as follows.

	Three Months				Six Months
In thousands	2013		2012		2013		2012
Gas storage costs	$	2,730	$	2,464	$	5,516	$	4,983

	April 30, 2013		October 31, 2012
Trade accounts payable	$	919	$	914

SouthStar Energy Services LLC

We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States, as well as Ohio, New York and Maryland, with most of its business being conducted in the unregulated retail gas market in Georgia. We account for our investment in SouthStar using the equity method, as we have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings. These financial contracts, in the form of futures, options and swaps, are considered to be derivatives

25

and fair value is based on selected market indices. Our share of movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of April 30, 2013 and October 31, 2012 are as follows.

	Three Months					Six Months
In thousands	2013		2012			2013		2012
Operating revenues	$	592	$	(26	)	$	583	$	(139	)

	April 30, 2013		October 31, 2012
Trade accounts receivable	$	579	$	473

Hardy Storage Company, LLC

We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC.

We have related party transactions as a customer of Hardy Storage and record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of April 30, 2013 and October 31, 2012 are as follows.

	Three Months				Six Months
In thousands	2013		2012		2013		2012
Gas storage costs	$	2,425	$	2,425	$	4,851	$	4,851

	April 30, 2013		October 31, 2012
Trade accounts payable	$	808	$	808

Constitution Pipeline Company, LLC

We own 24% of the membership interests in Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The purpose of the joint venture is to construct and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting natural gas gathering systems in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction

26

of the new pipeline, which is expected to cost approximately $680 million. As of April 30, 2013, our current quarter and fiscal year contributions were $1.2 million and $8.7 million, respectively, and we expect our total contributions will be an estimated $163 million through 2015 with approximately 90% of that funding to occur during our fiscal 2014 and 2015 years. The target in-service date of the project is March 2015. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

13. Variable Interest Entities

Under accounting guidance, a variable interest entity (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, 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, 2013, 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, as discussed in Note 12 to the consolidated financial statements in this Form 10-Q. 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. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements in this Form 10-Q. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of April 30, 2013 and October 31, 2012, our investment balances are as follows.

In thousands	April 30, 2013		October 31, 2012
Cardinal	$	18,270	$	17,969
Pine Needle		18,585		19,239
SouthStar		15,467		18,118
Hardy Storage		33,465		32,541
Constitution		8,979		-
Total equity method investments in non-utility activities	$	94,766	$	87,867

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

14. Business Segments

We have two reportable business segments, regulated utility and non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we

27

include the operations of merchandising and its related service work and home warranty programs, with activities 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 Comprehensive Income. Operations of the non-utility activities segment are included in the Consolidated Statements of Comprehensive 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, 2012.

Operations by segment for the three months and six months ended April 30, 2013 and 2012 are presented below.

In thousands	Regulated Utility				Non-utility Activities						Total
	2013		2012		2013			2012			2013		2012
Three Months
Revenues from external customers	$	399,411	$	308,432	$	-		$	-		$	399,411	$	308,432
Margin		183,856		171,951		-			-			183,856		171,951
Operations and maintenance expenses		65,037		60,511		66			21			65,103		60,532
Income from equity method investments		-		-		12,437			11,652			12,437		11,652
Operating income (loss) before income taxes		82,884		76,872		(70	)		(26	)		82,814		76,846
Income before income taxes		79,678		71,189		12,367			11,627			92,045		82,816
Six Months
Revenues from external customers	$	915,286	$	780,272	$	-		$	-		$	915,286	$	780,272
Margin		415,480		392,187		-			-			415,480		392,187
Operations and maintenance expenses		120,919		118,908		120			44			121,039		118,952
Income from equity method investments		-		-		19,592			17,944			19,592		17,944
Operating income (loss) before income taxes		222,396		203,912		(205	)		(132	)		222,191		203,780
Income before income taxes		214,555		190,770		19,386			17,812			233,941		208,582

Reconciliations to the Consolidated Statements of Comprehensive Income for the three months and six months ended April 30, 2013 and 2012 are presented below.

28

In thousands	Three Months						Six Months
	2013			2012			2013			2012
Operating Income:
Segment operating income before income taxes	$	82,814		$	76,846		$	222,191		$	203,780
Utility income taxes		(31,380	)		(28,090	)		(84,679	)		(75,311	)
Non-utility activities before income taxes		70			26			205			132
Operating income	$	51,504		$	48,782		$	137,717		$	128,601
Net Income:
Income before income taxes for reportable segments	$	92,045		$	82,816		$	233,941		$	208,582
Income taxes		(36,255	)		(32,624	)		(92,228	)		(82,163	)
Net income	$	55,790		$	50,192		$	141,713		$	126,419

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 were evaluated. For information on subsequent event disclosures related to regulatory matters, see Note 2 to the consolidated financial statements in this Form 10-Q.

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

Forward-Looking Statements

This report, as well as other documents we file with the Securities and Exchange Commission (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 from 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 the following, as well as those discussed in Item 1A. Risk Factors:

• Economic conditions in our markets

• Wholesale price of natural gas

• Availability of adequate interstate pipeline transportation capacity and natural gas supply

• Regulatory actions at the state level that impact our ability to earn a reasonable rate of return and fully recover our operating costs on a timely basis

• Competition from other companies that supply energy

• Changes in the regional economies, politics, regulations and weather patterns of the three states in which our operations are concentrated

• Costs of complying or effect of noncompliance with state and federal laws and regulations that are applicable to us

• Effect of climate change, carbon neutral or energy efficiency legislation or regulations on costs and market opportunities

• Weather conditions

• Operational interruptions to our gas distribution and transmission activities

• Ability to complete necessary or desirable pipeline expansion or infrastructure development projects

• Our credit ratings

29

• Availability and cost of capital

• Federal and state fiscal, tax and monetary policy

• Ability to generate sufficient cash flows to meet all our cash needs

• Ability to satisfy all of our outstanding debt obligations

• Ability of counterparties to meet their obligations to us

• Costs of providing pension benefits

• Earnings from the joint venture businesses in which we invest

• Ability to attract and retain professional and technical employees

• Changes in accounting standards

• Risk of cyber-attack, acts of cyber-terrorism, or failure of technology systems

• Ability to obtain and maintain sufficient insurance

• Change in number of outstanding shares

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 place undue reliance 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,” “assume,” “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 based on information available to us as of the date they are made, and we do not undertake any obligation to update publicly any forward-looking statement either as a result of new information, future events or otherwise except as required by applicable laws and regulations. Our reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are available at no cost on our website at www.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.

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. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas transportation and storage and intrastate natural gas transportation businesses. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Piedmont” means consolidated Piedmont Natural Gas Company, Inc. and its subsidiaries.

We have two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility 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. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses. The percentages of the assets as of April 30, 2013 and earnings before taxes by segments for the six months ended April 30, 2013 are presented below.

30

	Assets			Earnings Before Taxes
Regulated Utility		98	%		92	%
Non-utility Activities:
Regulated non-utility activities		2	%		2	%
Unregulated non-utility activities		-	%		6	%
Total non-utility activities		2	%		8	%

For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the consolidated financial statements in this Form 10-Q.

Regulation

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority (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 long-term debt and equity securities.

We are also subject to various federal regulations that affect our utility and non-utility operations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission that affect the certification and siting of new interstate natural gas pipeline projects, the purchase and sale of, the prices paid for, and the terms and condition of service for the interstate transportation and storage of natural gas, regulations of the U.S. Department of Transportation 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 other regulations, such as those relating to employment and benefit 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 recover the cost of natural gas we purchase for our customers and our operating expenses 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 in part 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.

We continually assess alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy. The traditional utility rate design provides for the collection of margin revenue based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. Alternative rate structures and cost recovery mechanisms are rate designs and mechanisms that allow utilities to recover certain costs through tracking mechanisms or riders without the need to file general base rate cases or that encourage energy efficiency and conservation by separating or decoupling the link between energy consumption and margin revenues, thereby aligning the interests of shareholders and customers.

In North Carolina, we have a margin decoupling mechanism that provides for the recovery of our approved margin from residential and commercial customers on an annual basis independent of consumption patterns. The margin decoupling mechanism provides for semi-annual rate adjustments to refund any over-collection of margin or to recover any under-collection of margin. In South Carolina, we operate under a rate stabilization adjustment tariff mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the rate stabilization adjustment tariff mechanism, we restate our rates in

31

South Carolina based on updated costs and revenues on an annual basis. We also have a weather normalization adjustment (WNA) mechanism for residential and commercial customers in South Carolina for bills rendered during the months of November through March and in Tennessee for bills rendered during the months of October through April that partially offsets the impact of colder- or warmer-than-normal winter weather. Our WNA formulas calculate the actual weather variance from normal, using 30 years of history, and increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The WNA formulas do not ensure full recovery of approved margin during periods when customer consumption patterns vary from consumption patterns used to establish the WNA factors.

In all three states, the gas cost portion of our costs is recoverable through purchased gas adjustment (PGA) procedures and is not affected by the margin decoupling mechanism or the WNA mechanism. For the six months ended April 30, 2013, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 70% of our utility margin, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 20% of our utility margin, including the rate stabilization mechanism in South Carolina and WNA in South Carolina and Tennessee; and volumetric or periodic renegotiation of 10% of our utility margin, including our secondary market programs. For further information on state commission regulation, see Note 2 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2012.

Strategic Focus

Our strategic directives focus on our customers, our communities, our employees and our shareholders and reflect what we believe is the inherent advantages of natural gas compared to other types of energy. They are as follows:

• Promote the benefits of natural gas

• Expand our core natural gas and complementary energy-related businesses to enhance shareholder value

• Be the energy and service provider of choice

• Achieve excellence in customer service every time

• Preserve financial strength and flexibility

• Execute sustainable business practices

• Enhance our healthy, high performance culture

For further discussion of our strategic objectives, see the “Overview” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K for the year ended October 31, 2012.

Executive Summary

We monitor our progress and measure our performance related to our strategic directives and our business objectives over the course of our fiscal year. The metrics we use to measure our performance include, but are not limited to, earnings per share (EPS) and EPS growth, total shareholder return compared to our industry peer group, return on invested capital, return on equity, utility margin, investment grade credit ratings, customer growth, utility customer satisfaction and loyalty, operations and maintenance expense discipline, pipeline safety, carbon emissions and our corporate culture related to employee job satisfaction, health and safety.

Focus Areas and Achievements

Managing Gas Supplies and Prices. Our gas supply acquisition strategy is regularly reviewed and adjusted to ensure that we have sufficient and reliable supplies of competitively-priced natural gas to meet the needs of our

32

utility customers. Natural gas development and production in North America continues to provide supply stability and price moderation for natural gas as an energy commodity. Over the past five years, the lower price of natural gas has allowed us to significantly lower the cost of gas to our customers with multiple filings for reductions in the wholesale natural gas cost component of customer rates in the three jurisdictions that we serve. In April 2013, we filed for an increase in the natural gas cost component of our rates in North Carolina and South Carolina that became effective May 1, 2013. Our residential billing rates still range between 28% and 38% less than those in effect in 2008. Currently, natural gas has a price advantage over many other fuels, and it is anticipated that the cost of natural gas will remain competitive due to abundant domestic sources of shale gas reserves.

In November 2012, in order to provide diversification, reliability and gas cost benefits to our customers, we signed long-term contracts to source more of our gas supplies from the Marcellus shale basin in Pennsylvania for our markets in the Carolinas. These new supply arrangements are scheduled to begin in September 2015 and December 2015.

Customer Growth. With some improvement in economic conditions and target marketing on the benefits of natural gas, customer gains improved 12% in the six months ended April 30, 2013 compared to the same period in 2012. Lower wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. Customer gains in our residential new construction and conversion markets increased 15% for the six months ended April 30, 2013 compared to the same period in 2012. Commercial customer additions decreased 6% for the six months ended April 30, 2013 compared to 2012, reflecting a reduction in new construction activity coupled with a longer sales cycle for conversions. We forecast gross customer growth for fiscal 2013 of slightly better than 1%. Overall, total customers billed increased 2% for the six months ended April 30, 2013 compared to the same period in 2012.

We continue to execute our plan to build compressed natural gas (CNG) fueling stations in our service area for use by our own vehicle fleet as well as by third party customers. We currently own and operate nine company CNG fueling stations at Company resource centers with 20% of our vehicle fleet capable of using CNG. We are marketing our CNG fueling stations to commercial fleets to utilize these CNG stations and will serve commercial customers with fueling stations at their sites where there is sufficient demand. We sold 33,000 dekatherms of CNG to commercial customers for the six months ended April 30, 2013, which is equivalent to approximately 485 homes, and our fleet used 3,400 dekatherms of CNG. Through sales of CNG to our commercial customers and use by our own fleet, this CNG usage displaced approximately 289,000 gallons of gasoline and diesel fuel.

Capital Expenditures. We continue to make progress with capital projects that we expect will provide benefits to our customers through safe and reliable natural gas service, while providing our shareholders a reasonable return on invested capital. On June 1, 2013, we placed into service one pipeline expansion project that will provide natural gas delivery service to a power generation facility in North Carolina. See the discussion of our forecasted capital investments in “Cash Flows from Investing Activities” in Item 2 of this Form 10-Q in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We are increasing our utility capital expenditures for pipeline integrity, safety and compliance programs as well as system and technology infrastructure. To ensure safe and efficient pipeline operations, we are developing a new work and asset management system. These capital expenditures will require rate cases or other regulatory mechanisms to obtain a return of and on those capital costs. See further discussion in the section below on “Business Process and Technology Improvements.”

Regulatory Activity. Even though we have WNA mechanisms in South Carolina and Tennessee, we are not fully insulated from the effects of weather that are significantly warmer than normal or colder than normal. Weather across our system for the six months ended April 30, 2013 was 3% colder than normal and 28% colder than the same prior year period.

33

For the six months ended April 30, 2013, the margin decoupling mechanism in North Carolina decreased margin by $3.7 million, and the WNA mechanisms in South Carolina and Tennessee increased margin by $2.4 million.

In April 2013, legislation was passed into law that gives the TRA the ability to approve alternative regulatory mechanisms. The law allows the TRA to implement: (1) separate rate adjustment mechanisms that track specific costs; (2) annual rate reviews in lieu of traditional rate cases and (3) adoption of other policies or procedures that permit a more timely review and revision of rates, streamline the regulatory process, and reduce the cost and time associated with the traditional ratemaking processes.

In May 2013, legislation was passed into law that gives the NCUC the ability to approve a rate adjustment mechanism in a general rate case proceeding to enable a natural gas local distribution company (LDC) to recover its prudently incurred capital investment and associated costs of complying with federal pipeline safety and integrity requirements, including a return based on the LDC’s then authorized return.

In May 2013, we filed a general rate application with the NCUC. For further information on this rate proceeding, see Note 2 to the consolidated financial statements in this Form 10-Q.

Business Process and Technology Improvements. To support our strategic objective of excellence in customer service and sustainable business practices through safe and efficient pipeline operations, we are in the process of a multi-year program designed to bring additional technology and automation to our field operations by providing systems and information to enable operations employees to more effectively and efficiently manage our pipeline assets, ensure operating efficiencies and facilitate compliance with pipeline safety and integrity regulations. These enhanced new systems and process programs, which include multiple projects, will be integrated with our current and future financial and other business systems.

Cost Containment Measures. We continue to focus on improving operating efficiency and productivity and cost containment discipline where possible in payroll, corporate overhead charges and various discretionary spending categories. We will manage our business as efficiently as possible consistent with providing safe, reliable and cost effective services to our customers.

Financial Strength and Flexibility. In order to profitably fund our Company’s investment in growth and our ongoing capital needs, we have executed our financing programs to optimize and reduce our cost of capital, preserve our liquidity and strong balance sheet and protect our high quality credit ratings. We have an open shelf registration filed with the SEC in June 2011 that is available for future issuances of debt or equity. On January 29, 2013, we entered into an underwriting agreement to sell up to 4.6 million shares of our common stock, priced to the public at $32 per share. Of the 4.6 million shares, 3 million shares were issued on February 4, 2013 providing net proceeds of $92.6 million, and we intend to issue the remaining shares in 2013 under the forward sale agreements (FSAs). For further information on this offering, see Note 6 to the consolidated financial statements in this Form 10-Q and the following discussion of “Cash Flows from Financing Activities.”

The following discussion on operating results is provided for the three-month and six-month periods.

Results of Operations

We reported net income of $55.8 million for the three months ended April 30, 2013 as compared to $50.2 million for the same period in 2012. The following table provides a comparison of the components of the Consolidated Statements of Comprehensive Income for the three months ended April 30, 2013 as compared with the three months ended April 30, 2012.

34

Comprehensive Income Statement Components

	Three Months Ended April 30				Variance			Percent Change
In thousands, except per share amounts	2013		2012
Operating Revenues	$	399,411	$	308,432	$	90,979			29.5	%
Cost of Gas		215,555		136,481		79,074			57.9	%
Margin		183,856		171,951		11,905			6.9	%
Operations and Maintenance		65,037		60,511		4,526			7.5	%
Depreciation		26,867		25,269		1,598			6.3	%
General Taxes		9,068		9,299		(231	)		(2.5	)%
Utility Income Taxes		31,380		28,090		3,290			11.7	%
Total Operating Expenses		132,352		123,169		9,183			7.5	%
Operating Income		51,504		48,782		2,722			5.6	%
Other Income (Expense), net of tax		7,608		7,073		535			7.6	%
Utility Interest Charges		3,322		5,663		(2,341	)		(41.3	)%
Net Income	$	55,790	$	50,192	$	5,598			11.2	%
Average Shares of Common Stock:
Basic		75,463		71,731		3,732			5.2	%
Diluted		75,904		72,026		3,878			5.4	%
Earnings Per Share of Common Stock:
Basic	$	0.74	$	0.70	$	0.04			5.7	%
Diluted	$	0.74	$	0.70	$	0.04			5.7	%

We reported net income of $141.7 million for the six months ended April 30, 2013 as compared to $126.4 million for the same period in 2012. The following table provides a comparison of the components of the Consolidated Statements of Comprehensive Income for the six months ended April 30, 2013 as compared with the six months ended April 30, 2012.

35

Comprehensive Income Statement Components

	Six Months Ended April 30				Variance			Percent Change
In thousands, except per share amounts	2013		2012
Operating Revenues	$	915,286	$	780,272	$	135,014			17.3	%
Cost of Gas		499,806		388,085		111,721			28.8	%
Margin		415,480		392,187		23,293			5.9	%
Operations and Maintenance		120,919		118,908		2,011			1.7	%
Depreciation		53,569		51,447		2,122			4.1	%
General Taxes		18,596		17,920		676			3.8	%
Utility Income Taxes		84,679		75,311		9,368			12.4	%
Total Operating Expenses		277,763		263,586		14,177			5.4	%
Operating Income		137,717		128,601		9,116			7.1	%
Other Income (Expense), net of tax		11,775		10,686		1,089			10.2	%
Utility Interest Charges		7,779		12,868		(5,089	)		(39.5	)%
Net Income	$	141,713	$	126,419	$	15,294			12.1	%
Average Shares of Common Stock:
Basic		73,884		71,931		1,953			2.7	%
Diluted		74,301		72,226		2,075			2.9	%
Earnings Per Share of Common Stock:
Basic	$	1.92	$	1.76	$	0.16			9.1	%
Diluted	$	1.91	$	1.75	$	0.16			9.1	%

The following table provides the components of our margin by customer class for the three months ended April 30, 2013 and 2012.

Margin by Customer Class

	Three Months Ended April 30
In thousands	2013				2012
Sales and Transportation:
Residential	$	104,206	57	%	$	99,509	58	%
Commercial		46,513	25	%		45,184	26	%
Industrial		15,075	8	%		13,487	8	%
Power Generation		10,184	6	%		6,006	4	%
For Resale		2,037	1	%		1,990	1	%
Total		178,015	97	%		166,176	97	%
Secondary Market Sales		1,975	1	%		2,300	1	%
Miscellaneous		3,866	2	%		3,475	2	%
Total	$	183,856	100	%	$	171,951	100	%

The following table provides the components of our margin by customer class for the six months ended April 30, 2013 and 2012.

36

Margin by Customer Class

	Six Months Ended April 30
In thousands	2013				2012
Sales and Transportation:
Residential	$	242,120	58	%	$	233,728	60	%
Commercial		106,367	26	%		103,267	26	%
Industrial		31,406	8	%		28,426	7	%
Power Generation		20,300	5	%		11,809	3	%
For Resale		4,144	1	%		4,120	1	%
Total		404,337	98	%		381,350	97	%
Secondary Market Sales		5,288	1	%		4,841	1	%
Miscellaneous		5,855	1	%		5,996	2	%
Total	$	415,480	100	%	$	392,187	100	%

Key statistics are shown in the table below for the three months ended April 30, 2013 and 2012.

Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Three Months Ended April 30
	2013			2012			Variance			Percent Change
Deliveries in Dekatherms (in thousands):
Sales Volumes		37,406			24,024			13,382			55.7	%
Transportation Volumes		71,478			57,922			13,556			23.4	%
Throughput		108,884			81,946			26,938			32.9	%
Secondary Market Volumes		14,319			13,038			1,281			9.8	%
Customers Billed (at period end)		1,000,133			984,125			16,008			1.6	%
Gross Customer Additions		3,046			2,620			426			16.3	%
Degree Days
Actual		1,418			865			553			63.9	%
Normal		1,180			1,194			(14	)		(1.2	)%
Percent colder (warmer) than normal		20.2	%		(27.5	)%		n/a			n/a
Number of Employees (at period end)		1,765			1,775			(10	)		(0.6	)%

37

Key statistics are shown in the table below for the six months ended April 30, 2013 and 2012.

Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Six Months Ended April 30
	2013			2012			Variance			Percent Change
Deliveries in Dekatherms (in thousands):
Sales Volumes		79,874			62,620			17,254			27.6	%
Transportation Volumes		136,958			110,291			26,667			24.2	%
Throughput		216,832			172,911			43,921			25.4	%
Secondary Market Volumes		30,666			24,485			6,181			25.2	%
Customers Billed (at period end)		1,000,133			984,125			16,008			1.6	%
Gross Customer Additions		6,792			6,058			734			12.1	%
Degree Days
Actual		3,109			2,433			676			27.8	%
Normal		3,029			3,063			(34	)		(1.1	)%
Percent colder (warmer) than normal		2.6	%		(20.6	)%		n/a			n/a
Number of Employees (at period end)		1,765			1,775			(10	)		(0.6	)%

Operating Revenues

Changes in operating revenues for the three months and six months ended April 30, 2013 compared with the same periods in 2012 are presented below.

Changes in Operating Revenues - Increase (Decrease)

In millions	Three Months			Six Months
Residential and commercial customers	$	98.2		$	114.3
Industrial customers		5.9			9.5
Power generation customers		6.1			12.1
Secondary market		22.8			52.6
Margin decoupling mechanism		(32.9	)		(42.4	)
WNA mechanisms		(9.2	)		(11.3	)
Other		.1			.2
Total	$	91.0		$	135.0

• Residential and commercial customers – the increases for the three months and six months are primarily due to higher consumption from colder weather, slightly higher gas costs passed through to customers and customer growth.

• Industrial customers – the increases for the three months and six months are primarily due to colder weather and customer growth.

• Power generation customers – the increases for the three months and six months are primarily due to increased transportation services due to a new contract that began in June 2012.

38

• Secondary market – the increases for the three months and six months are due to increased activity from colder weather and slightly higher commodity costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

• Margin decoupling mechanism – the decreases for the three months and six months are due to colder weather in North Carolina. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to weather and conservation.

• WNA mechanisms – the decreases for the three months and six months are due to colder weather in South Carolina and Tennessee.

Cost of Gas

Changes in cost of gas for the three months and six months ended April 30, 2013 compared with the same period in 2012 are presented below.

Changes in Cost of Gas - Increase (Decrease)

In millions	Three Months			Six Months
Commodity gas costs passed through to sales customers	$	63.1		$	79.0
Commodity gas costs in secondary market transactions		23.1			52.2
Pipeline demand charges		8.9			12.4
Regulatory approved gas cost mechanisms		(16.0	)		(31.9	)
Total	$	79.1		$	111.7

• Commodity gas costs passed through to sales customers – the increases for the three months and six months are due to higher volumes sold due to colder weather and slightly higher wholesale gas costs passed through to sales customers.

• Commodity gas costs in secondary market transactions – the increases for the three months and six months are due to increased activity from colder weather and higher average wholesale gas costs.

• Pipeline demand charges – the increases for the three months and six months are due to increased demand costs, decreased asset manager payments and decreased capacity release.

• Regulatory approved gas cost mechanisms – the decreases for the three months and six months are primarily due to commodity gas cost true-ups.

In all three states, we are authorized to recover from customers all prudently incurred gas costs. Charges to cost of gas are based on the amount recoverable under approved rate schedules. The net of any over- or under-recoveries of gas costs are reflected in a regulatory deferred account and are added to or deducted from cost of gas and are included in “Amounts due from customers” in “Current Assets” or “Amounts due to customers” in “Current Liabilities” in the Consolidated Balance Sheets.

39

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory passthrough of changes in wholesale gas costs. Our utility margin is defined as natural gas revenues less natural gas commodity costs and fixed gas costs for transportation and storage capacity. It is the component of our revenues that is established in general rate cases and is designed to cover our utility operating expenses and our return of and on our utility capital investments and related taxes. Our commodity gas costs accounted for 44% of revenues for the six months ended April 30, 2013, and our pipeline transportation and storage costs accounted for 9%.

In general rate proceedings, state regulatory commissions authorize us to recover our margin in our monthly fixed demand charges and on each unit of gas delivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansion of natural gas service to larger industrial customers under terms and conditions of service that are competitive with alternative energy sources and allow such service to be provided without general subsidies from Piedmont’s other system customers.

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These include WNA mechanisms in Tennessee and South Carolina, the Natural Gas Rate Stabilization Act in South Carolina, secondary market activity in North Carolina and South Carolina, the gas supply Incentive Plan in Tennessee, the margin decoupling mechanism in North Carolina, negotiated loss treatment in North Carolina and South Carolina and the recovery of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.

Changes in margin for the three months and six months ended April 30, 2013 compared with the same periods in 2012 are presented below.

Changes in Margin – Increase (Decrease)

In millions	Three Months			Six Months
Residential and commercial customers	$	6.0		$	11.5
Industrial customers		1.6			3.0
Power generation customers		4.2			8.5
Secondary market activity		(.3	)		.4
Net gas cost adjustments		.4			(.1	)
Total	$	11.9		$	23.3

• Residential and commercial customers – the increases for the three months and six months are primarily due to increased volumes delivered due to colder weather, the general rate increase in Tennessee effective March 1, 2012 and customer growth in all three states.

• Industrial customers – the increases for the three months and six months are primarily due to higher consumption in the industrial market from colder weather and customer growth.

40

• Power generation customers – the increases for the three months and six months are due to increased transportation services due to a new contract that began in June 2012.

• Secondary market activity – the decrease for the three months is primarily due to lower volatility, slightly offset by increased activity and the increase for the six months is primarily due to increased activity from colder weather.

Operations and Maintenance Expenses

Changes in operations and maintenance expenses for the three months and six months ended April 30, 2013 compared with the same periods in 2012 are presented below.

Changes in Operations and Maintenance Expenses – Increase (Decrease)

In millions	Three Months		Six Months
Contract labor	$	1.5	$	2.2
Employee benefits		1.2		(2.3	)
Payroll		.7		.2
Regulatory		.5		1.1
Other		.6		.8
Total	$	4.5	$	2.0

• Contract labor – the increases for the three months and six months are primarily due to process improvement projects, pipeline integrity and maintenance programs and safety efforts.

• Employee benefits – the increase for the three months is primarily due to an increase in pension expense. The decrease for the six months is primarily due to reduced group medical insurance expense from lower claims, a regulatory pension deferral in Tennessee in the current year related to the funding of the plan in November 2012 versus no plan funding in the prior year, partially offset by an increase in pension expense.

• Payroll – the increase for the three months is primarily due to increases in incentive plan accruals partially offset by vacancies and salaries capitalized to projects.

• Regulatory – the increase for the six months is primarily due to amortization of regulatory assets with amortization periods established in the Tennessee general rate proceeding, effective in March 2012.

Depreciation

Depreciation expense increased $1.6 million and $2.1 million for the three months and six months ended April 30, 2013, respectively, compared with the same periods in 2012 primarily due to increases in plant in service, particularly related to system integrity projects being completed.

41

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, non-operating income, non- operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, home service warranty programs, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and miscellaneous expenses. Activity for the three months ended April 30, 2013 compared with the same period in 2012 was comparable.

The primary change to Other Income (Expense) for the six months ended April 30, 2013 compared with the same period in 2012 was income from equity method investments, primarily from SouthStar Energy Services LLC (SouthStar). Income from equity method investments from SouthStar increased $1.4 million primarily due to increased average customer usage in Georgia related to colder weather relative to the prior year period, net of weather derivatives, and the recording of a lower of cost or market storage inventory adjustment in the prior year, partially offset by increased gas costs.

Utility Interest Charges

Changes in utility interest charges for the three months and six months ended April 30, 2013 compared with the same periods in 2012 are presented below.

Changes in Utility Interest Charges – Increase (Decrease)

In millions	Three Months			Six Months
Borrowed Allowance for Funds Used During Construction (AFUDC)	$	(3.9	)	$	(7.8	)
Regulatory interest expense, net		(.5	)		(1.2	)
Interest expense on short-term debt		(.4	)		(1.1	)
Interest expense on long-term debt		2.6			5.3
Other		(.1	)		(.3	)
Total	$	(2.3	)	$	(5.1	)

• Borrowed AFUDC – the decreases for the three months and six months are due to an increase in capitalized interest primarily as a result of increased construction expenditures in the current periods.

• Regulatory interest expense, net – the decreases for the three months and six months are primarily due to interest charged on increased amounts due from customers, which is recorded as interest income.

• Interest expense on short-term debt – the decrease for the three months is primarily due to interest rates being on average 38 basis points lower than the same prior period with the balance of borrowings being slightly lower in the current period. The decrease for the six months is primarily due to interest rates that are on average 58 basis points lower than the same prior period, partially offset by higher balances outstanding during the current period used for utility capital expenditures and other corporate purposes.

• Interest expense on long-term debt – the increases for the three months and six months are primarily due to higher amounts of debt outstanding in the current periods.

Financial Condition and Liquidity

Our capital market strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical

42

business risks, and maintaining a balanced capital structure through the issuance of equity and long-term debt securities or the repurchase of our equity securities. The need for long-term capital is driven by long-term debt maturities and the level and timing of capital expenditures. Our issuance of long-term debt and equity securities is subject to regulation by the NCUC. On January 29, 2013, we offered 4.6 million shares of our common stock for sale under an open combined debt and equity shelf registration statement, and on February 4, 2013, we issued 3 million of those common shares. Also on January 29, 2013, in connection with the offering of these shares, we entered into a FSA for up to 1 million shares to be settled no later than December 15, 2013. On February 19, 2013, we entered into a second FSA as part of the offering for an additional .6 million shares to be settled no later than December 15, 2013. For further information on these transactions, see Note 6 to the consolidated financial statements in this Form 10-Q.

To meet our capital and liquidity requirements outside of the long-term capital markets, we rely on certain resources, including cash flows from operating activities, cash generated from our investments in joint ventures and short-term debt. Operating activities primarily provides the liquidity to fund our working capital, a portion of our capital expenditures and other cash needs.

Short-term debt is vital to meet the timing of our working capital needs, such as our seasonal requirements for gas supply, pipeline capacity, payment of dividends, general corporate liquidity, a portion of our capital expenditures and approved investments. We rely on short-term debt together with long-term capital markets to provide a significant source of liquidity to meet operating requirements that are not satisfied by internally generated cash flows. Currently, cash flows from operations are not adequate to finance the full cost of planned capital expenditures, which are fundamental to support our system infrastructure and growth.

We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our commercial paper (CP) program and the issuance of long-term debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions and other cash needs. Our ability to satisfy all of these requirements is dependent upon our future operating performance and other factors, some of which we are not able to control. These factors include prevailing economic conditions, regulatory changes, the price and demand for natural gas and operational risks, among others. Liquidity has been enhanced by the extension of bonus depreciation legislation. For further information on bonus depreciation, see the following discussion of “Cash Flows from Operating Activities.”

Short-Term Debt. We have a $650 million five-year revolving syndicated credit facility that expires in October 2017, and we have an option to request an expansion up to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $650 million. The five-year revolving syndicated credit facility contains normal and customary financial covenants.

We have a $650 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt.

Highlights for our short-term debt as of April 30, 2013 and for the quarter ended April 30, 2013 are presented below.

43

Short-Term Debt

As of April 30, 2013

In thousands	Credit Facility			Commercial Paper			Total Borrowings
End of period (April 30, 2013):
Amount outstanding	$	-		$	345,000		$	345,000
Weighted average interest rate		-	%		.30	%		.30	%
During the period (February 1, 2013 – April 30, 2013):
Average amount outstanding	$	-		$	383,600		$	383,600
Minimum amount outstanding		-			315,000			315,000
Maximum amount outstanding		-			525,000			525,000
Minimum interest rate		-	%		.28	%		.28	%
Maximum interest rate		-	%		.37	%		.37	%
Weighted average interest rate		-	%		.33	%		.33	%
Maximum amount outstanding:
February 2013	$	-		$	525,000		$	525,000
March 2013		-			415,000			415,000
April 2013		-			370,000			370,000

As of April 30, 2013, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $2.1 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of April 30, 2013, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $302.9 million.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term debt to meet seasonal working capital needs. The level of short-term debt can vary significantly due to changes in the wholesale cost of natural gas and the level of purchases of natural gas supplies for storage to serve customer demand. We pay our suppliers for natural gas purchases before we collect our costs from customers through their monthly bills. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, construction activity and decreases in receipts from customers.

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

44

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers, but may lead to conservation by customers in order to reduce their heating bills. Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, are expected to mitigate the impact that customer conservation and higher bad debt expense may have on our results of operations. Warmer-than-normal weather can lead to reduced operating cash flows, thereby increasing the need for short-term bank borrowings to meet current cash requirements.

Net cash provided by operating activities was $268.2 million and $244.5 million for the six months ended April 30, 2013 and 2012, respectively. Net cash provided by operating activities reflects an increase of $15.3 million in net income for 2013 compared with 2012 primarily due to higher margin and lower interest expense partially offset by higher operating expenses. The effect of changes in working capital on net cash provided by operating activities is described below.

• Trade accounts receivable and unbilled utility revenues increased $85.3 million from October 31, 2012 primarily due to colder weather and higher consumption of natural gas. Volumes sold to weather-sensitive residential and commercial customers increased 17 million dekatherms as compared with the same prior period primarily due to 27.8% colder weather during the current period. Total throughput increased 43.9 million dekatherms as compared with the same prior period, largely from 22 million dekatherms, or 36%, increased deliveries to power generation customers as well as increased sales to residential and commercial customers.

• Net amounts due from customers decreased $51.7 million from October 31, 2012 primarily due to the collection of deferred gas costs and margin decoupling through rates.

• Gas in storage decreased $24.1 million in the current period primarily due to decreased volumes of gas in storage from higher customer sales in 2013 due to colder weather as discussed above, slightly offset by an increase in the weighted average cost of gas purchased for injections.

• Prepaid gas costs decreased $18.4 million in the current period primarily due to gas being made available for sale during the period. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have WNA mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers in South Carolina and in October through April for residential and commercial customers in Tennessee. The WNA mechanisms in South Carolina and Tennessee generated charges to customers of $2.4 million and $13.7 million in the six months ended April 30, 2013 and 2012, respectively. In Tennessee, adjustments are made directly to individual customer bills. In South Carolina, the adjustments are calculated at the individual customer level but are recorded in “Amounts due from customers” in “Current Assets” or “Amounts due to customers” in “Current Liabilities” in the Consolidated Balance Sheets for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism decreased margin by $3.7 million and increased margin by $38.7 million in the six months ended April 30, 2013 and 2012, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanisms.

45

The American Taxpayer Relief Act of 2012, enacted in January 2013, and The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted in December 2010 (the Acts), extended the 50% bonus depreciation that expired December 2009 and temporarily increased bonus depreciation for federal income tax purposes to 100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010 – 2015. Based on current capital projections and timelines, we are anticipating that bonus depreciation will reduce cash needed to pay federal income taxes during fiscal years 2010 – 2015 by $165 – $205 million as compared with cash tax needs prior to the Acts. While reducing cash tax payments, bonus depreciation will increase deferred tax liabilities by a similar amount. Rate base generally consists of net utility plant in service less utility deferred income tax liabilities. Rate base upon which authorized revenue requirements are determined is expected to increase for 2013, but less than if bonus depreciation had not been in effect.

Primarily due to bonus depreciation, we generated a federal net operating loss (NOL) in our tax year 2012, and we anticipate generating a federal NOL again in our tax year 2013. We will be filing claims to carryback a portion of the NOLs to prior federal income tax returns. We have recorded $30 million in “Income taxes receivable” in “Current Assets” in the Consolidated Balance Sheets for the refundable income taxes that we anticipate will be generated from the carryback of these NOLs. Any NOLs that are not carried back will be carried forward to offset future taxable income. As of April 30, 2013, we have recorded a current deferred tax benefit of approximately $21 million included in “Deferred income taxes” in “Current Liabilities” in the Consolidated Balance Sheets from the estimated 2013 NOLs that we anticipate carrying forward to offset taxable income in 2014. We anticipate that we will generate taxable income sufficient to utilize all NOLs prior to the expiration of the loss carryforward periods.

The financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

The regulated utility competes with other energy products, such as electricity and propane, in the residential and commercial customer markets. The most significant product competition is with electricity for space heating, water heating and cooking. Numerous factors can influence customer demand for natural gas, including price, value, availability, environmental attributes, comfort, convenience, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

In the industrial market, many of our customers are capable of burning a fuel other than natural gas, with fuel oil being the most significant competing energy alternative. Our ability to maintain industrial market share is largely dependent on price. The relationship between supply and demand has the greatest impact on the price of natural gas. The price of oil depends upon a number of factors beyond our control, including the relationship between worldwide supply and demand and the policies of foreign and domestic governments and organizations, as well as the value of the US dollar versus other currencies. Our liquidity could be impacted, either positively or negatively, as a result of alternate fuel decisions made by industrial customers.

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

46

Cash Flows from Investing Activities. Net cash used in investing activities was $294.8 million and $229.2 million for the six months ended April 30, 2013 and 2012, respectively. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures for the six months ended April 30, 2013 were $274.9 million as compared to $220.3 million in the same prior period primarily due to additional expenditures on system integrity projects.

We have a substantial capital expansion program for the construction of transmission and distribution facilities, purchase of equipment and other general improvements. We are increasing our spending for pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity. Our program primarily supports our system infrastructure and the growth in our customer base. To ensure safe pipeline operations, we are also deploying new technology through the development of a new work and asset management system. Significant utility construction expenditures are expected for growth and system integrity and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed.

We anticipate making utility capital expenditures, including AFUDC, in the range of $550 – $600 million in our fiscal year 2013, including approximately $250 million for system integrity projects, and $75 – $85 million for the completion of the Sutton power generation delivery project. Our estimates of utility capital expenditures shown below for 2013 – 2015 include system integrity projects of approximately $150 million in both 2014 and 2015. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 45 – 50% in long-term debt and 50 – 55% in common equity. A portion of the funding for capital expenditures is derived from operations, including lower federal income tax payments due to accelerated depreciation as well as bonus depreciation benefits. Additional detail for the anticipated capital expenditures follows.

In millions	2013		2014		2015
Utility	$	475 – 515	$	275 – 325	$	275 – 325
Sutton power generation project		75 – 85		-		-
Total forecasted capital expenditures	$	550 – 600	$	275 – 325	$	275 – 325

In April 2010, we reached an agreement with Progress Energy Carolinas, now a subsidiary of Duke Energy Corporation, to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement called for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant which was placed into service as scheduled on June 1, 2013. Our investment in the pipeline and compression facilities is supported by a long-term service agreement with fixed monthly payments.

The Sutton facilities also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. We anticipate that a portion of the revenue requirement of this project will be included in our North Carolina utility rates because the facilities will enhance our ability to serve our other North Carolina customers.

In November 2012, we became a 24% equity member of Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The purpose of the joint venture is to construct and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting natural gas gathering systems in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $680 million. Our current fiscal year contributions through April 30, 2013 were $8.7 million, and we expect our total contributions will be an

47

estimated $163 million through 2015 with approximately 90% of that funding to occur during our fiscal 2014 and 2015 years. The target in service date of the project is March 2015. For further information regarding this agreement, see Note 12 to the consolidated financial statements in this Form 10-Q.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was $39.5 million and ($11.7) million for the six months ended April 30, 2013 and 2012, respectively. Funds are primarily provided from long-term securities, short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP), our employee stock purchase plan (ESPP) and bonus depreciation. We may sell common stock and long-term debt when market and other conditions favor such long-term financing to maintain our target capital structure of 50 – 55% equity to total long-term capital. Funds are primarily used to retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program and pay quarterly dividends on our common stock.

Outstanding debt under our syndicated revolving credit facility and CP program decreased to $345 million as of April 30, 2013 from $365 million as of October 31, 2012 primarily due to the net proceeds received from the issuance of our common stock. For further information on short-term debt, see Note 5 to the consolidated financial statements in this Form 10-Q and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”

We have an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that is available for future use. On January 29, 2013, we entered into an underwriting agreement to sell up to 4.6 million shares of our common stock under the registration statement, including the direct issuance of 3 million shares and an additional 1.6 million shares to be issued under FSAs. The offering for 3 million shares was settled on February 4, 2013, and we received net proceeds of $92.6 million from the underwriters at the net price of $30.88, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share. We have two FSAs totaling 1.6 million shares that must be settled no later than December 15, 2013. Under the terms of the FSAs, at our election, we may physically settle in shares, cash or net share settle for all or a portion of our obligations under the agreements. We expect to settle by delivering shares. If we physically settle by issuing the 1.6 million shares to the forward counterparty, the forward counterparty will, at settlement, pay us the proceeds less certain adjustments from its sale of the borrowed shares to the underwriters, which is anticipated to be $47.3 million at December 15, 2013.

We used the net proceeds from this sale of our common stock to repay outstanding unsecured notes under the CP program. We intend to use the proceeds from the FSAs for the same purpose and for general corporate purposes. For further information on our common stock, see Note 6 to the consolidated financial statements in this Form 10-Q.

We anticipate issuing $300 million in long-term debt in fiscal 2013, in part to fund the balance of $100 million of our 5% medium-term notes due in December 2013 with the remainder of the proceeds to be used to repay short-term debt and for general corporate purposes. We continually monitor customer growth trends and investment opportunities in our markets and the timing of any infrastructure investments that would require the need for additional long-term debt.

During the six months ended April 30, 2013 and 2012, we issued $12.3 million and $10.8 million, respectively, of common stock through DRIP and ESPP. From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2 in this Form 10-Q. We do not anticipate repurchasing any of our common stock in our fiscal year 2013. During the six months ended April 30, 2012, we repurchased and retired .8 million shares for $26.5 million under the program.

We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain note agreements under which certain long-term debt was issued restrict the amount of cash dividends that may be paid. As of April 30, 2013, our retained earnings were not restricted. On June 7, 2013, the Board of Directors declared a quarterly dividend on common stock of $.31 per share, payable July 15, 2013 to shareholders of record at the close of business on June 24, 2013.

48

Our long-term targeted capitalization ratio is 45 – 50% in long-term debt and 50 – 55% in common equity. As of April 30, 2013, our capitalization, including current maturities of long-term debt, if any, consisted of 44% in long-term debt and 56% in common equity.

The components of our total debt outstanding (short-term debt and long-term debt) to our total capitalization as of April 30, 2013 and 2012, and October 31, 2012, are summarized in the table below.

	April 30					October 31					April 30
In thousands	2013		Percentage			2012		Percentage			2012		Percentage
Short-term debt	$	345,000		14	%	$	365,000		16	%	$	80,000		4	%
Current portion of long-term debt		100,000		4	%		-		-	%		-		-	%
Long-term debt		875,000		34	%		975,000		41	%		975,000		46	%
Total debt		1,320,000		52	%		1,340,000		57	%		1,055,000		50	%
Common stockholders’ equity		1,230,731		48	%		1,027,004		43	%		1,064,811		50	%
Total capitalization (including short-term debt)	$	2,550,731		100	%	$	2,367,004		100	%	$	2,119,811		100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. The borrowing costs under our revolving credit facility and our CP program are based on our credit ratings, and consequently, any decrease in our credit ratings would increase our borrowing costs. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds.

The lenders under our revolving credit facility and our CP program are major financial institutions, all of which have investment grade credit ratings as of April 30, 2013. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

As of April 30, 2013, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P) and “A3” by Moody’s Investors Service (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our CP program at “A1” and “P2”, respectively. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, capital structure, a change from the constructive regulatory environments in which we operate or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by our rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of April 30, 2013, there has been no event of default giving rise to acceleration of our debt.

49

Estimated Future Contractual Obligations

During the three months ended April 30, 2013, there were no material changes to our estimated future contractual obligations in Management’s Discussion and Analysis in this Form 10-Q compared to the disclosure provided in our Form 10-K for the year ended October 31, 2012. Based on current cost estimates, we are contractually committed to fund an estimated $163 million in proportion to our 24% membership interest in Constitution for the development and construction of a new pipeline. As of April 30, 2013, we have funded $8.7 million. For further information about this contractual obligation, see Note 12 to the consolidated financial statements in this Form 10-Q.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than letters of credit and operating leases. The letters of credit are discussed in Note 5 to the consolidated financial statements in this Form 10-Q. The operating leases were discussed in Note 8 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2012.

Critical Accounting Policies and Estimates

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

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates presented in our Form 10-K for the year ended October 31, 2012 in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Management has discussed these critical accounting estimates with the Audit Committee of the Board of Directors. There have been no changes in our critical accounting policies and estimates since October 31, 2012.

Accounting Guidance

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

50

During the six months ended April 30, 2013, there were no material changes in the way that we monitor and manage market risk and credit risk in accordance with our policies and procedures. Our exposure to and management of interest rate risk, commodity price risk and weather risk has remained the same during the six months ended April 30, 2013. Our annual discussion of market risk was included in Item 7A of our Form 10-K as of October 31, 2012.

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

As of April 30, 2013, we had $345 million of debt outstanding under our CP program at an interest rate of .30%, which at April 30, 2013 was the rate for the CP program as we were not borrowing under the revolving syndicated credit facility. The carrying amount of this debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $2.1 million during the six months ended April  30, 2013.

Item 4. Controls and Procedures

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

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the second quarter of fiscal 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

During the six months ended April 30, 2013, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2012.

51

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

c) Issuer Purchases of Equity Securities.

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended April 30, 2013.

Period	Total Number of Shares Purchased			Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Program		Maximum Number of Shares that May Yet be Purchased Under the Program (1)
Beginning of the period									2,910,074
2/1/13 – 2/28/13		-		$	-		-		2,910,074
3/1/13 – 3/31/13		-		$	-		-		2,910,074
4/1/13 – 4/30/13		48	(2)	$	33.01		-		2,910,074
Total		48		$	33.01		-

(1) The Common Stock Open Market Purchase Program was approved by the Board of Directors and announced on June 4, 2004 to purchase up to three million shares of common stock for reissuance under our dividend reinvestment and stock purchase, employee stock purchase and incentive compensation plans. On December 16, 2005, the Board of Directors approved an increase in the number of shares in this program from three million to six million to reflect the two-for-one stock split in 2004. The Board also approved on that date an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. The additional four million shares were referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

(2) The total number of shares purchased is shares withheld by us to satisfy tax withholding obligations related to the vesting of shares awarded under an incentive compensation award that is outside of the Common Stock Open Market Purchase Program.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of April 30, 2013, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 6. Exhibits

10.1	Confirmation of Forward Sale Transaction dated February 19, 2013 between Piedmont Natural Gas Company, Inc. and Morgan Stanley & Co. LLC, in its capacity as the forward counterparty (incorporated by reference to Exhibit 99.1, Form 8-K filed February 25, 2013)
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer

52

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Calculation Linkbase
101.DEF	XBRL Taxonomy Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheets at April 30, 2013 and October 31, 2012; (3) Consolidated Statements of Comprehensive Income for the three months and six months ended April 30, 2013 and 2012; (4) Consolidated Statements of Cash Flows for the six months ended April 30, 2013 and 2012; (5) Consolidated Statements of Stockholders’ Equity for the six months ended April 30, 2013 and 2012; and (6) Notes to Consolidated Financial Statements.

53

SIGNATURES

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

Piedmont Natural Gas Company, Inc.

(Registrant)

Date June 7, 2013	/s/ Karl W. Newlin
	Karl W. Newlin
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Date June 7, 2013	/s/ Jose M. Simon
	Jose M. Simon
	Vice President and Controller (Principal Accounting Officer)

54

Piedmont Natural Gas Company, Inc.

Form 10-Q

For the Quarter Ended April 30, 2013

Exhibits

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

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Thomas E. Skains, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   June 7, 2013	/s/ Thomas E. Skains
	Thomas E. Skains
	Chairman of the Board, President
	and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Karl W. Newlin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Piedmont Natural Gas Company, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   June 7, 2013	/s/ Karl W. Newlin
	Karl W. Newlin
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Quarterly Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-Q for the period ended April 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Skains, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

June 7, 2013

/s/ Thomas E. Skains

Thomas E. Skains

Chairman of the Board, President and Chief Executive Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Quarterly Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-Q for the period ended April 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Karl W. Newlin, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

June 7, 2013

/s/ Karl W. Newlin

Karl W. Newlin

Senior Vice President and Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Commitment & Contingencies (Disclosure)

3 Months Ended

Apr. 30, 2013

Commitments And Contingencies Disclosure [Abstract]

Commitments And Contingencies Disclosure Text Block

9.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. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for pipeline and storage capacity contracts are uptotwenty-two years. The time periods for gas supply contracts are up to eleven months.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 are uptofouryears. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (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 Comprehensive 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. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

Legal

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

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our generaland automobile liability policies. We had $2.1million in letters of credit that were issued and outstanding as ofApril 30, 2013. Additional information concerning letters of credit is included in Note 5 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.

We are responsible for any third-party claims for personal injury, death, property damage and diminution of property value or natural resources regarding nine manufactured gas plant (MGP) sites that were a part of a 1997 settlement with a third party and several MGP sites retained by Progress Energy, Inc., now a subsidiary of Duke Energy Corporation, in connection with our 2003acquisition of North Carolina Natural Gas Corporation. We know of no such pending or threatened claims.

There are fourother MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated and for which we have an investigation and remediation liability. In fiscal year 2012, we performed soil remediation work at our Reidsville site. In July 2012, the North Carolina Department of Environment and Natural Resources (NCDENR) approved our proposed groundwater investigation work plan, which included installing five monitoring wells in September 2012.Although the water samples from these wells yielded uncontaminated groundwater, NCDENR is requesting a groundwater remedial action plan requiring additional sampling activities to be conducted for one year. We have incurred $.6million of remediation costs at the Reidsville site through April 30, 2013.

As part of a voluntary agreement with the NCDENR, we conducted and completed soil remediationfor the Hickory, North Carolina MGP site in 2010. A Phase II groundwater investigation was conducted in 2011. A groundwater remedial action plan was submitted and approved by the NCDENR in 2012. We continue to conduct quarterly groundwater monitoring at this site in accordance with our site remediation plan. We have incurred $1.5 millionof remediation costsat this site through April 30, 2013.

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 final consent order imposing land usage restrictions on the property was approved and signed by the TDEC in June 2010. The final consent order required two years of semi-annual groundwater monitoring, which has been completed. In February 2013, we received a letter from the TDEC certifying completion of the actions agreed to be taken in the consent order. We have incurred $1.5 million of remediation costs at this site through April 30, 2013.

During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville LNG facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required at the site for this issue. In September 2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site. In April 2012, we entered into a no admit/no deny ACO that imposed a fine of $40,000, unpaid annual fees totaling $18,000and $1,860 for investigative and administrative costs. As part of the ACO, we were required to develop a site assessment plan to determine the extent of the groundwater contamination related to the sieve burial, a groundwater remediation strategy and a groundwater and surface water site-wide monitoring program. A site assessment plan was accepted by the NCDENR,and we began groundwater sampling in July 2012. We performed an initial round of samplingin our first quarter, and additional groundwater monitoring wells were installed during our second quarter to aid in determining the extent of the groundwater contamination. The groundwater sampling results will be submitted to the NCDENR, and based on their response,we may be required to submit additional plan(s) to remediate and/or monitor the groundwater. These plan(s) are duewithin thirty days of the completion of the site assessment.

The Huntersville LNG facility was originally coated with lead-based paint. To avoid lead-based paint exposure, removal of lead-based paint from the site was initiated in spring 2010. The last phase of the lead-based paint removal began in July 2012 on the LNG tank, and the remediation of rafters in a nearby building will begin in mid-2013 with completion anticipated for both projects by the end of fiscal 2014. We have incurred $4.3million of remediation costs through April 30, 2013 for all issues at the Huntersville LNG plant site. Once the lead-based paint is removed at our Huntersville LNG facility, we expect there will be no potential environmental or employee exposures.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina resource center is the only location that continues to operate USTs.

For all matters discussed above, as of April 30, 2013, our estimated undiscounted environmental liability totaled $1.8 millionand consisted of $1.1 million for the MGP sites for which we retain remediation responsibility, $.2million for the LNG facilities, $.2 million for the groundwater remediation at the Huntersville LNG site and $.3 million for the USTs not yet remediated. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others.

As of April 30, 2013, our regulatory assets for unamortized environmental costs in our three-state territory totaled $10.2 million. We received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the recent general rate case proceeding in Tennessee. We will seek recovery of the remaining balance in future rate proceedings. For further information on regulatory matters, see Note 2 to the consolidated financial statements in this Form 10-Q.

Further evaluation of the MGP, LNG and UST sites and removal of lead-based paint at our LNG site could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.

Additional information concerning commitments and contingencies is set forth in Note 8to theconsolidated financial statements of our Form 10-K for the year ended October 31, 2012.

XML

Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended		6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012
Consolidated Statements of Comprehensive Income (Unaudited)
Operating Revenues	$ 399,411,000	$ 308,432,000	$ 915,286,000	$ 780,272,000
Cost of Gas	215,555,000	136,481,000	499,806,000	388,085,000
Margin	183,856,000	171,951,000	415,480,000	392,187,000
Operating Expenses
Operations and maintenance	65,037,000	60,511,000	120,919,000	118,908,000
Depreciation	26,867,000	25,269,000	53,569,000	51,447,000
General taxes	9,068,000	9,299,000	18,596,000	17,920,000
Utility income taxes	31,380,000	28,090,000	84,679,000	75,311,000
Total operating expenses	132,352,000	123,169,000	277,763,000	263,586,000
Operating Income	51,504,000	48,782,000	137,717,000	128,601,000
Other Income (Expense)
Income from equity method investments	12,437,000	11,652,000	19,592,000	17,944,000
Non-operating income	742,000	581,000	1,190,000	641,000
Non-operating expense	(696,000)	(626,000)	(1,458,000)	(1,047,000)
Income taxes	(4,875,000)	(4,534,000)	(7,549,000)	(6,852,000)
Total other income (expense)	7,608,000	7,073,000	11,775,000	10,686,000
Utility Interest Charges
Interest on long-term debt	12,652,000	10,005,000	25,327,000	20,028,000
Allowance for borrowed funds used during construction	(9,938,000)	(6,053,000)	(18,251,000)	(10,476,000)
Other	608,000	1,711,000	703,000	3,316,000
Total utility interest charges	3,322,000	5,663,000	7,779,000	12,868,000
Net Income	55,790,000	50,192,000	141,713,000	126,419,000
Other Comprehensive Income (Loss), net of tax
Unrealized gain (loss) from hedging activities of equity method investments, net of tax	238,000	(419,000)	59,000	(855,000)
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax	76,000	(11,000)	97,000	415,000
Total other comprehensive income (loss)	314,000	(430,000)	156,000	(440,000)
Comprehensive Income	$ 56,104,000	$ 49,762,000	$ 141,869,000	$ 125,979,000
Average Shares of Common Stock
Basic	75,463,000	71,731,000	73,884,000	71,931,000
Diluted	75,904,000	72,026,000	74,301,000	72,226,000
Earnings Per Share of Common Stock
Basic	$ 0.74	$ 0.70	$ 1.92	$ 1.76
Diluted	$ 0.74	$ 0.70	$ 1.91	$ 1.75
Cash Dividends Per Share of Common Stock	$ 0.31	$ 0.30	$ 0.61	$ 0.59

XML

Regulatory Matters (Disclosure)

3 Months Ended

Apr. 30, 2013

Regulatory Matters Disclosure [Abstract]

Public Utilities Disclosure Text Block

2.       Regulatory Matters

In October 2012, we filed a petition with theNorth Carolina Utility Commission (NCUC) seeking authority to transfer $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” relates to the development of the liquefied natural gas (LNG) facility in Robeson County, North Carolina, construction of which was suspended by Piedmont in March 2009. In January 2013, we filed a motion to suspend this filing in order to incorporate it into a future regulatory proceeding. On April 30, 2013, we withdrew the petition, citing our intent to file a general rate application and address the appropriate treatment of the Robeson County LNG costs in that general rate application.

On May 31, 2013, we filed a general rate application with the NCUC requesting an increase in rates and charges for all customers to produce overall increased annual revenues of $79.8million, or9.3% above the current annual revenues. This represents an annual average cost increase of 1.86% since our last general rate proceeding in 2008. In this proceeding, we are seeking authorization from the NCUC to:

• Update and increase our rates and charges based on an overall rate base of $1.9 billion, an equity capital structure component of 50.7% and a return on common equity of 11.3%,
• Increase total revenues by $79.8 million, including $66.2 million related to gas utility margin and $13.6 million related to increased fixed gas costs,
• Implement a new integrity rider designed to separately track and recover the costs associated with significant levels of capital expenditures projected to be incurred to comply with federal pipeline safety and integrity requirements,
• Implement new depreciation rates to amortize the costs of assets, net of salvage value, over the estimated useful life of the assets,
• Update and revise our existing service regulations and tariffs,
• Amortize and collect certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above,
• Amortize and collect certain environmental expenses and pipeline safety and integrity compliance expenses that have been deferred in the period since our last general rate case, and
• Provide for ongoing annual contributions to help fund pipeline safety and integrity research.

New rates are proposed to be effective January 1, 2014. We are waiting on a hearing date to be set by the NCUCfor this general rate proceeding at this time.

On February 7, 2013, the Public Service Commission of South Carolina (PSCSC) set a hearing date of July 11, 2013 for our annual review of purchased gas adjustment (PGA) and gas purchasing policies for the twelve months ended March 31, 2013. We filed our testimony in this proceeding on June 4, 2013.

In August 2012, we filed an annual report with the Tennessee Regulatory Authority (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, 2012 under the Tennessee Incentive Plan (TIP). On February 27, 2013, the TRA Utilities Division Audit Staff (Staff) submitted their Audit Report with which we concurred. On March 13, 2013, the TRA approved and adopted the Staff's Audit Report and issued its written order on March 26, 2013.

In September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. On February 26, 2013, the Staff submitted their ACA Compliance Audit Report with which we concurred. On March 13, 2013, the TRA approved and adopted the Staff's ACA Compliance Audit Report and issued its written order on March 26, 2013.

XML

Summary Of Significant Accounting Policies (Policies)

3 Months Ended

Apr. 30, 2013

Summary Of Significant Accounting Policies [Abstract]

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, 2012.

Seasonality

The unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of the statement of financial position at April 30, 2013 and October 31, 2012, the results of operations for the three months and six months ended April 30, 2013 and 2012, and cash flows and stockholders' equityfor the six months ended April 30, 2013 and 2012. Our business is seasonal in nature. The results of operations for the threemonths and sixmonths ended April 30, 2013 do not necessarily reflect the results to be expected for the full year.

Use of Estimates

In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the periods reported. 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 these estimates and assumptions.

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.

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.

Fair Value Measurements

Our financial assets and liabilities are recorded at fair value. Theyconsist primarilyofderivatives that are recorded in the Consolidated Balance Sheets in accordance with derivativeaccounting standards and marketable securities thatare held in rabbi trusts established for our deferred compensation plans and are classified as trading securities. Our qualified pension and postretirement plan assets and liabilities are recorded at fair value in the Consolidated Balance Sheets in accordance with employers' accounting and related disclosures of postretirement plans.

Fair value is the price that would be received to sell an asset or paid to transfer a liability inan orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to thevaluation technique. These inputs can be readily observable, market corroborated or generallyunobservable. We primarily apply the market approach for fair value measurements andendeavor to utilize the best available information. Accordingly, we use valuation techniques thatmaximize the use of observable inputs and minimize the use of unobservable inputs.

Marketable Securities

The fair values of the equity securities are based on the quoted market prices as traded on the exchanges.

Trading securities are recorded at fair value in the Consolidated Balance Sheets with any gains or losses recognized currently in earnings.

Earnings Per Share

We compute basic earnings per share (EPS) using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are included in our calculation of fully diluted EPS.

Subsequent Events Policy Text Block

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.

XML

Employee Benefit Plans (Disclosure)

3 Months Ended

Apr. 30, 2013

Pension Plans and Postretirement Plans Disclosure [Abstract]

Pension And Other Postretirement Benefits Disclosure Text Block

10.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, 2013 and 2012 are presented below.

	Qualified Pension				Nonqualified Pension				Other Benefits
In thousands		2013		2012		2013		2012		2013		2012
Service cost	$	3,150	$	2,475	$	-	$	10	$	332	$	347
Interest cost		2,475		2,650		40		51		282		337
Expected return
on plan assets		(5,300)		(5,125)		-		-		(416)		(388)
Amortization of
transition obligation		-		-		-		-		167		167
Amortization of prior
service (credit) cost		(550)		(550)		20		20		-		-
Amortization of actuarial
loss		2,750		1,375		40		12		-		-
Total	$	2,525	$	825	$	100	$	93	$	365	$	463

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the six months ended April 30, 2013 and 2012 are presented below.

	Qualified Pension				Nonqualified Pension				Other Benefits
In thousands		2013		2012		2013		2012		2013		2012
Service cost	$	6,300	$	4,950	$	-	$	20	$	663	$	693
Interest cost		4,950		5,300		79		102		565		674
Expected return
on plan assets		(10,600)		(10,250)		-		-		(832)		(776)
Amortization of
transition obligation		-		-		-		-		334		334
Amortization of prior
service (credit) cost		(1,100)		(1,100)		40		40		-		-
Amortization of actuarial
loss		5,500		2,750		80		24		-		-
Total	$	5,050	$	1,650	$	199	$	186	$	730	$	925

In November 2012, we contributed $20 millionto the qualified pension plan,and in January 2013, we contributed $.7 million to the money purchase pension plan. We anticipate that we will contribute the following amounts to our other plans in 2013.

In thousands
Nonqualified pension plans	$	502
OPEB plan		1,500

We have a non-qualified defined contribution restoration (DCR)plan thatwe fund annually and that covers all officers at the vice president level and above. For the sixmonths ended April 30, 2013,we contributed $.4million to this plan.Participants may not contribute to the DCR plan. We have a voluntary deferral plan for the benefit of alldirector-levelemployees and officers, where we make no contributionsto this plan. Both deferred compensation plans are funded through rabbi trusts with a bank as the trustee. As ofApril 30, 2013, we have a liability of $3.1 million for these plans.

See Note 7 and Note 8 to the consolidated financial statements in this Form 10-Q for information on the investments in marketable securities that are held in the trusts.

XML

Business Segments Reconciliations To Statements Of Operations (Details) (USD $)	3 Months Ended		6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012
Net Income [Abstract]
Income Before Income Taxes	$ 92,045,000	$ 82,816,000	$ 233,941,000	$ 208,582,000
Income Taxes	(36,255,000)	(32,624,000)	(92,228,000)	(82,163,000)
Net Income	55,790,000	50,192,000	141,713,000	126,419,000
Segment Reconciliation Abstract
Segment Operating Income (Loss) Before Income Taxes	82,814,000	76,846,000	222,191,000	203,780,000
Utility Income Taxes	(31,380,000)	(28,090,000)	(84,679,000)	(75,311,000)
Non-utility Activities Before Income Taxes	70,000	26,000	205,000	132,000
Operating Income	$ 51,504,000	$ 48,782,000	$ 137,717,000	$ 128,601,000

XML

Short Term Debt (Details) (USD $)	3 Months Ended	6 Months Ended
	Apr. 30, 2013	Apr. 30, 2013	Oct. 31, 2012
Line Of Credit Facility [Line Items]
Credit Facility Maximum Amount Outstanding During Period	$ 525,000,000	$ 555,000,000
Credit Facility Minimum Amount Outstanding During Period	315,000,000	315,000,000
Short-term debt	345,000,000	345,000,000	365,000,000
Maximum [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.37%	1.12%
Minimum [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.28%	0.28%
Weighted Average [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.33%	0.36%
Letter Of Credit [Member]
Line Of Credit Facility [Line Items]
Credit Facility Current Borrowing Capacity	10,000,000	10,000,000	10,000,000
Credit Facility Amount Outstanding	2,100,000	2,100,000	3,600,000
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Credit Facility Current Borrowing Capacity	650,000,000	650,000,000
Maximum Facility	850,000,000	850,000,000
Line Of Credit Commitment Annual Fee	$35,000 plus 8.5 basis points
Line Of Credit Facility Frequency Of Commitment Fee Payment	Annual
Maximum Unused Amount On Which Fees Are Payable	650,000,000
Credit Facility Interest Rate Description	30-day LIBOR rate plus from 75 to 125 basis points
Credit Facility Covenant Terms	total debt to total capitalization of no greater than 70%
Credit Facility Covenant Compliance	actual ratio was 52%
Credit Facility Maximum Amount Outstanding During Period	0	10,000,000
Credit Facility Minimum Amount Outstanding During Period	0	0
Line of Credit Facility, Expiration Date	Oct. 01, 2017
Revolving Credit Facility [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.00%	1.12%
Revolving Credit Facility [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.00%	1.12%
Revolving Credit Facility [Member] | Weighted Average [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.00%	1.12%
Commercial Paper [Member]
Line Of Credit Facility [Line Items]
Credit Facility Interest Rate Description	among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points
Weighted Average Interest Rate	0.30%	0.30%
Credit Facility Maximum Amount Outstanding During Period	525,000,000	555,000,000
Credit Facility Minimum Amount Outstanding During Period	315,000,000	315,000,000
Commercial Paper	$ 345,000,000	$ 345,000,000	$ 365,000,000
Short Term Borrowings Term	$650 million unsecured commercial paper (CP) program that is backstopped by the revolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million unless the option to expand the credit facility is exercised as discussed above. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt.
Commercial Paper [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.37%	0.45%
Number Days Outstanding From Issuance Until Maturity	14 days	14 days
Commercial Paper [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.28%	0.28%
Number Days Outstanding From Issuance Until Maturity	8 days	8 days
Commercial Paper [Member] | Weighted Average [Member]
Line Of Credit Facility [Line Items]
Line of Credit Facility Interest Rate During Period	0.33%	0.36%

XML

Stockholders' Equity (Tables)

3 Months Ended

Apr. 30, 2013

Stockholders' Equity [Abstract]

Schedule Of Capital Stock [Table Text Block]

Changes in common stock for the six months ended April 30, 2013 are as follows.

In thousands	Shares	Amount
Balance, October 31, 2012	72,250	$	442,461
Issued to participants in the Employee Stock Purchase Plan (ESPP)	16		505
Issued to the Dividend Reinvestment and Stock Purchase Plan	360		11,136
Issued to participants in the Incentive Compensation Plan (ICP)	94		2,999
Issuance of common stock through public share offering, net of underwriting fees	3,000		92,640
Costs from issuance of common stock	-		(358)
Balance, April 30, 2013	75,720	$	549,383

Schedule Of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

Changes of each component ofaccumulated OCILare presented below for the three months and sixmonths ended April 30, 2013.

	Changes in Accumulated OCIL(1)
	Three		Six
In thousands	Months		Months
Accumulated OCIL beginning balance, net of tax	$	(463)	$	(305)
OCIL before reclassifications, net of tax		238		59
Amounts reclassified from accumulated OCIL, net of tax		76		97
Total current period activity, net of tax		314		156
Accumulated OCIL ending balance, net of tax	$	(149)	$	(149)
(1) Amounts in parentheses indicate debits to accumulated OCIL.

Reclassification Out Of Accumulated Other Comprehensive Income [Table Text Block]

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the three months and six months ended April 30, 2013.

	Reclassifications Out of
	Accumulated OCIL (1)
	Three		Six		Affected Line Items on Statement
In thousands	Months		Months		of Comprehensive Income
Hedging activities of equity method investments	$	(125)	$	(160)	Income from equity method investments
Income tax expense		49		63	Income taxes
Total reclassification for the period, net of tax	$	(76)	$	(97)
(1) Amounts in parentheses indicate credits to accumulated OCIL.

XML

Short Term Debt (Tables)

3 Months Ended

Apr. 30, 2013

Short Term Debt Disclosure [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

A summary of the short-term debt activity for the threemonths and six months ended April 30, 2013 is as follows.

	Credit Facility						Commercial Paper						Total Borrowings (3)
	Three			Six			Three			Six			Three			Six
In millions	Months			Months			Months			Months			Months			Months
Minimum amount outstanding during period (1)	$	-		$	-		$	315		$	315		$	315		$	315
Maximum amount outstanding during period (1)		-			10			525			555			525			555
Minimum interest rate during period (2)		-	%		1.12	%		.28	%		.28	%		.28	%		.28	%
Maximum interest rate during period		-	%		1.12	%		.37	%		.45	%		.37	%		1.12	%
Weighted average interest rate during period		-	%		1.12	%		.33	%		.36	%		.33	%		.36	%
(1) During December 2012, we were borrowing under both the credit facility and CP program for a portion of the month.
(2) This is the minimum rate when we were borrowing under the credit facility and/or CP program.
(3) The minimum and maximum balances outstanding for each short-term debt instrument occurred at different times during the period; therefore, the total balances may not be indicative of actual borrowings on any one day during the period.

XML

Variable Interest Entities (Details) (Variable Interest Entity, Not Primary Beneficiary [Member], USD $)	Apr. 30, 2013	Oct. 31, 2012
Variable Interest Entity [Line Items]
Variable Interest Entity Nonconsolidated Carrying Amount Assets	$ 94,766,000	$ 87,867,000
Cardinal Pipeline Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Nonconsolidated Carrying Amount Assets	18,270,000	17,969,000
Pine Needle Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Nonconsolidated Carrying Amount Assets	18,585,000	19,239,000
South Star Energy Services [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Nonconsolidated Carrying Amount Assets	15,467,000	18,118,000
Piedmont Hardy Storage [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Nonconsolidated Carrying Amount Assets	33,465,000	32,541,000
Constitution Pipeline Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Nonconsolidated Carrying Amount Assets	$ 8,979,000	$ 0

XML

Business Segments (Tables)

3 Months Ended

Apr. 30, 2013

Business Segments Details [Abstract]

Operations By Segment [Table Text Block]

Operations by segment for the threemonths and six months ended April 30, 2013 and 2012 are presented below.

		Regulated				Non-utility
In thousands		Utility				Activities				Total
		2013		2012		2013		2012		2013		2012
Three Months
Revenues from external customers	$	399,411	$	308,432	$	-	$	-	$	399,411	$	308,432
Margin		183,856		171,951		-		-		183,856		171,951
Operations and maintenance expenses		65,037		60,511		66		21		65,103		60,532
Income from equity method investments		-		-		12,437		11,652		12,437		11,652
Operating income (loss) before income taxes		82,884		76,872		(70)		(26)		82,814		76,846
Income before income taxes		79,678		71,189		12,367		11,627		92,045		82,816
Six Months
Revenues from external customers	$	915,286	$	780,272	$	-	$	-	$	915,286	$	780,272
Margin		415,480		392,187		-		-		415,480		392,187
Operations and maintenance expenses		120,919		118,908		120		44		121,039		118,952
Income from equity method investments		-		-		19,592		17,944		19,592		17,944
Operating income (loss) before income taxes		222,396		203,912		(205)		(132)		222,191		203,780
Income before income taxes		214,555		190,770		19,386		17,812		233,941		208,582

Segment Information To Consolidated Financial Statements Reconciliation [Table Text Block]

Reconciliations to the Consolidated Statements of Comprehensive Income for the three months and sixmonths ended April 30, 2013and 2012 are presented below.

In thousands		Three Months				Six Months
		2013		2012		2013		2012
Operating Income:
Segment operating income before
income taxes	$	82,814	$	76,846	$	222,191	$	203,780
Utility income taxes		(31,380)		(28,090)		(84,679)		(75,311)
Non-utility activities before income taxes		70		26		205		132
Operating income	$	51,504	$	48,782	$	137,717	$	128,601

Schedule Of Reconciliation Income Before Taxes To Net Income [Table Text Block]

Net Income:
Income before income taxes for
reportable segments	$	92,045	$	82,816	$	233,941	$	208,582
Income taxes		(36,255)		(32,624)		(92,228)		(82,163)
Net income	$	55,790	$	50,192	$	141,713	$	126,419

XML

Marketable Securities (Details) (USD $)	Apr. 30, 2013	Oct. 31, 2012
Investment Measurement [Line Items]
Current trading securities (fair value)	$ 180,000	$ 157,000
Noncurrent trading securities (fair value)	2,806,000	2,131,000
Current trading securities (cost)	134,000	134,000
Noncurrent trading securities (cost)	2,380,000	1,911,000
Total trading (fair value)	2,986,000	2,288,000
Total trading securities (cost)	2,514,000	2,045,000
Money markets
Investment Measurement [Line Items]
Current trading securities (fair value)	0	0
Noncurrent trading securities (fair value)	335,000	243,000
Current trading securities (cost)	0	0
Noncurrent trading securities (cost)	335,000	243,000
Total trading (fair value)	335,000	243,000
Mutual funds
Investment Measurement [Line Items]
Current trading securities (fair value)	180,000	157,000
Noncurrent trading securities (fair value)	2,471,000	1,888,000
Current trading securities (cost)	134,000	134,000
Noncurrent trading securities (cost)	2,045,000	1,668,000
Total trading (fair value)	$ 2,651,000	$ 2,045,000

XML

Subsequent Events (Details) (Subsequent Event [Member], NCUC [Member], USD $)	May 31, 2013
Subsequent Event [Member] | NCUC [Member]
Subsequent Event [Line Items]
Requested Annual Revenues Increase (Decrease)	$ 79,800,000
Requested Percentage Increase (Decrease)	9.30%
Proposed Return On Equity	11.30%
Requested Annual Average Cost Increase From Last Rate Case	1.86%
Proposed Equity Capital Structure Percentage	50.70%
Requested Increase Revenues Related To Gas Utility Margin	66,200,000
Requested Increase Revenues Related To Fixed Gas Costs	13,600,000
Overall Rate Base With Requested Rates And Charges	$ 1,900,000,000

XML

Employee Share Based Plans (Tables)

3 Months Ended

Apr. 30, 2013

Employee Share Based Plans Details [Abstract]

Compensation Expense And Liabilities

The compensation expense related to the incentive compensation plans for the threemonths and six months ended April 30, 2013 and 2012, and the amounts recorded as liabilities as of April 30, 2013 and October 31, 2012 are presented below.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Compensation expense	$	1,801	$	501	$	3,657	$	2,075
		April 30,		October 31,
		2013		2012
Liability	$	10,228	$	10,631

XML

Employee Benefit Plans (Details) (USD $)	3 Months Ended		6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012
Defined Contribution Plans Disclosure [Abstract]
Defined Contribution Restoration and Voluntary Deferral Plan Recorded Liability	$ 3,100,000
VDP Employer Contribution			0
MPP Plan [Member]
Defined Contribution Plans Disclosure [Abstract]
Employee Benefit Plan Employer Contribution			700,000
DCR Plan [Member]
Defined Contribution Plans Disclosure [Abstract]
Employee Benefit Plan Employer Contribution			400,000
Qualified Pension [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Abstract]
Service Cost	3,150,000	2,475,000	6,300,000	4,950,000
Interest Cost	2,475,000	2,650,000	4,950,000	5,300,000
Expected Return On Plan Assets	(5,300,000)	(5,125,000)	(10,600,000)	(10,250,000)
Amortization Of Transition Obligation	0	0	0	0
Amortization Of Prior Service (Credit) Cost	(550,000)	(550,000)	(1,100,000)	(1,100,000)
Amortization Of Actuarial Loss	2,750,000	1,375,000	5,500,000	2,750,000
Net Periodic Benefit Cost	2,525,000	825,000	5,050,000	1,650,000
Defined Benefit Plan, Contributions by Employer			20,000,000
Non Qualified Pension [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Abstract]
Service Cost	0	10,000	0	20,000
Interest Cost	40,000	51,000	79,000	102,000
Expected Return On Plan Assets	0	0	0	0
Amortization Of Transition Obligation	0	0	0	0
Amortization Of Prior Service (Credit) Cost	20,000	20,000	40,000	40,000
Amortization Of Actuarial Loss	40,000	12,000	80,000	24,000
Net Periodic Benefit Cost	100,000	93,000	199,000	186,000
Future Employee Benefit Plan Employer Contribution	502,000		502,000
Other Benefits [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Abstract]
Service Cost	332,000	347,000	663,000	693,000
Interest Cost	282,000	337,000	565,000	674,000
Expected Return On Plan Assets	(416,000)	(388,000)	(832,000)	(776,000)
Amortization Of Transition Obligation	167,000	167,000	334,000	334,000
Amortization Of Prior Service (Credit) Cost	0	0	0	0
Amortization Of Actuarial Loss	0	0	0	0
Net Periodic Benefit Cost	365,000	463,000	730,000	925,000
Future Employee Benefit Plan Employer Contribution	$ 1,500,000		$ 1,500,000

XML

Earnings Per Share (Tables)

3 Months Ended

Apr. 30, 2013

Earnings Per Share of Common Stock

Earnings Per Share Reconciliation

A reconciliation of basic and diluted EPS for the threemonthsand six months ended April 30, 2013 and 2012 is presented below.

		Three Months				Six Months
In thousands except per share amounts		2013		2012		2013		2012
Net Income	$	55,790	$	50,192	$	141,713	$	126,419
Average shares of common stock outstanding for
basic earnings per share		75,463		71,731		73,884		71,931
Contingently issuable shares under incentive
compensation plans		314		295		333		295
Contingently issuable shares under forward
sale agreements		127		-		84		-
Average shares of dilutive stock		75,904		72,026		74,301		72,226
Earnings Per Share of Common Stock:
Basic	$	0.74	$	0.70	$	1.92	$	1.76
Diluted	$	0.74	$	0.70	$	1.91	$	1.75

XML

Consolidated Statements Of Cash Flows (Unaudited) (USD $)	6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012
Cash Flows from Operating Activities
Net Income	$ 141,713,000	$ 126,419,000
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	56,954,000	53,727,000
Allowance for doubtful accounts (provision)	2,848,000	2,447,000
Net gain on sale of property	(18,000)	0
Income from equity method investments	(19,592,000)	(17,944,000)
Distributions of earnings from equity method investments	16,276,000	12,164,000
Deferred income taxes, net	89,685,000	85,907,000
Changes in assets and liabilities
Gas purchase derivatives, at fair value	(938,000)	166,000
Receivables	(85,257,000)	(11,488,000)
Inventories	24,171,000	18,685,000
Amounts due from/to customers	51,740,000	(8,931,000)
Settlement of legal asset retirement obligations	(1,127,000)	(637,000)
Regulatory asset for postretirement benefits	4,855,000	2,049,000
Other assets	16,314,000	13,101,000
Accounts payable	(4,363,000)	(22,632,000)
Provision for postretirement benefits	(19,427,000)	72,000
Other liabilities	(5,609,000)	(8,632,000)
Net cash provided by operating activities	268,225,000	244,473,000
Cash Flows from Investing Activities
Utility capital expenditures	(274,895,000)	(220,256,000)
Allowance for borrowed funds used during construction	(18,251,000)	(10,476,000)
Contributions to equity method investments	(8,748,000)	(3,356,000)
Distributions of capital from equity method investments	5,422,000	4,850,000
Proceeds from sale of property	614,000	409,000
Investments in marketable securities	(445,000)	(701,000)
Other	1,513,000	350,000
Net cash used in investing activities	(294,790,000)	(229,180,000)
Cash Flows from Financing Activities
Borrowings under credit facility	10,000,000	345,000,000
Repayments under credit facility	(10,000,000)	(676,000,000)
Net borrowings (repayments) - commercial paper	(20,000,000)	380,000,000
Expenses related to issuance of debt	(12,000)	(2,448,000)
Proceeds from issuance of common stock, net of expenses	92,286,000	0
Issuance of common stock through dividend reinvestment and employee stock plans	12,338,000	10,802,000
Repurchases of common stock	0	(26,528,000)
Dividends paid	(45,123,000)	(42,494,000)
Other	18,000	(33,000)
Net cash provided by (used in) financing activities	39,507,000	(11,701,000)
Net Increase in Cash and Cash Equivalents	12,942,000	3,592,000
Cash and Cash Equivalents at Beginning of Period	1,959,000	6,777,000
Cash and Cash Equivalents at End of Period	14,901,000	10,369,000
Cash Paid During the Year for
Interest	23,720,000	22,878,000
Income Taxes
Income taxes paid	1,352,000	3,344,000
Income taxes refunded	0	0
Income taxes, net	1,352,000	3,344,000
Noncash Investing and Financing Activities
Accrued capital expenditures	$ 54,120,000	$ 3,776,000

XML

Consolidated Statements of Stockholders' Equity (Unaudited) (Parentheticals) (USD $)	6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012
Consolidated Statements of Stockholders' Equity (Unaudited)
Dividends declared per share	$ 0.61	$ 0.59

XML

Earnings Per Share (Disclosure)

3 Months Ended

Apr. 30, 2013

Earnings Per Share of Common Stock

Earnings Per Share

3.       Earnings per Share

We compute basic earnings per share (EPS) using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are included in our calculation of fully diluted EPS.

A reconciliation of basic and diluted EPS for the threemonthsand six months ended April 30, 2013 and 2012 is presented below.

		Three Months				Six Months
In thousands except per share amounts		2013		2012		2013		2012
Net Income	$	55,790	$	50,192	$	141,713	$	126,419
Average shares of common stock outstanding for
basic earnings per share		75,463		71,731		73,884		71,931
Contingently issuable shares under incentive
compensation plans		314		295		333		295
Contingently issuable shares under forward
sale agreements		127		-		84		-
Average shares of dilutive stock		75,904		72,026		74,301		72,226
Earnings Per Share of Common Stock:
Basic	$	0.74	$	0.70	$	1.92	$	1.76
Diluted	$	0.74	$	0.70	$	1.91	$	1.75

XML

Significant Accounting Policies (Disclosure)

3 Months Ended

Apr. 30, 2013

Summary Of Significant Accounting Policies [Abstract]

Significant Accounting Policies Text Block

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, 2012.

Seasonality and Use of Estimates

The unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of the statement of financial position at April 30, 2013 and October 31, 2012, the results of operations for the three months and six months ended April 30, 2013 and 2012, and cash flows and stockholders' equityfor the six months ended April 30, 2013 and 2012. Our business is seasonal in nature. The results of operations for the threemonths and sixmonths ended April 30, 2013 do not necessarily reflect the results to be expected for the full year.

In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the periods reported. 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 these estimates and assumptions.

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, 2012. There were no significant changes to those accounting policies during the six months ended April 30, 2013.

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 commissions 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 regulatory assets are recoverable in current rates or future rate proceedings.

Regulatory assets and liabilities in the Consolidated Balance Sheets as of April 30, 2013 and October 31, 2012 are as follows.

		April 30,		October 31,
In thousands		2013		2012
Regulatory assets	$	239,106	$	293,104
Regulatory liabilities		504,470		489,692

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 12 to the consolidated financial statements in this Form 10-Q.

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, short-term debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our financial assets and liabilities are recorded at fair value. Theyconsist primarilyofderivatives that are recorded in the Consolidated Balance Sheets in accordance with derivativeaccounting standards and marketable securities thatare held in rabbi trusts established for our deferred compensation plans and are classified as trading securities. Our qualified pension and postretirement plan assets and liabilities are recorded at fair value in the Consolidated Balance Sheets in accordance with employers' accounting and related disclosures of postretirement plans.

Fair value is the price that would be received to sell an asset or paid to transfer a liability inan orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to thevaluation technique. These inputs can be readily observable, market corroborated or generallyunobservable. We primarily apply the market approach for fair value measurements andendeavor to utilize the best available information. Accordingly, we use valuation techniques thatmaximize the use of observable inputs and minimize the use of unobservable inputs.The fairvalue of our financial assets and liabilities are subject to potentially significant volatility based onchanges in market prices, the portfolio valuation of our contracts, as well as the maturity andsettlement of those contracts, and subsequent newly originated transactions, each of which directlyaffects the estimated fair value of our financial instruments. We are able to classify fair valuebalances based on the observance of those inputs at the lowest level that is significant to the fair value measurement, in its entirety,in the fair value hierarchy levels asset forth in the fair value guidance.

For the fair value measurements of our derivatives and marketable securities, see Note 8 tothe consolidated financial statements in this Form 10-Q.For the fair value measurements of our benefit plan assets, see Note 9 tothe consolidated financial statements in our Form 10-K for the year ended October 31, 2012. For further information on our fair value methodologies, see “Fair Value Measurements” in Note 1 to the consolidatedfinancial statements in our Form 10-K for the year ended October 31, 2012. There were no significant changes to these fair value methodologies during the three months ended April 30, 2013.

Recently Issued Accounting Guidance

In December 2011, the Financial Accounting Standards Board (FASB) issued accounting guidance to improve disclosures and make information more comparable to International Financial Reporting Standards regarding the nature of an entity's rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements in tabular format to enable users of financial statements to understand the effect of those arrangements on the entity's financial position. The new disclosure requirements are effective for annual periods beginning after January 1, 2013 and interim periods therein and require retrospective application in all periods presented. We will adopt this offsetting disclosure guidance for the first quarter of our fiscal year ending October 31, 2014. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.

In November 2012, the FASB finalized the presentation disclosures on items reclassified from other comprehensive income. In February 2013, the FASB further clarified the presentation disclosures. This disclosure guidance, which we adopted this quarter, is effective for interim and annual periods beginning after December 15, 2012. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.

XML

Financial Instruments & Related Fair Value (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Apr. 30, 2013 MMBTU	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012	Oct. 31, 2012 MMBTU
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives Held For Distribution Operations	$ 4,091,000		$ 4,091,000		$ 3,153,000
Total trading (fair value)	2,986,000		2,986,000		2,288,000
Total Recurring Fair Value Assets	7,077,000		7,077,000		5,441,000
Long Term Debt Fair Value	1,165,585,000		1,165,585,000		1,163,227,000
Long Term Debt Carrying Value	975,000,000		975,000,000		975,000,000
Gas Options Total Coverage	14,900,000				35,800,000
Amount Of Loss Deferred Under PGA Procedures	1,816,000	2,365,000	4,291,000	5,288,000
Percentage Of Annual Gas Costs Approved For Recovery Under TIP	1.00%
Fair Value Measurement Transfers Between Levels Activity	no transfers between any level				no transfers between any level
Derivative [Line Items]
Gas Purchase Options Current Assets	4,091,000		4,091,000		3,153,000
Concentration Risk [Line Items]
Concentration Risk, Benchmark Description	“Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets
Concentration Risk, Customer	We are exposed to credit risk as a result of transactions for the purchase and sale of products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base. We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with (or are associated with) energy producers, utility companies, off-system municipalities and natural gas marketers.
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration Risk Amount	11,300,000		11,300,000
Accounts Receivable [Member] | Credit Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	8.00%
Money markets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	335,000		335,000		243,000
Mutual funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	2,651,000		2,651,000		2,045,000
Quoted Prices In Active Markets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives Held For Distribution Operations	4,091,000		4,091,000		3,153,000
Total Recurring Fair Value Assets	7,077,000		7,077,000		5,441,000
Quoted Prices In Active Markets [Member] | Money markets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	335,000		335,000		243,000
Quoted Prices In Active Markets [Member] | Mutual funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	2,651,000		2,651,000		2,045,000
Significant Other Observable Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives Held For Distribution Operations	0		0		0
Total Recurring Fair Value Assets	0		0		0
Significant Other Observable Inputs [Member] | Money markets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	0		0		0
Significant Other Observable Inputs [Member] | Mutual funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	0		0		0
Significant Unobservable Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives Held For Distribution Operations	0		0		0
Total Recurring Fair Value Assets	0		0		0
Significant Unobservable Inputs [Member] | Money markets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	0		0		0
Significant Unobservable Inputs [Member] | Mutual funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total trading (fair value)	$ 0		$ 0		$ 0

XML

Marketable Securities (Tables)

3 Months Ended

Apr. 30, 2013

Marketable Securities [Abstract]

Marketable Securities Table

The composition of these securities as of April 30, 2013and October 31, 2012is as follows.

	April 30, 2013				October 31, 2012
			Fair				Fair
In thousands	Cost		Value		Cost		Value
Current trading securities:
Money markets	$	-	$	-	$	-	$	-
Mutual funds		134		180		134		157
Total current trading securities		134		180		134		157
Noncurrent trading securities:
Money markets		335		335		243		243
Mutual funds		2,045		2,471		1,668		1,888
Total noncurrent trading securities		2,380		2,806		1,911		2,131
Total trading securities	$	2,514	$	2,986	$	2,045	$	2,288

XML

Equity Method Investments (Tables)

3 Months Ended

Apr. 30, 2013

Equity Method Investments Details [Abstract]

Schedule of Equity Method Investments [Table Text Block]

For each period of thethreemonths and six months ended April 30, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Transportation costs	$	2,155	$	1,012	$	4,294	$	2,047
		April 30,		October 31,
		2013		2012
Trade accounts payable	$	730	$	855

For each period of the threemonthsand six months ended April 30, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Gas storage costs	$	2,730	$	2,464	$	5,516	$	4,983
		April 30,		October 31,
		2013		2012
Trade accounts payable	$	919	$	914

For each period of the threemonthsand six months ended April 30, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owedus as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Operating revenues	$	592	$	(26)	$	583	$	(139)
		April 30,		October 31,
		2013		2012
Trade accounts receivable	$	579	$	473

For each period of the threemonths and six months ended April 30, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Gas storage costs	$	2,425	$	2,425	$	4,851	$	4,851
		April 30,		October 31,
		2013		2012
Trade accounts payable	$	808	$	808

XML

Earnings Per Share (Details) (USD $)	3 Months Ended		6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012
Earnings Per Share Reconciliation Of Basic And Diluted
Net Income	$ 55,790,000	$ 50,192,000	$ 141,713,000	$ 126,419,000
Average Shares Of Common Stock Outstanding For Basic Earnings Per Share	75,463,000	71,731,000	73,884,000	71,931,000
Contingently Issuable Shares Under Incentive Compensation Plans	314,000	295,000	333,000	295,000
Contingently Issuable Shares Under Forward Sale Agreements	127,000	0	84,000	0
Average Shares Of Dilutive Stock	75,904,000	72,026,000	74,301,000	72,226,000
Earnings Per Share Basic	$ 0.74	$ 0.70	$ 1.92	$ 1.76
Earnings Per Share Diluted	$ 0.74	$ 0.70	$ 1.91	$ 1.75

XML

Equity Method Investments (Details) (USD $)	6 Months Ended		3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended			3 Months Ended	6 Months Ended	24 Months Ended
	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013 Cardinal Pipeline Company [Member]	Apr. 30, 2012 Cardinal Pipeline Company [Member]	Apr. 30, 2013 Cardinal Pipeline Company [Member]	Apr. 30, 2012 Cardinal Pipeline Company [Member]	Oct. 31, 2012 Cardinal Pipeline Company [Member]	Apr. 30, 2013 Pine Needle Company [Member]	Apr. 30, 2012 Pine Needle Company [Member]	Apr. 30, 2013 Pine Needle Company [Member]	Apr. 30, 2012 Pine Needle Company [Member]	Oct. 31, 2012 Pine Needle Company [Member]	Apr. 30, 2013 South Star Energy Services [Member]	Apr. 30, 2012 South Star Energy Services [Member]	Apr. 30, 2013 South Star Energy Services [Member]	Apr. 30, 2012 South Star Energy Services [Member]	Oct. 31, 2012 South Star Energy Services [Member]	Apr. 30, 2013 Piedmont Hardy Storage [Member]	Apr. 30, 2012 Piedmont Hardy Storage [Member]	Apr. 30, 2013 Piedmont Hardy Storage [Member]	Apr. 30, 2012 Piedmont Hardy Storage [Member]	Oct. 31, 2012 Piedmont Hardy Storage [Member]	Apr. 30, 2013 Constitution Pipeline Company [Member]	Apr. 30, 2013 Constitution Pipeline Company [Member]	Oct. 31, 2015 Constitution Pipeline Company [Member]
Schedule Of Equity Method Investments [Line Items]
Equity Method Investment Ownership Percentage			21.49%		21.49%			40.00%		40.00%			15.00%		15.00%			50.00%		50.00%			24.00%	24.00%
Pipeline Subscription Capacity Percentage																							100.00%
Related Party Transaction Expenses From Transactions With Related Party			$ 2,155,000	$ 1,012,000	$ 4,294,000	$ 2,047,000		$ 2,730,000	$ 2,464,000	$ 5,516,000	$ 4,983,000							$ 2,425,000	$ 2,425,000	$ 4,851,000	$ 4,851,000
Due To Related Parties Current			730,000		730,000		855,000	919,000		919,000		914,000						808,000		808,000		808,000
Due From Related Parties Current													579,000		579,000		473,000
Revenue from Related Parties													592,000	(26,000)	583,000	(139,000)
Contributions to equity method investments	8,748,000	3,356,000																					1,200,000	8,700,000
Estimated Piedmont Contributions To Pipeline Project																							163,000,000	163,000,000
Term Pipeline Subscription Agreements																							15 years	15 years
Approximate Pipeline Length																							120	120
Estimated Pipeline Development And Construction Costs																							$ 680,000,000	$ 680,000,000
Funding Percentage of Total Estimated Piedmont Contributions																									90.00%
Pipeline Target In Service Date																							March 2015
Number of Producer Shippers With Negotiated Rate Structure																							2	2

XML

Consolidated Balance Sheets (Unaudited) (Parentheticals) (USD $)	Apr. 30, 2013	Oct. 31, 2012
Consolidated Balance Sheets (Unaudited)
Other Physical Property accumulated depreciation	$ 860,000	$ 843,000
Allowance for doubtful accounts	$ 4,427,000	$ 1,579,000
Cumulative preferred stock no par value	$ 0	$ 0
Cumulative preferred stock shares authorized	175,000	175,000
Common stock no par value	$ 0	$ 0
Common stock shares authorized	200,000,000	200,000,000
Common stock shares outstanding	75,720,000	72,250,000

XML

Stockholders' Equity (Disclosure)

3 Months Ended

Apr. 30, 2013

Stockholders' Equity [Abstract]

Stockholders' Equity [Text Block]

6.Stockholders' Equity

Capital Stock

Changes in common stock for the six months ended April 30, 2013 are as follows.

In thousands	Shares	Amount
Balance, October 31, 2012	72,250	$	442,461
Issued to participants in the Employee Stock Purchase Plan (ESPP)	16		505
Issued to the Dividend Reinvestment and Stock Purchase Plan	360		11,136
Issued to participants in the Incentive Compensation Plan (ICP)	94		2,999
Issuance of common stock through public share offering, net of underwriting fees	3,000		92,640
Costs from issuance of common stock	-		(358)
Balance, April 30, 2013	75,720	$	549,383

On January 29, 2013, we entered into an underwriting agreementunder our open combined debt and equity shelf registration statement to sell up to 4.6 million shares of our common stockas follows.

• Direct shares – 3 million shares were issued by us and delivered directly to the underwriters with settlement on February 4, 2013. We received $92.6 million from the underwriters and recorded this amount in “Stockholders' equity” as an addition to “Common Stock” in the Consolidated Balance Sheets. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share. The net proceeds from this sale of our common stock were used to repay outstanding short-term, unsecured notes under our CP program.
• Forward shares – 1 million shares were borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013. Under this initial forward sale agreement (FSA) that we executed with the forward counterparty on January 29, 2013, we agreed to sell 1 million shares to the forward counterparty at the same price as the direct shares to be settled no later than December 15, 2013. Under the terms of this FSA, at our election, we may physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreement. We expect to settle by delivering shares. If we physically settle by issuing 1 million shares of our common stock to the forward counterparty, the forward counterparty will, at settlement, pay us the proceeds of $30.88 per share less certain adjustments from its sale of the borrowed shares to the underwriters.
• Additional shares – Up to .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock at the net price described above of $30.88 per share with settlement on February 22, 2013. We elected to place the .6 million shares under an additional FSA having substantially similar terms as the original FSA, including settlement options at our election as described above. In connection with the additional FSA, the .6 million shares were borrowed from third parties and sold to the underwriters by the forward counterparty. We expect to settle by delivering shares. Under the terms of the additional FSA, to the extent that the transaction is physically settled, we will be required to issue and deliver an equivalent number of shares of our common stock to the forward counterparty at the then applicable forward sale price, which will be the net price described above of $30.88 per share less certain adjustments.

In accordance with ASC 815-40, Derivatives and Hedging- Contracts in Entity's Own Equity, we have classified the FSAs as equity transactions because the forward sale transactions are indexed to our own stock and physical settlement is within our control. As a result of this classification, no amounts will be recorded in the consolidated financial statements until settlement of each FSA.

Upon physical settlement of the FSAs, delivery of our shares will result in dilution to our EPS at the date of the settlement. In quarters prior to the settlement date,any dilutive effect of the FSAs on our EPS could occur during periods when the average market price per share of our common stock is above the per share adjusted forward sale price described above. See Note 3 to the consolidated financial statements in this Form 10-Q for the dilutive effect of the FSAs on our EPS at April 30, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

If we had settled the FSAs by delivery of 1.6 million shares of our common stock to the forward counterparty at April 30, 2013, we would have received net proceeds of approximately $48.8 million based on the net settlement price of $30.88 per share described above less certain adjustments. Upon settlement, the net proceeds from these FSA transactions will be used to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

Other Comprehensive Income (Loss)

Our other comprehensive income (loss) (OCIL) is a part of our accumulated OCIL and is comprised of hedging activities from our equity method investments. For further information on these hedging activities by our equity method investments, see Note 12to the consolidated financial statements in this Form 10-Q. Changes of each component ofaccumulated OCILare presented below for the three months and sixmonths ended April 30, 2013.

	Changes in Accumulated OCIL(1)
	Three		Six
In thousands	Months		Months
Accumulated OCIL beginning balance, net of tax	$	(463)	$	(305)
OCIL before reclassifications, net of tax		238		59
Amounts reclassified from accumulated OCIL, net of tax		76		97
Total current period activity, net of tax		314		156
Accumulated OCIL ending balance, net of tax	$	(149)	$	(149)
(1) Amounts in parentheses indicate debits to accumulated OCIL.

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the three months and six months ended April 30, 2013.

	Reclassifications Out of
	Accumulated OCIL (1)
	Three		Six		Affected Line Items on Statement
In thousands	Months		Months		of Comprehensive Income
Hedging activities of equity method investments	$	(125)	$	(160)	Income from equity method investments
Income tax expense		49		63	Income taxes
Total reclassification for the period, net of tax	$	(76)	$	(97)
(1) Amounts in parentheses indicate credits to accumulated OCIL.

XML

Consolidated Statements of Comprehensive Income (Unaudited) (Parentheticals) (USD $)	3 Months Ended		6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012
Consolidated Statements of Comprehensive Income (Unaudited)
Unrealized Gain (Loss) On Derivatives From Equity Method Investments Arising During Period Tax	$ 152,000	$ (267,000)	$ 38,000	$ (545,000)
Reclassification Adjustment Of Realized Gain (Loss) From Hedging Activities Of Equity Method Investments Included In Net Income Tax	$ 49,000	$ (7,000)	$ 63,000	$ 265,000

XML

Consolidated Balance Sheets (Unaudited) (USD $)	Apr. 30, 2013	Oct. 31, 2012
Utility Plant
Utility plant in service	$ 3,834,061,000	$ 3,746,178,000
Less accumulated depreciation	1,053,073,000	1,036,814,000
Utility plant in service, net	2,780,988,000	2,709,364,000
Construction work in progress	579,035,000	388,979,000
Plant held for future use	6,743,000	6,743,000
Total utility plant, net	3,366,766,000	3,105,086,000
Other Physical Property at cost, net	399,000	415,000
Current Assets
Cash and cash equivalents	14,901,000	1,959,000
Trade accounts receivable, net	142,721,000	56,700,000
Income taxes receivable	29,972,000	31,606,000
Other receivables	2,086,000	2,104,000
Unbilled utility revenues	20,397,000	24,012,000
Gas in storage	48,557,000	72,661,000
Materials, supplies and merchandise	867,000	934,000
Gas purchase derivative assets, at fair value	4,091,000	3,153,000
Amounts due from customers	29,858,000	81,626,000
Prepayments	13,096,000	30,600,000
Other current assets	292,000	287,000
Total current assets	306,838,000	305,642,000
Noncurrent Assets
Equity method investments in non-utility activities	94,766,000	87,867,000
Goodwill	48,852,000	48,852,000
Marketable securities, at fair value	2,806,000	2,131,000
Regulatory asset for postretirement benefits	118,435,000	123,290,000
Unamortized debt expense	12,975,000	13,583,000
Regulatory cost of removal asset	22,040,000	21,129,000
Other noncurrent assets	64,064,000	61,944,000
Total noncurrent assets	363,938,000	358,796,000
Total Assets	4,037,941,000	3,769,939,000
Stockholders' equity
Cumulative preferred stock - no par value	0	0
Common stock - no par value	549,383,000	442,461,000
Retained earnings	681,497,000	584,848,000
Accumulated other comprehensive loss	(149,000)	(305,000)
Total stockholders' equity	1,230,731,000	1,027,004,000
Long-term debt	875,000,000	975,000,000
Total capitalization	2,105,731,000	2,002,004,000
Current Liabilities
Current maturities of long-term debt	100,000,000	0
Short-term debt	345,000,000	365,000,000
Trade accounts payable	113,101,000	94,269,000
Other accounts payable	35,010,000	47,699,000
Income taxes accrued	995,000	0
Accrued interest	24,741,000	21,450,000
Customers' deposits	21,584,000	21,739,000
Deferred income taxes	994,000	13,542,000
General taxes accrued	9,283,000	21,504,000
Amounts due to customers	0	28,000
Other current liabilities	7,620,000	7,320,000
Total current liabilities	658,328,000	592,551,000
Noncurrent Liabilities
Deferred income taxes	699,679,000	597,211,000
Unamortized federal investment tax credits	1,536,000	1,669,000
Accumulated provision for postretirement benefits	17,872,000	37,299,000
Cost of removal obligations	508,757,000	492,963,000
Other noncurrent liabilities	46,038,000	46,242,000
Total noncurrent liabilities	1,273,882,000	1,175,384,000
Commitments and Contingencies
Total Capitalization and Liabilities	$ 4,037,941,000	$ 3,769,939,000

XML

Financial Instruments & Related Fair Value (Tables)

3 Months Ended

Apr. 30, 2013

Financial Instruments And Related Fair Value Tables [Abstract]

Assets And Liabilities Measured And Recorded At Fair Value On Recurring Basis

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, 2013 and October 31, 2012.

Recurring Fair Value Measurements as of April 30, 2013
			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable		Total
	Markets		Inputs		Inputs		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Value
Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	4,091	$	-	$	-	$	4,091
Debt and equity securities held as trading securities:
Money markets		335		-		-		335
Mutual funds		2,651		-		-		2,651
Total recurring fair value assets	$	7,077	$	-	$	-	$	7,077

Recurring Fair Value Measurements as of October 31, 2012
			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable		Total
	Markets		Inputs		Inputs		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Value
Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	3,153	$	-	$	-	$	3,153
Debt and equity securities held as trading securities:
Money markets		243		-		-		243
Mutual funds		2,045		-		-		2,045
Total recurring fair value assets	$	5,441	$	-	$	-	$	5,441

Fair Value By Balance Sheet Grouping

The carrying amount and fair value of our long-term debt,including the current portion, which is classified within Level 2, are shown below.

		Carrying
In thousands		Amount		Fair Value
As of April 30, 2013	$	975,000	$	1,165,585
As of October 31, 2012		975,000		1,163,227

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of April 30, 2013 and October 31, 2012.

Fair Value of Derivative Instruments
		Fair Value		Fair Value
In thousands		April 30, 2013		October 31, 2012
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets - Gas purchase derivative assets (June 2013-January 2014)	$	4,091
Current Assets - Gas purchase derivative assets (December 2012-October 2013)			$	3,153

Impact That Financial Instruments Would Have Had On Statement Of Operations

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on theConsolidated Statements ofComprehensive Income for the three months and sixmonths ended April 30, 2013 and 2012, absent the regulatory treatment under our approved PGA procedures.

									Location of Loss
									Recognized through
In thousands		Amount of Loss Recognized on Derivatives and Deferred Under PGA Procedures							PGA Procedures
		Three Months Ended				Six Months Ended
		April 30				April 30
		2013		2012		2013		2012
Gas purchase options	$	1,816	$	2,365	$	4,291	$	5,288	Cost of Gas

XML

Subsequent Events (Disclosure)

3 Months Ended

Apr. 30, 2013

Subsequent Events Details [Abstract]

Schedule Of Subsequent Events Text Block

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 were evaluated. For information on subsequent event disclosures related to regulatory matters, seeNote 2to the consolidated financial statements in this Form 10-Q.

XML

Employee Share Based Plans (Details) (USD $)	0 Months Ended			1 Months Ended	3 Months Ended		6 Months Ended		36 Months Ended		60 Months Ended
	Dec. 15, 2016	Dec. 15, 2015	Dec. 15, 2014	Dec. 31, 2011	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012	Oct. 31, 2014	Dec. 15, 2013	Dec. 15, 2016	Oct. 31, 2012
Employee Share Based Plans Details [Abstract]
Unvested Shares Issued To CEO				64,700
Incentive Compensation Plan Percentage Of Common Stock Vested	50%	30%	20%
Share-based Compensation Expense					$ 1,801,000	$ 501,000	$ 3,657,000	$ 2,075,000
Liability					$ 10,228,000		$ 10,228,000					$ 10,631,000
Employee Stock Purchase Plan Exercise Price As A Percentage Of Fair Market Value					95.00%
Vesting Period For Common Stock Granted Years											5 years
Number Of Performance Periods Under Icp Plans Performance Awards									3 years
Number Of Performance Periods Under Icp Plans Retention Award										3 years
Maximum Statutory Withholdings Allowed					50.00%		50.00%

XML

Stockholders' Equity (Details) (USD $)	3 Months Ended			6 Months Ended
	Apr. 30, 2013	Jan. 31, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012
Accumulated Other Comprehensive Income Loss [Abstract]
Accumulated OCIL beginning balance, net of tax	$ (463,000)	$ (305,000)		$ (305,000)
Other comprehensive income (loss) before reclassifications, net of tax	238,000			59,000
Amounts reclassified, net of tax	76,000			97,000
Total other comprehensive income (loss)	314,000		(430,000)	156,000	(440,000)
Accumulated OCIL ending balance, net of tax	(149,000)	(463,000)		(149,000)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income from equity method investments	12,437,000		11,652,000	19,592,000	17,944,000
Income taxes	(4,875,000)		(4,534,000)	(7,549,000)	(6,852,000)
Net Income	55,790,000		50,192,000	141,713,000	126,419,000
Stockholders' Equity [Abstract]
Common Stock, Shares, Outstanding, Beginning Balance		72,250,000		72,250,000
Common Stock, Value, Issued, Beginning Balance		442,461,000		442,461,000
Stock Issued During Period Shares Employee Stock Purchase Plans				16,000
Stock Issued During Period Value Employee Stock Purchase Plan				505,000
Stock Issued During Period Shares Dividend Reinvestment And Stock Purchase Plans				360,000
Stock Issued During Period Value Dividend Reinvestment And Stock Purchase Plans				11,136,000
Stock Issued During Period Shares Incentive Compensation Plan				94,000
Stock Issued During Period Value Incentive Compensation Plan				2,999,000
Issuance of commons stock shares through public share offering, net of underwriting fees				3,000,000
Issuance of common stock through public share offering, net of underwriting fees				92,640,000
Costs Of Stock Issuance Shares				0
Expenses From Issuance of Common Stock				(358,000)
Common Stock, Shares, Outstanding, Ending Balance	75,720,000			75,720,000
Common Stock, Value, Issued, Ending Balance	549,383,000			549,383,000
Common Stock Underwriting Agreement [Line Items]
Price Per Share Gross	$ 32
Maximum Number Of Shares To Be Purchased		4,600,000
Equity Issuance, Date Direct Shares	Feb. 04, 2013
Underwriter Discount	$ 1.12			$ 1.12
Net Settlement Price Per Share	$ 30.88			$ 30.88
Exercised Option Purchase Shares	600,000			600,000
Option to Purchase Settlement Date	Feb. 22, 2013			Feb. 22, 2013
Forward Contract Shares	1,600,000			1,600,000
Forward Contract Settlement Value	48,800,000			48,800,000
Maximum [Member]
Common Stock Underwriting Agreement [Line Items]
Shares Subject To Underwriters Option To Purchase		600,000
Forward Sale Agreement [Member]
Common Stock Underwriting Agreement [Line Items]
Forward Shares To Be Borrowed By Forward Counterparty		1,000,000
Forward Contract Shares	1,000,000			1,000,000
Forward Settlement Rate Price Per Share	$ 30.88
Forward Sale Agreement [Member] | Maximum [Member]
Common Stock Underwriting Agreement [Line Items]
Forward Settlement Date	Dec. 15, 2013
Additional Forward Sale Agreement [Member]
Common Stock Underwriting Agreement [Line Items]
Forward Contract Shares	600,000			600,000
Forward Settlement Rate Price Per Share	$ 30.88
Additional Forward Sale Agreement [Member] | Maximum [Member]
Common Stock Underwriting Agreement [Line Items]
Forward Settlement Date	Dec. 15, 2013
Reclassification Out Of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income from equity method investments	(125,000)			(160,000)
Income taxes	49,000			63,000
Net Income	$ (76,000)			$ (97,000)

XML

Summary Of Significant Accounting Policies (Details) (USD $)	Apr. 30, 2013	Oct. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
Regulatory Assets	$ 239,106,000	$ 293,104,000
Regulatory Liabilities	$ 504,470,000	$ 489,692,000

XML

Regulatory Matters (Details) (Tennessee Regulatory Authority [Member], USD $)	Apr. 30, 2013
Tennessee Regulatory Authority [Member]
Schedule Of Regulatory Matters [Line Items]
Request Transfer Plant Held For Future Use To Deferred Regulatory Asset	$ 6,700,000

XML

Short Term Debt (Disclosure)

3 Months Ended

Apr. 30, 2013

Short Term Debt Disclosure [Abstract]

Short Term Debt Text Block

5. Short-Term Debt Instruments

We have a $650 million five-year revolving syndicated credit facility that expires on October 1, 2017. The credit facility has an option to request an expansion up to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up to $650 million. The facility provides a line of credit for letters of credit of $10 million, of which $2.1 million and $3.6 million were issued and outstanding as of April 30, 2013 and October 31, 2012, respectively. 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 London Interbank Offered Rate (LIBOR) plus from 75 to 125 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the period.

We have a $650 million unsecured commercial paper (CP) programthat is backstopped by therevolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance and bear interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million unless the option to expand the credit facility is exercised as discussed above. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt. The notes under the CP program are not registered andare being offered andissued pursuant to an exemption from registration.

As of April 30, 2013, we have $345 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets with original maturities ranging from8 to 14 days from their dates of issuance at a weighted average interest rate of .30%. As of October 31, 2012, our outstanding notes under the CP program,included in the Consolidated Balance Sheets as stated above, were $365million.

A summary of the short-term debt activity for the threemonths and six months ended April 30, 2013 is as follows.

	Credit Facility						Commercial Paper						Total Borrowings (3)
	Three			Six			Three			Six			Three			Six
In millions	Months			Months			Months			Months			Months			Months
Minimum amount outstanding during period (1)	$	-		$	-		$	315		$	315		$	315		$	315
Maximum amount outstanding during period (1)		-			10			525			555			525			555
Minimum interest rate during period (2)		-	%		1.12	%		.28	%		.28	%		.28	%		.28	%
Maximum interest rate during period		-	%		1.12	%		.37	%		.45	%		.37	%		1.12	%
Weighted average interest rate during period		-	%		1.12	%		.33	%		.36	%		.33	%		.36	%
(1) During December 2012, we were borrowing under both the credit facility and CP program for a portion of the month.
(2) This is the minimum rate when we were borrowing under the credit facility and/or CP program.
(3) The minimum and maximum balances outstanding for each short-term debt instrument occurred at different times during the period; therefore, the total balances may not be indicative of actual borrowings on any one day during the period.

Our five-year revolving syndicated credit facility's financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 52% at April 30, 2013.

XML

Employee Benefit Plans (Tables)

3 Months Ended

Apr. 30, 2013

Pension Plans and Postretirement Plans Disclosure [Abstract]

Components Of Net Periodic Benefit Cost

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, 2013 and 2012 are presented below.

	Qualified Pension				Nonqualified Pension				Other Benefits
In thousands		2013		2012		2013		2012		2013		2012
Service cost	$	3,150	$	2,475	$	-	$	10	$	332	$	347
Interest cost		2,475		2,650		40		51		282		337
Expected return
on plan assets		(5,300)		(5,125)		-		-		(416)		(388)
Amortization of
transition obligation		-		-		-		-		167		167
Amortization of prior
service (credit) cost		(550)		(550)		20		20		-		-
Amortization of actuarial
loss		2,750		1,375		40		12		-		-
Total	$	2,525	$	825	$	100	$	93	$	365	$	463

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the six months ended April 30, 2013 and 2012 are presented below.

	Qualified Pension				Nonqualified Pension				Other Benefits
In thousands		2013		2012		2013		2012		2013		2012
Service cost	$	6,300	$	4,950	$	-	$	20	$	663	$	693
Interest cost		4,950		5,300		79		102		565		674
Expected return
on plan assets		(10,600)		(10,250)		-		-		(832)		(776)
Amortization of
transition obligation		-		-		-		-		334		334
Amortization of prior
service (credit) cost		(1,100)		(1,100)		40		40		-		-
Amortization of actuarial
loss		5,500		2,750		80		24		-		-
Total	$	5,050	$	1,650	$	199	$	186	$	730	$	925

Anticipated Employer Contribution To Benefit Plans

We anticipate that we will contribute the following amounts to our other plans in 2013.

In thousands
Nonqualified pension plans	$	502
OPEB plan		1,500

XML

Commitment & Contingencies (Details) (USD $)	3 Months Ended			96 Months Ended					3 Months Ended				3 Months Ended		24 Months Ended
	Apr. 30, 2013	Oct. 31, 2012	Oct. 31, 1997	Feb. 29, 2020 Tennessee Regulatory Authority [Member]	Apr. 30, 2013 Tennessee Regulatory Authority [Member]	Apr. 30, 2013 Environmental Restoration Costs [Member]	Apr. 30, 2013 Letter Of Credit [Member]	Oct. 31, 2012 Letter Of Credit [Member]	Apr. 30, 2013 Pipeline And Storage Capacity Contacts [Member] Maximum [Member]	Apr. 30, 2013 Gas Supply Contracts [Member] Maximum [Member]	Apr. 30, 2013 Telecommunications And Technology Outsourcing Contracts [Member] Maximum [Member]	Apr. 30, 2013 Hickory North Carolina Site [Member]	Apr. 30, 2013 Reidsville North Carolina Site [Member]	Sep. 30, 2012 Reidsville North Carolina Site [Member]	Jun. 30, 2012 Nashville MGP Site [Member]	Apr. 30, 2013 Nashville MGP Site [Member]	Apr. 30, 2013 Huntersville LNG Facility [Member]	Apr. 11, 2012 Huntersville LNG Facility [Member]	Apr. 30, 2013 Underground Storage Tank [Member]	Apr. 30, 2013 Manufactured Gas Plant Sites [Member]	Apr. 30, 2013 Liquified Natural Gas Facilites [Member]	Apr. 30, 2013 Huntersville LNG Groundwanter Remediation [Member]
Commitments And Contingencies Disclosure [Abstract]
Number Of Regulatory Commissions	3
MGP Sites Under Settlement			9
Site Contingency Unasserted Claims	0
MGP Sites Not Under Settlement	4
Site Contingency [Line Items]
Site Contingency Environmental Remediation Costs Recognized												$ 1,500,000	$ 600,000			$ 1,500,000	$ 4,300,000
Administrative Consent Order Fine																		40,000
Administrative Consent Order Unpaid Annual Fees																		18,000
Administrative Consent Order Investigative And Administrative Cost																		1,860
Number Of Monitoring Wells														5
Site Contingency, Accrual, Undiscounted Amount	1,800,000																		300,000	1,100,000	200,000	200,000
Duration Groundwater Remediation Monitoring													1 year		2 years
Long Term Purchase Commitment [Line Items]
Long Term Purchase Commitment Time Period									22 years	11 months	4 years
Line Of Credit Facility [Line Items]
Credit Facility Amount Outstanding							2,100,000	3,600,000
Regulatory Asset [Line Items]
Regulatory Assets	239,106,000	293,104,000				10,200,000
Schedule Of Regulatory Matters [Line Items]
Approved Recovery Unamortized Environmental Costs					$ 2,000,000
Amortization Period Recovery Deferred Environmental Costs				8 years

XML

Financial Instruments & Related Fair Value (Disclosure)

3 Months Ended

Apr. 30, 2013

Financial Instruments And Risk Management Disclosure [Abstract]

Financial Instruments And Risk Management [Text Block]

8.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 of 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, 2013 and October 31, 2012, we had long gas purchase options providing total coverage of14.9million dekatherms and 35.8 million dekatherms, respectively.  The long gas purchase options held at April 30, 2013 are for the period from June 2013 through January 2014.

       Fair Value Measurements

We use financial instruments that are not designated as hedges to mitigate commodity price risk for our customers. We also havemarketable securities that are held in rabbi trusts established for certain of our deferred compensation plans.In developing our fair value measurements of these financial instruments, we utilize market data or assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the entity transacts. We classify fair value balances based on the observance of those inputs into the fair value hierarchy levels as set forth in the fair value accounting guidance and fully described in “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2012.

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, 2013 and October 31, 2012.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, 2013 and 2012.

Recurring Fair Value Measurements as of April 30, 2013
			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable		Total
	Markets		Inputs		Inputs		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Value
Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	4,091	$	-	$	-	$	4,091
Debt and equity securities held as trading securities:
Money markets		335		-		-		335
Mutual funds		2,651		-		-		2,651
Total recurring fair value assets	$	7,077	$	-	$	-	$	7,077

Recurring Fair Value Measurements as of October 31, 2012
			Significant
	Quoted Prices		Other		Significant
	in Active		Observable		Unobservable		Total
	Markets		Inputs		Inputs		Carrying
In thousands	(Level 1)		(Level 2)		(Level 3)		Value
Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	3,153	$	-	$	-	$	3,153
Debt and equity securities held as trading securities:
Money markets		243		-		-		243
Mutual funds		2,045		-		-		2,045
Total recurring fair value assets	$	5,441	$	-	$	-	$	5,441

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 gasprices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through ourPGA 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 to customers” in “Current Liabilities” or “Amounts due from customers”in “Current Assets” in theConsolidated Balance Sheets. These derivative instrumentsare 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 rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in “Noncurrent Assets” in the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual fundswhich 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 benchmark 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, which is classified within Level 2, are shown below.

		Carrying
In thousands		Amount		Fair Value
As of April 30, 2013	$	975,000	$	1,165,585
As of October 31, 2012		975,000		1,163,227

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 designated 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, 2013 and October 31, 2012.

Fair Value of Derivative Instruments
		Fair Value		Fair Value
In thousands		April 30, 2013		October 31, 2012
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets - Gas purchase derivative assets (June 2013-January 2014)	$	4,091
Current Assets - Gas purchase derivative assets (December 2012-October 2013)			$	3,153

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide some level of protection against significant price increases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially deferred as amounts due to/from customers in the Consolidated Balance Sheets and recognized in the Consolidated Statements of Comprehensive Income as a component of cost of gas when the related costs are recovered through our rates.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on theConsolidated Statements ofComprehensive Income for the three months and sixmonths ended April 30, 2013 and 2012, absent the regulatory treatment under our approved PGA procedures.

									Location of Loss
									Recognized through
In thousands		Amount of Loss Recognized on Derivatives and Deferred Under PGA Procedures							PGA Procedures
		Three Months Ended				Six Months Ended
		April 30				April 30
		2013		2012		2013		2012
Gas purchase options	$	1,816	$	2,365	$	4,291	$	5,288	Cost of Gas

In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Credit and Counterparty Risk

We are exposed to credit risk as a result of transactions for the purchase and sale of products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk.Credit risk associated with trade accounts receivable for the natural gas distribution segment is mitigated by the large number of individual customers and diversity in our customer base.

We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with (or are associated with) energy producers, utility companies, off-system municipalitiesand natural gas marketers. The amount included in “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets attributable to these entities amounted to $11.3 million, or approximately 8% of our gross trade accounts receivable at April 30, 2013.Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where counterparties do not have investment grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty's credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of April 30, 2013, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable is adequate for our credit loss exposure.

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 anEnergy Price Risk Management Committee that monitors compliance with our hedging programs, policies and procedures.

XML

Long Term Debt (Disclosure)

3 Months Ended

Apr. 30, 2013

Long Term Debt Details Abstract

Long Term Debt Text Block

4. Long-Term Debt Instruments

We have an open combined debt and equity shelf registration statement filed with the SEC in July 2011 that is available for future useuntil its expiration date of July 6, 2014. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for or investments in our subsidiaries, and for repurchases of shares of our common stock. On January 29, 2013, we entered into an underwriting agreement to sell shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements in this Form 10-Q.

XML

Consolidated Statements of Stockholders' Equity (Unaudited) (USD $)	Total	Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Stockholders' Equity, beginning balance at Oct. 31, 2011	$ 996,923,000	$ 446,791,000	$ 550,584,000	$ (452,000)
Common Stock, Shares, Outstanding, Beginning Balance at Oct. 31, 2011		72,318,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	126,419,000		126,419,000
Other Comprehensive Income (Loss)	(440,000)			(440,000)
Common Stock Issued	10,877,000	10,877,000
Common Stock Repurchased	(26,528,000)	(26,528,000)
Tax Benefit from Dividends Paid on ESOP Shares	54,000		54,000
Dividends Declared	(42,494,000)		(42,494,000)
Common Stock Issued (Shares)		361,000
Common Stock Repurchased (Shares)		(800,000)
Stockholders' Equity, ending balance at Apr. 30, 2012	1,064,811,000	431,140,000	634,563,000	(892,000)
Common Stock, Shares, Outstanding, Ending Balance at Apr. 30, 2012		71,879,000
Stockholders' Equity, beginning balance at Oct. 31, 2012	1,027,004,000	442,461,000	584,848,000	(305,000)
Common Stock, Shares, Outstanding, Beginning Balance at Oct. 31, 2012	72,250,000	72,250,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	141,713,000		141,713,000
Other Comprehensive Income (Loss)	156,000			156,000
Common Stock Issued	107,280,000	107,280,000
Expenses From Issuance of Common Stock	(358,000)	(358,000)
Tax Benefit from Dividends Paid on ESOP Shares	59,000		59,000
Dividends Declared	(45,123,000)		(45,123,000)
Common Stock Issued (Shares)		3,470,000
Stockholders' Equity, ending balance at Apr. 30, 2013	$ 1,230,731,000	$ 549,383,000	$ 681,497,000	$ (149,000)
Common Stock, Shares, Outstanding, Ending Balance at Apr. 30, 2013	75,720,000	75,720,000

XML

Business Segments (Details) (USD $)	3 Months Ended		6 Months Ended
	Apr. 30, 2013	Apr. 30, 2012	Apr. 30, 2013	Apr. 30, 2012
Segment Reporting Information [Line Items]
Revenues From External Customers	$ 399,411,000	$ 308,432,000	$ 915,286,000	$ 780,272,000
Margin	183,856,000	171,951,000	415,480,000	392,187,000
Operations And Maintenance Expenses	65,103,000	60,532,000	121,039,000	118,952,000
Income From Equity Method Investments	12,437,000	11,652,000	19,592,000	17,944,000
Operating Income (Loss) Before Income Taxes	82,814,000	76,846,000	222,191,000	203,780,000
Income Before Income Taxes	92,045,000	82,816,000	233,941,000	208,582,000
Number Of Operating Segments	2
Regulated Operation [Member]
Segment Reporting Information [Line Items]
Revenues From External Customers	399,411,000	308,432,000	915,286,000	780,272,000
Margin	183,856,000	171,951,000	415,480,000	392,187,000
Operations And Maintenance Expenses	65,037,000	60,511,000	120,919,000	118,908,000
Income From Equity Method Investments	0	0	0	0
Operating Income (Loss) Before Income Taxes	82,884,000	76,872,000	222,396,000	203,912,000
Income Before Income Taxes	79,678,000	71,189,000	214,555,000	190,770,000
Non Utility Activities [Member]
Segment Reporting Information [Line Items]
Revenues From External Customers	0	0	0	0
Margin	0	0	0	0
Operations And Maintenance Expenses	66,000	21,000	120,000	44,000
Income From Equity Method Investments	12,437,000	11,652,000	19,592,000	17,944,000
Operating Income (Loss) Before Income Taxes	(70,000)	(26,000)	(205,000)	(132,000)
Income Before Income Taxes	$ 12,367,000	$ 11,627,000	$ 19,386,000	$ 17,812,000

XML

Variable Interest Entities (Tables)

3 Months Ended

Apr. 30, 2013

Variable Interest Entities Loss Exposure [Abstract]

Schedule Of Variable Interest Entities Investment Balances [Table Text Block]

As of April 30, 2013 and October 31, 2012,our investment balances are as follows.

		April 30,		October 31,
In thousands		2013		2012
Cardinal	$	18,270	$	17,969
Pine Needle		18,585		19,239
SouthStar		15,467		18,118
Hardy Storage		33,465		32,541
Constitution		8,979		-
Total equity method investments in non-utility activities	$	94,766	$	87,867

XML

Employee Share Based Plans (Disclosure)

3 Months Ended

Apr. 30, 2013

Employee Share Based Plans Details [Abstract]

Disclosure Of Compensation Related Costs Share Based Payments Text Block

11.Employee Share-Based Plans

Underour shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-yearincentive 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, 2013 and 2012, we recorded compensation expense, and as of April 30, 2013 and October 31, 2012, 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 stock unit award under theICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award will vest for 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. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of all or a portion of a participant's units. For the three monthsand six months ended April 30, 2013 and 2012, we recorded compensation expense, and as of April 30, 2013 and October 31, 2012, we have accrued a liability for this award 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 ICP, 64,700 unvested retention stock units were granted toour President and Chief Executive Officer in December 2011. During the five-year vesting period, any dividend equivalentswill accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units willvest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation,over a five-year period only if he is an employee on each vesting date.In accordance with the vesting schedule, 20% of the units vest on December 15, 2014, 30%of the units vest on December 15, 2015 and 50% of the unitsvest on December 15, 2016.For the three months and six months ended April 30, 2013, we recorded compensation expense, and as of April 30, 2013, we have accrued a liability for this award 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.

At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been immaterial. We present these net shares issued in theConsolidated Statements of Stockholders' Equity.

The compensation expense related to the incentive compensation plans for the threemonths and six months ended April 30, 2013 and 2012, and the amounts recorded as liabilities as of April 30, 2013 and October 31, 2012 are presented below.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Compensation expense	$	1,801	$	501	$	3,657	$	2,075
		April 30,		October 31,
		2013		2012
Liability	$	10,228	$	10,631

On a quarterly basis, we issue shares of common stock under the ESPPand 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.

XML

Marketable Securities (Disclosure)

3 Months Ended

Apr. 30, 2013

Marketable Securities [Abstract]

Marketable Securities Disclosure

7.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 rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 10 to the consolidated financial statements in this Form 10-Q.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value in the Consolidated Balance Sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their investments at any time. 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 is included in “Other current assets” in “Current Assets” in the Consolidated Balance Sheets.

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.The composition of these securities as of April 30, 2013and October 31, 2012is as follows.

	April 30, 2013				October 31, 2012
			Fair				Fair
In thousands	Cost		Value		Cost		Value
Current trading securities:
Money markets	$	-	$	-	$	-	$	-
Mutual funds		134		180		134		157
Total current trading securities		134		180		134		157
Noncurrent trading securities:
Money markets		335		335		243		243
Mutual funds		2,045		2,471		1,668		1,888
Total noncurrent trading securities		2,380		2,806		1,911		2,131
Total trading securities	$	2,514	$	2,986	$	2,045	$	2,288

XML

Business Segments (Disclosure)

3 Months Ended

Apr. 30, 2013

Business Segments Details [Abstract]

Segment Reporting Disclosure Text Block

14.Business Segments

We have two reportable business segments, regulated utility and non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated utility segment is the gas distribution business, where we include the operations of merchandising and its related service work and home warranty programs, with activities 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 ofComprehensive Income. Operations of the non-utility activities segment are included in theConsolidated Statements of Comprehensive Incomein “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, 2012.

Operations by segment for the threemonths and six months ended April 30, 2013 and 2012 are presented below.

		Regulated				Non-utility
In thousands		Utility				Activities				Total
		2013		2012		2013		2012		2013		2012
Three Months
Revenues from external customers	$	399,411	$	308,432	$	-	$	-	$	399,411	$	308,432
Margin		183,856		171,951		-		-		183,856		171,951
Operations and maintenance expenses		65,037		60,511		66		21		65,103		60,532
Income from equity method investments		-		-		12,437		11,652		12,437		11,652
Operating income (loss) before income taxes		82,884		76,872		(70)		(26)		82,814		76,846
Income before income taxes		79,678		71,189		12,367		11,627		92,045		82,816
Six Months
Revenues from external customers	$	915,286	$	780,272	$	-	$	-	$	915,286	$	780,272
Margin		415,480		392,187		-		-		415,480		392,187
Operations and maintenance expenses		120,919		118,908		120		44		121,039		118,952
Income from equity method investments		-		-		19,592		17,944		19,592		17,944
Operating income (loss) before income taxes		222,396		203,912		(205)		(132)		222,191		203,780
Income before income taxes		214,555		190,770		19,386		17,812		233,941		208,582

Reconciliations to the Consolidated Statements of Comprehensive Income for the three months and sixmonths ended April 30, 2013and 2012 are presented below.

In thousands		Three Months				Six Months
		2013		2012		2013		2012
Operating Income:
Segment operating income before
income taxes	$	82,814	$	76,846	$	222,191	$	203,780
Utility income taxes		(31,380)		(28,090)		(84,679)		(75,311)
Non-utility activities before income taxes		70		26		205		132
Operating income	$	51,504	$	48,782	$	137,717	$	128,601

Net Income:
Income before income taxes for
reportable segments	$	92,045	$	82,816	$	233,941	$	208,582
Income taxes		(36,255)		(32,624)		(92,228)		(82,163)
Net income	$	55,790	$	50,192	$	141,713	$	126,419

XML

Equity Method Investments (Disclosure)

3 Months Ended

Apr. 30, 2013

Equity Method Investments Details [Abstract]

Equity Method Investments Disclosure Text Block

12.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 “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)”in the Consolidated Statements ofComprehensive Income.

Cardinal Pipeline Company, L.L.C.

We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. Cardinal owns and operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC.

Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders' equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreementsis combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal's long-term debt is nonrecourse to the members.

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Consolidated Statements of Comprehensive Income.For each period of thethreemonths and six months ended April 30, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Transportation costs	$	2,155	$	1,012	$	4,294	$	2,047
		April 30,		October 31,
		2013		2012
Trade accounts payable	$	730	$	855

Pine Needle LNG Company, L.L.C.

We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), aNorth Carolina limited liability company. Pine Needle owns aninterstateLNG storage facility in North Carolina and is regulated by the FERC.

Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders' equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreementsis combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Pine Needle's long-term debt is nonrecourse to the members.

We have related party transactions as a customer of Pine Needle, and we record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each period of the threemonthsand six months ended April 30, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Gas storage costs	$	2,730	$	2,464	$	5,516	$	4,983
		April 30,		October 31,
		2013		2012
Trade accounts payable	$	919	$	914

SouthStar Energy Services LLC

We own 15% of the membership interestsin SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States, as well as Ohio, New York and Maryland,with most of its business being conducted in the unregulated retail gas market in Georgia. We account for our investment in SouthStar using the equity method, as we haveboard representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings. These financial contracts, in the form of futures, options and swaps, are considered to be derivatives and fair value is based on selected market indices. Our share of movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders' equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStarin “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For each period of the threemonthsand six months ended April 30, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owedus as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Operating revenues	$	592	$	(26)	$	583	$	(139)
		April 30,		October 31,
		2013		2012
Trade accounts receivable	$	579	$	473

Hardy Storage Company, LLC

We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. Hardy Storage owns and operates an underground interstate natural gas storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC.

We have related party transactions as a customer of Hardy Storage and record the storage costs charged by Hardy Storagein “Cost of Gas” in the Consolidated Statements of Comprehensive Income.For each period of the threemonths and six months ended April 30, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of April 30, 2013 and October 31, 2012 are as follows.

		Three Months				Six Months
In thousands		2013		2012		2013		2012
Gas storage costs	$	2,425	$	2,425	$	4,851	$	4,851
		April 30,		October 31,
		2013		2012
Trade accounts payable	$	808	$	808

Constitution Pipeline Company, LLC

We own 24% of the membership interestsin Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The purpose of the joint venture is to construct and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting natural gas gathering systems in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately $680 million. As of April 30, 2013, our current quarter and fiscal year contributions were$1.2 million and $8.7million, respectively, and we expect our total contributions will be an estimated $163 million through 2015 with approximately 90% of that funding to occur during our fiscal 2014 and 2015 years. The target in-service date of the project is March 2015. The capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.

XML

Document And Entity Information	3 Months Ended
	Apr. 30, 2013	Jun. 04, 2013
Document And Entity Information [Abstract]
Entity Registrant Name	PIEDMONT NATURAL GAS CO INC
Entity Central Index Key	0000078460
Document Type	10-Q
Document Period End Date	Apr. 30, 2013
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2013
Amendment Flag	false
Current Fiscal Year End Date	--10-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		75,746,114

XML

Variable Interest Entities (Disclosure)

3 Months Ended

Apr. 30, 2013

Variable Interest Entities [Abstract]

Aggregation Of Variable Interest Entities Disclosures [Text Block]

13. Variable Interest Entities

Under accounting guidance, a variable interest entity (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, 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, 2013, 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, as discussed in Note 12 to the consolidated financial statements in this Form 10-Q. 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. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial statements in this Form 10-Q. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of April 30, 2013 and October 31, 2012,our investment balances are as follows.

		April 30,		October 31,
In thousands		2013		2012
Cardinal	$	18,270	$	17,969
Pine Needle		18,585		19,239
SouthStar		15,467		18,118
Hardy Storage		33,465		32,541
Constitution		8,979		-
Total equity method investments in non-utility activities	$	94,766	$	87,867

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