Piedmont Natural Gas (PNY) 10-Q 2013 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended July 31, 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 Number1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  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 filerx	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 August 30, 2013
Common Stock, no par value	75,930,485

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

July 31, 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		51
Item 4.	Controls and Procedures		52
Part II.	Other Information
Item 1.	Legal Proceedings		52
Item 1A.	Risk Factors		52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 6.	Exhibits		54
	Signatures		55

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)

	July 31, 2013		October 31, 2012
ASSETS
Utility Plant:
Utility plant in service	$	4,246,605	$	3,746,178
Less accumulated depreciation		1,072,775		1,036,814
Utility plant in service, net		3,173,830		2,709,364
Construction work in progress		329,399		388,979
Plant held for future use		6,743		6,743
Total utility plant, net		3,509,972		3,105,086
Other Physical Property, at cost (net of accumulated depreciation of $868 in 2013 and $843 in 2012)		390		415
Current Assets:
Cash and cash equivalents		4,781		1,959
Trade accounts receivable (less allowance for doubtful accounts of $2,831 in 2013 and $1,579 in 2012)		73,756		56,700
Income taxes receivable		33,652		31,606
Other receivables		2,106		2,104
Unbilled utility revenues		10,208		24,012
Inventories:
Gas in storage		68,800		72,661
Materials, supplies and merchandise		996		934
Gas purchase derivative assets, at fair value		983		3,153
Amounts due from customers		48,780		81,626
Prepayments		29,049		30,600
Other current assets		3,495		287
Total current assets		276,606		305,642
Noncurrent Assets:
Equity method investments in non-utility activities		101,791		87,867
Goodwill		48,852		48,852
Marketable securities, at fair value		2,928		2,131
Regulatory asset for postretirement benefits		115,855		123,290
Unamortized debt expense		12,803		13,583
Regulatory cost of removal asset		22,504		21,129
Other noncurrent assets		66,895		61,944
Total noncurrent assets		371,628		358,796
Total	$	4,158,596	$	3,769,939

See notes to consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)

	July 31, 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: 75,917 in 2013 and 72,250 in 2012		555,935			442,461
Retained earnings		655,751			584,848
Accumulated other comprehensive loss		(237	)		(305	)
Total stockholders’ equity		1,211,449			1,027,004
Long-term debt		875,000			975,000
Total capitalization		2,086,449			2,002,004
Current Liabilities:
Current maturities of long-term debt		100,000			-
Short-term debt		515,000			365,000
Trade accounts payable		81,431			94,269
Other accounts payable		35,074			47,699
Accrued interest		12,738			21,450
Customers’ deposits		19,900			21,739
Deferred income taxes		-			13,542
General taxes accrued		15,067			21,504
Amounts due to customers		-			28
Other current liabilities		7,430			7,320
Total current liabilities		786,640			592,551
Noncurrent Liabilities:
Deferred income taxes		679,215			597,211
Unamortized federal investment tax credits		1,469			1,669
Accumulated provision for postretirement benefits		17,840			37,299
Cost of removal obligations		516,139			492,963
Other noncurrent liabilities		70,844			46,242
Total noncurrent liabilities		1,285,507			1,175,384
Commitments and Contingencies (Note 9)
Total	$	4,158,596		$	3,769,939

See notes to consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands except per share amounts)

	Three Months Ended July 31						Nine Months Ended July 31
	2013			2012			2013			2012
Operating Revenues	$	162,943		$	161,123		$	1,078,229		$	941,395
Cost of Gas		65,943			74,663			565,749			462,748
Margin		97,000			86,460			512,480			478,647
Operating Expenses:
Operations and maintenance		62,950			59,248			183,869			178,155
Depreciation		28,599			25,532			82,168			76,980
General taxes		8,307			8,275			26,903			26,196
Utility income taxes		(3,447	)		(4,082	)		81,232			71,228
Total operating expenses		96,409			88,973			374,172			352,559
Operating Income (Loss)		591			(2,513	)		138,308			126,088
Other Income (Expense):
Income from equity method investments		3,652			3,290			23,244			21,234
Non-operating income		667			267			1,857			909
Non-operating expense		(897	)		(342	)		(2,355	)		(1,389	)
Income taxes		(603	)		(1,238	)		(8,152	)		(8,090	)
Total other income (expense)		2,819			1,977			14,594			12,664
Utility Interest Charges:
Interest on long-term debt		12,656			10,164			37,983			30,192
Allowance for borrowed funds used during construction		(7,507	)		(6,656	)		(25,758	)		(17,131	)
Other		554			569			1,257			3,885
Total utility interest charges		5,703			4,077			13,482			16,946
Net Income (Loss)		(2,293	)		(4,613	)		139,420			121,806
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($21) and $10 for the three months ended July 31, 2013 and 2012, respectively, and $17 and ($535) for the nine months ended July 31, 2013 and 2012, respectively		(36	)		18			23			(837	)
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of ($33) and $268 for the three months ended July 31, 2013 and 2012, respectively, and $30 and $533 for the nine months ended July 31, 2013 and 2012, respectively		(52	)		420			45			835
Total other comprehensive income (loss)		(88	)		438			68			(2	)
Comprehensive Income (Loss)	$	(2,381	)	$	(4,175	)	$	139,488		$	121,804
Average Shares of Common Stock:
Basic		75,774			71,936			74,521			71,933
Diluted		75,774			71,936			74,987			72,233
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.03	)	$	(0.06	)	$	1.87		$	1.69
Diluted	$	(0.03	)	$	(0.06	)	$	1.86		$	1.69
Cash Dividends Per Share of Common Stock	$	0.31		$	0.30		$	0.92		$	0.89

See notes to consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Nine Months Ended July 31
	2013			2012
Cash Flows from Operating Activities:
Net income	$	139,420		$	121,806
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		87,250			81,038
Allowance for doubtful accounts		1,252			1,094
Net gain on sale of property		(18	)		-
Income from equity method investments		(23,244	)		(21,234	)
Distributions of earnings from equity method investments		18,464			13,988
Deferred income taxes, net		65,015			105,958
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		2,170			(793	)
Receivables		(4,565	)		14,873
Inventories		3,799			19,103
Amounts due from/to customers		32,818			(27,047	)
Settlement of legal asset retirement obligations		(1,784	)		(1,156	)
Overfunded postretirement asset		-			(57	)
Regulatory asset for postretirement benefits		7,435			3,424
Other assets		(6,277	)		(16,109	)
Accounts payable		(26,551	)		(15,243	)
Provision for postretirement benefits		(19,459	)		145
Other liabilities		10,146			(13,648	)
Net cash provided by operating activities		285,871			266,142
Cash Flows from Investing Activities:
Utility capital expenditures		(443,312	)		(350,986	)
Allowance for borrowed funds used during construction		(25,758	)		(17,131	)
Contributions to and purchase of additional interest in equity method investments		(15,008	)		(3,566	)
Distributions of capital from equity method investments		5,980			10,222
Proceeds from sale of property		891			734
Investments in marketable securities		(477	)		(687	)
Other		2,198			1,911
Net cash used in investing activities		(475,486	)		(359,503	)

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Nine Months Ended July 31
	2013			2012
Cash Flows from Financing Activities:
Borrowings under credit facility	$	10,000		$	350,000
Repayments under credit facility		(10,000	)		(681,000	)
Net borrowings – commercial paper		150,000			400,000
Proceeds from issuance of long-term debt		-			100,000
Expenses related to issuance of debt		(151	)		(2,548	)
Proceeds from issuance of common stock, net of expenses		92,282			-
Issuance of common stock through dividend reinvestment and employee stock plans		18,890			16,483
Repurchases of common stock		-			(26,528	)
Dividends paid		(68,605	)		(64,068	)
Other		21			(34	)
Net cash provided by financing activities		192,437			92,305
Net Increase (Decrease) in Cash and Cash Equivalents		2,822			(1,056	)
Cash and Cash Equivalents at Beginning of Period		1,959			6,777
Cash and Cash Equivalents at End of Period	$	4,781		$	5,721
Cash Paid During the Year for:
Interest	$	48,982		$	43,075
Income Taxes:
Income taxes paid	$	5,267		$	4,215
Income taxes refunded		-			88
Income taxes, net	$	5,267		$	4,127
Noncash Investing and Financing Activities:
Accrued capital expenditures	$	44,701		$	3,384

See notes to consolidated financial statements.

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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								121,806						121,806
Other Comprehensive Loss											(2	)		(2	)
Common Stock Issued		545			16,558									16,558
Common Stock Repurchased		(800	)		(26,528	)								(26,528	)
Tax Benefit from Dividends Paid on ESOP Shares								82						82
Dividends Declared ($.89 per share)								(64,068	)					(64,068	)
Balance, July 31, 2012		72,063		$	436,821		$	608,404		$	(454	)	$	1,044,771
Balance, October 31, 2012		72,250		$	442,461		$	584,848		$	(305	)	$	1,027,004
Net Income								139,420						139,420
Other Comprehensive Income											68			68
Common Stock Issued		3,667			113,832									113,832
Expenses from Issuance of Common Stock					(358	)								(358	)
Tax Benefit from Dividends Paid on ESOP Shares								88						88
Dividends Declared ($.92 per share)								(68,605	)					(68,605	)
Balance, July 31, 2013		75,917		$	555,935		$	655,751		$	(237	)	$	1,211,449

See notes to consolidated financial statements.

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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 July 31, 2013 and October 31, 2012, the results of operations for the three months and nine months ended July 31, 2013 and 2012, and cash flows and stockholders’ equity for the nine months ended July 31, 2013 and 2012. Our business is seasonal in nature. The results of operations for the three months and nine months ended July 31, 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 nine months ended July 31, 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

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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 July 31, 2013 and October 31, 2012 are as follows.

In thousands	July 31, 2013		October 31, 2012
Regulatory assets	$	258,139	$	293,104
Regulatory liabilities		534,059		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 July 31, 2013.

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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 within those periods, 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 July 2013, the FASB issued accounting guidance on presenting an unrecognized tax benefit when net operating loss (NOL) carryforwards exist. The guidance was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2013, with early adoption permitted. The adoption of this guidance will have 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,

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• 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. A hearing has been set for the week of October 14, 2013 by the NCUC for this general rate proceeding.

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) entries and gas purchasing policies for the twelve months ended March 31, 2013. On June 28, 2013, we filed a settlement agreement with the Office of Regulatory Staff on this matter. On August 7, 2013, the PSCSC approved the settlement agreement and found that our gas purchasing policies and practices were reasonable and prudent, that we properly adhered to the gas cost recovery provisions of our tariff and relevant PSCSC orders and that we managed our hedging program in a manner consistent with PSCSC orders. The PSCSC issued its order on this matter on August 13, 2013.

In August 2013, we filed a petition with the Tennessee Regulatory Authority (TRA) seeking authority to implement an integrity management rider to recover the costs of our capital investments that are made in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment January 1, 2014 and that rates be updated annually outside of general rate cases for the return of and on these capital investments. We are waiting on a ruling from the TRA at this time.

In August 2013, we filed an annual report with the TRA reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2013 under the Tennessee Incentive Plan (TIP). We are waiting on a ruling from the TRA at this time.

In August 2013, we filed an Actual Cost Adjustment (ACA) petition with the TRA to authorize us to make an adjustment to the deferred gas cost account reporting for prior periods in the amount of a $3.7 million under collection. We are waiting on a ruling from the TRA at this time. We intend to file our ACA annual report for the twelve months ended June 30, 2013 upon resolution of this petition.

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 and forward sale agreements 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 nine months ended July 31, 2013 and 2012 is presented below.

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	Three Months						Nine Months
In thousands except per share amounts	2013			2012			2013		2012
Net Income (Loss)	$	(2,293	)	$	(4,613	)	$	139,420	$	121,806
Average shares of common stock outstanding for basic earnings per share		75,774			71,936			74,521		71,933
Contingently issuable shares under incentive compensation plans *		-			-			330		300
Contingently issuable shares under forward sale agreements **		-			-			136		-
Average shares of dilutive stock		75,774			71,936			74,987		72,233
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.03	)	$	(0.06	)	$	1.87	$	1.69
Diluted	$	(0.03	)	$	(0.06	)	$	1.86	$	1.69

* For the three months ended July 31, 2013 and 2012, the inclusion of 316 and 300 contingently issuable shares under incentive compensation plans, respectively, would have been antidilutive.

** For the three months ended July 31, 2013, the inclusion of 192 contingently issuable shares under forward sales agreements would have been antidilutive.

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, advances for or investments in our subsidiaries and for repurchases of shares of our common stock. In February 2013, we sold 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.

In July 2013, we entered into an agreement to issue $300 million of thirty-year, unsecured senior notes with an interest rate of 4.65% under the registration statement noted above. On August 1, 2013, we issued these notes, which will mature on August 1, 2043. We have the option to redeem all or part of the notes before the stated maturity prior to February 1, 2043, at a redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Comparable Treasury Issue rate as defined in the note agreement, plus 15 basis points and any accrued and unpaid interest to the date of redemption. We have the option to redeem all or part of the notes before the stated maturity on or after February 1, 2043, at 100% of the principal amount plus any accrued and unpaid interest to the date of redemption. We intend to use the net proceeds of $297.2 million from this issuance to finance capital expenditures, to repay $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term, unsecured notes under our commercial paper program and for general corporate purposes.

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 July 31, 2013, there has been no event of default giving rise to acceleration of our debt.

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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 July 31, 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.

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. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the period.

As of July 31, 2013, we have $515 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 2 to 45 days from their dates of issuance at a weighted average interest rate of .25%. 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 nine months ended July 31, 2013 is as follows.

	Credit Facility						Commercial Paper						Total Borrowings (3)
In millions	Three Months			Nine Months			Three Months			Nine Months			Three Months			Nine Months
Minimum amount outstanding during period(1)	$	-		$	-		$	330		$	315		$	330		$	315
Maximum amount outstanding during period(1)		-			10			515			555			515			555
Minimum interest rate during period(2)		-	%		1.12	%		.23	%		.23	%		.23	%		.23	%
Maximum interest rate during period		-	%		1.12	%		.30	%		.45	%		.30	%		1.12	%
Weighted average interest rate during period		-	%		1.12	%		.26	%		.33	%		.26	%		.33	%

⁽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 55% at July 31, 2013.

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6. Stockholders’ Equity

Capital Stock

Changes in common stock for the nine months ended July 31, 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)		24		760
Issued to the Dividend Reinvestment and Stock Purchase Plan		548		17,401
Issued to participants in the Incentive Compensation Plan (ICP)		95		3,031
Issuance of common stock through public share offering, net of underwriting fees		3,000		92,640
Costs from issuance of common stock		-		(358	)
Balance, July 31, 2013		75,917	$	555,935

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 with settlement of 3 million shares on February 4, 2013 at an offering price to the public of $32 per share less an underwriting discount of $1.12 per share, or $30.88 per share. We entered into forward sale agreements (FSAs) for 1 million shares on January 29, 2013 and for .6 million shares on February 22, 2013. Under the terms of the FSAs, we may physically settle in shares, cash or net share settle for all or a portion of our obligations under the agreements with both FSAs to be settled no later than December 15, 2013. We expect to settle by delivering shares. If we physically settle by issuing 1.6 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, the original offering price, less certain adjustments from its sale of the borrowed shares to the underwriters.

If we had settled the FSAs by delivery of 1.6 million shares of our common stock to the forward counterparty at July 31, 2013, we would have received net proceeds of approximately $48.1 million based on the net settlement price of $30.88 per share described above less certain adjustments. Upon settlement, we intend to use the net proceeds from these FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.

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 July 31, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.

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 in each

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component of accumulated OCIL are presented below for the three months and nine months ended July 31, 2013.

	Changes in Accumulated  OCIL(1)
In thousands	Three Months			Nine Months
Accumulated OCIL beginning balance, net of tax	$	(149	)	$	(305	)
OCIL before reclassifications, net of tax		(36	)		23
Amounts reclassified from accumulated OCIL, net of tax		(52	)		45
Total current period activity, net of tax		(88	)		68
Accumulated OCIL ending balance, net of tax	$	(237	)	$	(237	)

⁽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 nine months ended July 31, 2013.

	Reclassifications Out of Accumulated OCIL(1)						Affected Line Items on Statement of Operations and Comprehensive  Income
In thousands	Three Months			Nine Months
Hedging activities of equity method investments	$	85		$	(75	)	Income from equity method investments
Income tax expense		(33	)		30		Income taxes
Total reclassification for the period, net of tax	$	52		$	(45	)

⁽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 July 31, 2013 and October 31, 2012 is as follows.

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	July 31, 2013				October 31, 2012
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	-	$	-	$	-	$	-
Mutual funds		134		189		134		157
Total current trading securities		134		189		134		157
Noncurrent trading securities:
Money markets		337		337		243		243
Mutual funds		2,075		2,591		1,668		1,888
Total noncurrent trading securities		2,412		2,928		1,911		2,131
Total trading securities	$	2,546	$	3,117	$	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. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of July 31, 2013 and October 31, 2012, we had long gas purchase options providing total coverage of 14.7 million dekatherms and 35.8 million dekatherms, respectively. The long gas purchase options held at July 31, 2013 are for the period from September 2013 through August 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 July 31, 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 July 31, 2013 and 2012.

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Recurring Fair Value Measurements as of July 31, 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	$	983	$	-	$	-	$	983
Debt and equity securities held as trading securities:
Money markets		337		-		-		337
Mutual funds		2,780		-		-		2,780
Total recurring fair value assets	$	4,100	$	-	$	-	$	4,100

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.

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In thousands	Carrying Amount		Fair Value
As of July 31, 2013	$	975,000	$	1,092,377
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 July 31, 2013 and October 31, 2012.

Fair Value of Derivative Instruments

In thousands	Fair Value July 31,  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 (September 2013-August 2014)	$	983
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 Operations and 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 Operations and Comprehensive Income for the three months and nine months ended July 31, 2013 and 2012, absent the regulatory treatment under our approved PGA procedures.

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In thousands	Amount of Loss Recognized on Derivatives and Deferred Under  PGA Procedures								Location of Loss Recognized  through PGA Procedures
	Three Months Ended July 31				Nine Months Ended July 31
	2013		2012		2013		2012
Gas purchase options	$	829	$	1,445	$	5,120	$	6,733		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, power generation, 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 $5.3 million, or approximately 7% of our gross trade accounts receivable at July 31, 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 July 31, 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

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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 fifteen 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 three 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 Operations and 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.

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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 July 31, 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. The NCDENR is no longer requiring the groundwater remedial action plan. We will be filing land use restrictions on the property with the NCDENR in the fourth quarter of our fiscal year 2013. We have incurred $.6 million of remediation costs at the Reidsville site through July 31, 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 will be filing land use restrictions on the property with the NCDENR in the fourth quarter of our fiscal year 2013. We have incurred $1.5 million of remediation costs at this site through July 31, 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 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, which was inconclusive as to migration, and thus 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 will be required to submit additional plan(s) to remediate and/or monitor the groundwater.

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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 the fourth quarter of our fiscal year 2013 with completion anticipated for both projects by the end of fiscal 2014. We have incurred $4.6 million of remediation costs through July 31, 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 have transitioned away from owning and maintaining our own petroleum underground storage tanks (USTs) with the exception of our Charlotte, North Carolina resource center which continues to operate two USTs.

For all matters discussed above, as of July 31, 2013, our estimated undiscounted environmental liability totaled $1.6 million and consisted of $1.1 million for the MGP sites for which we retain remediation responsibility, $.1 million for the LNG facilities, $.1 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 July 31, 2013, our regulatory assets for unamortized environmental costs in our three-state territory totaled $10.1 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 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee 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 July 31, 2013 and 2012 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2013			2012			2013		2012		2013			2012
Service cost	$	2,704		$	2,230		$	-	$	10	$	332		$	347
Interest cost		2,509			2,680			39		51		282			337
Expected return on plan assets		(5,229	)		(4,967	)		-		-		(416	)		(388	)
Amortization of transition obligation		-			-			-		-		167			167
Amortization of prior service (credit) cost		(548	)		(548	)		21		20		-			-
Amortization of actuarial loss		2,901			1,724			40		12		-			-
Total	$	2,337		$	1,119		$	100	$	93	$	365		$	463

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Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2013 and 2012 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2013			2012			2013		2012		2013			2012
Service cost	$	9,004		$	7,180		$	-	$	29	$	995		$	1,040
Interest cost		7,459			7,980			118		153		848			1,011
Expected return on plan assets		(15,829	)		(15,217	)		-		-		(1,247	)		(1,163	)
Amortization of transition obligation		-			-			-		-		500			500
Amortization of prior service (credit) cost		(1,648	)		(1,648	)		61		61		-			-
Amortization of actuarial loss		8,401			4,474			120		37		-			-
Total	$	7,387		$	2,769		$	299	$	280	$	1,096		$	1,388

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. During the nine months ended July 31, 2013, we contributed $.4 million to the nonqualified pension plans. We anticipate that we will contribute the following amounts to our other plans in 2013.

In thousands
Nonqualified pension plans	$	144
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 nine months ended July 31, 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 July 31, 2013, we have a liability of $3.3 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.

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 nine months ended July 31, 2013 and 2012, we recorded compensation expense, and as of July 31, 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.

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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 nine months ended July 31, 2013 and 2012, we recorded compensation expense, and as of July 31, 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 nine months ended July 31, 2013, we recorded compensation expense, and as of July 31, 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.

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 nine months ended July 31, 2013 and 2012, and the amounts recorded as liabilities as of July 31, 2013 and October 31, 2012 are presented below.

	Three Months				Nine Months
In thousands	2013		2012		2013		2012
Compensation expense	$	1,848	$	2,119	$	5,505	$	4,195
	July 31, 2013		October 31, 2012
Liability	$	12,076	$	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.

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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 Operations and 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 Operations and 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 Operations and Comprehensive Income. For each period of the three months and nine months ended July 31, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of July 31, 2013 and October 31, 2012 are as follows.

	Three Months				Nine Months
In thousands	2013		2012		2013		2012
Transportation costs	$	2,240	$	2,030	$	6,534	$	4,077

	July 31, 2013		October 31, 2012
Trade accounts payable	$	755	$	855

Pine Needle LNG Company, L.L.C.

Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company, owns an interstate LNG storage facility in North Carolina and is regulated by the FERC. In June 2013, we entered into an agreement with Hess Corporation (Hess) to acquire their 5% membership interest in Pine Needle. Effective July 1, 2013, we acquired Hess’ 5% membership interest for $2.9 million. With the purchase of this additional 5% membership interest, our membership interest in Pine Needle increased from 40% to 45%.

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 Operations and Comprehensive Income. Pine Needle’s long-term debt is nonrecourse to the members.

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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 Operations and Comprehensive Income. For each period of the three months and nine months ended July 31, 2013 and 2012, these gas storage costs and the amounts we owed Pine Needle as of July 31, 2013 and October 31, 2012 are as follows.

	Three Months				Nine Months
In thousands	2013		2012		2013		2012
Gas storage costs	$	2,791	$	2,714	$	8,307	$	7,696

	July 31, 2013		October 31, 2012
Trade accounts payable	$	940	$	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 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 Operations and 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 Operations and Comprehensive Income. For each period of the three months and nine months ended July 31, 2013 and 2012, our operating revenues from these sales and the amounts SouthStar owed us as of July 31, 2013 and October 31, 2012 are as follows.

	Three Months				Nine Months
In thousands	2013		2012		2013		2012
Operating revenues	$	1,469	$	1,017	$	2,053	$	1,247

	July 31, 2013		October 31, 2012
Trade accounts receivable	$	427	$	473

Hardy Storage Company, LLC

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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 Operations and Comprehensive Income. For each period of the three months and nine months ended July 31, 2013 and 2012, these gas storage costs and the amounts we owed Hardy Storage as of July 31, 2013 and October 31, 2012 are as follows.

	Three Months				Nine Months
In thousands	2013		2012		2013		2012
Gas storage costs	$	2,425	$	2,425	$	7,276	$	7,276

	July 31, 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. In May 2013, through one of its subsidiaries, WGL Holdings, Inc. became a member of the joint venture along with existing members The Williams Companies, Inc. and Cabot Oil & Gas Corporation. 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 July 31, 2013, our current quarter and fiscal year contributions were $3.4 million and $12.1 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.

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

In thousands	July 31, 2013		October 31, 2012
Cardinal	$	18,335	$	17,969
Pine Needle		20,998		19,239
SouthStar		15,926		18,118
Hardy Storage		33,847		32,541
Constitution		12,685		-
Total equity method investments in non-utility activities	$	101,791	$	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 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 (Loss)” in the Consolidated Statements of Operations and Comprehensive Income. Operations of the non-utility activities segment are included in the Consolidated Statements of Operations and 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 and our cash flows in 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.

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Operations by segment for the three months and nine months ended July 31, 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	$	162,943		$	161,123		$	-		$	-		$	162,943		$	161,123
Margin		97,000			86,460			-			-			97,000			86,460
Operations and maintenance expenses		62,950			59,248			35			14			62,985			59,262
Income from equity method investments		-			-			3,652			3,290			3,652			3,290
Operating loss before income taxes		(2,856	)		(6,595	)		(117	)		(86	)		(2,973	)		(6,681	)
Income (loss) before income taxes		(8,673	)		(10,662	)		3,536			3,205			(5,137	)		(7,457	)
Nine Months
Revenues from external customers	$	1,078,229		$	941,395		$	-		$	-		$	1,078,229		$	941,395
Margin		512,480			478,647			-			-			512,480			478,647
Operations and maintenance expenses		183,869			178,155			155			59			184,024			178,214
Income from equity method investments		-			-			23,244			21,234			23,244			21,234
Operating income (loss) before income taxes		219,540			197,316			(322	)		(217	)		219,218			197,099
Income before income taxes		205,882			180,108			22,922			21,016			228,804			201,124

Reconciliations to the Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2013 and 2012 are presented below.

In thousands	Three Months						Nine Months
	2013			2012			2013			2012
Operating Income (Loss):
Segment operating income (loss) before income taxes	$	(2,973	)	$	(6,681	)	$	219,218		$	197,099
Utility income taxes		3,447			4,082			(81,232	)		(71,228	)
Non-utility activities before income taxes		117			86			322			217
Operating income (loss)	$	591		$	(2,513	)	$	138,308		$	126,088
Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(5,137	)	$	(7,457	)	$	228,804		$	201,124
Income taxes		2,844			2,844			(89,384	)		(79,318	)
Net income (loss)	$	(2,293	)	$	(4,613	)	$	139,420		$	121,806

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 and long-term debt, see Note 2 and Note 4, respectively, to the consolidated financial statements in this Form 10-Q.

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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

• Availability and cost of capital

• Federal and state fiscal, tax and monetary policies

• 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,” “guidance,” “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 atwww.piedmontng.com as soon as reasonably practicable after the report is filed with or furnished to the SEC.

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Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, 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 July 31, 2013 and earnings before taxes by segments for the nine months ended July 31, 2013 are presented below.

	Assets			Earnings Before Taxes
Regulated Utility		97	%		90	%
Non-utility Activities:
Regulated non-utility activities		2	%		3	%
Unregulated non-utility activities		1	%		7	%
Total non-utility activities		3	%		10	%

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.

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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 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 those 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 nine months ended July 31, 2013, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 71% of our utility margin, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 18% 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 11% 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 are 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

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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, safety and sustainable business practices.

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 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. Our residential billing rates 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 capacity and 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, total residential and commercial customer additions increased 15% in the nine months ended July 31, 2013 compared to the same period in 2012. Lower wholesale natural gas costs also continued to favorably position natural gas relative to other energy sources. Customer gains in our residential new construction and conversion markets increased 18% for the nine months ended July 31, 2013 compared to the same period in 2012. Commercial customer additions decreased 6% for the nine months ended July 31, 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 between 1% and 1.5%. Overall, total customers billed increased 2% for the nine months ended July 31, 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 21% 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 65,325 dekatherms of CNG to commercial customers for the nine months ended July 31, 2013, which is equivalent to approximately 956 homes, and our fleet used 6,600 dekatherms of CNG. Through sales of CNG to our commercial customers and use by our own fleet, this CNG usage displaced approximately 571,100 gallons of gasoline and diesel fuel.

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Capital Expenditures. We continue to make progress with capital projects that will provide benefits to our customers through safe and reliable natural gas service, while providing our shareholders a fair and reasonable return on invested capital. On June 1, 2013, we placed into service a major 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” presented below.

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 these capital investments. See further discussion in the section below on “Business Process and Technology Improvements.”

Rulemaking proceedings under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 remain active. Items currently being discussed include mandates concerning the integrity verification process of maximum allowable operating pressure of transmission pipelines. Potential regulatory changes resulting from the rulemaking could have a significant impact on our future capital and operating maintenance expenditures for pipeline integrity, safety and compliance, and we will seek recovery of future operating expenses and/or capital expenditures through separate rate adjustment mechanisms and other rate filings that track or recover these specific capital and operating costs as provided by our regulatory commissions.

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 nine months ended July 31, 2013 was 4% colder than normal and 30% colder than the same prior year period.

For the nine months ended July 31, 2013, the margin decoupling mechanism in North Carolina decreased margin by $.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 capital costs and operational expenses; (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.

With this new law in effect, we filed a petition with the TRA in August 2013 seeking authority to implement an integrity management rider to recover the significant costs of our capital investments that we have made and expect to make in the future in compliance with federal and state safety and integrity management laws or regulations. We proposed that the rider be effective October 1, 2013 with an initial adjustment January 1, 2014 and that rates be updated annually outside of general rate cases for the return of and on these capital investments.

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. We included this new rate adjustment mechanism in our general rate application filed In May 2013 with the NCUC. For further information on this rate proceeding, see Note 2 to the consolidated financial statements in this Form 10-Q.

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In June 2013, legislation was passed in North Carolina that increases criminal penalties and fines for interference with natural gas, water and electric lines in the state. This law will help us and all utility providers protect the integrity and safety of their system infrastructures as well as protect the general public.

In July 2013, legislation was passed in North Carolina affecting corporate taxation. The legislation reduces the corporate income tax rate from 6.9% to 6% for tax years beginning after January 1, 2014 and to 5% for tax years beginning after January 1, 2015. It also provides for two additional 1% rate reductions if the state’s tax collections exceed certain thresholds. We record deferred income taxes on temporary tax differences using the income tax rate in effect when the temporary difference is expected to reverse. As a result of the rate reductions, we adjusted our noncurrent deferred income tax balances at July 31, 2013 by approximately $24 million for temporary differences expected to reverse at a lower rate than under the prior law and recognized a tax benefit of approximately $1 million in net income, the majority of which relates to our non-utility activities segment, with the balance of approximately $23 million recorded as a regulatory liability in “Other noncurrent liabilities” in the Consolidated Balance Sheets reflecting a future benefit to our customers; our state commissions will determine the recovery period of this regulatory liability in future proceedings.

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, tools 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 calendar 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.”

On July 29, 2013, we entered into an agreement to issue $300 million of unsecured senior notes with an interest rate of 4.65%. On August 1, 2013, we issued these notes, which will mature on August 1, 2043. We intend to use the net proceeds of $297.2 million from this issuance to finance capital expenditures, to repay $100 million of our 5.00% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term, unsecured notes under our commercial paper program and for general corporate purposes.

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

Results of Operations

We reported a net loss of $2.3 million for the three months ended July 31, 2013 as compared to a net loss of $4.6 million for the same period in 2012. The following table provides a comparison of the components of the Consolidated Statements of Operations and Comprehensive Income for the three months ended July 31, 2013 as compared with the three months ended July 31, 2012.

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Comprehensive Statement of Operations Components

	Three Months Ended July 31						Variance			Percent Change
In thousands, except per share amounts	2013			2012
Operating Revenues	$	162,943		$	161,123		$	1,820			1.1	%
Cost of Gas		65,943			74,663			(8,720	)		(11.7	)%
Margin		97,000			86,460			10,540			12.2	%
Operations and Maintenance		62,950			59,248			3,702			6.2	%
Depreciation		28,599			25,532			3,067			12.0	%
General Taxes		8,307			8,275			32			0.4	%
Utility Income Taxes		(3,447	)		(4,082	)		635			15.6	%
Total Operating Expenses		96,409			88,973			7,436			8.4	%
Operating Income (Loss)		591			(2,513	)		3,104			123.5	%
Other Income (Expense), net of tax		2,819			1,977			842			42.6	%
Utility Interest Charges		5,703			4,077			1,626			39.9	%
Net Loss	$	(2,293	)	$	(4,613	)	$	2,320			50.3	%
Average Shares of Common Stock:
Basic		75,774			71,936			3,838			5.3	%
Diluted		75,774			71,936			3,838			5.3	%
Loss Per Share of Common Stock:
Basic	$	(0.03	)	$	(0.06	)	$	0.03			50.0	%
Diluted	$	(0.03	)	$	(0.06	)	$	0.03			50.0	%

We reported net income of $139.4 million for the nine months ended July 31, 2013 as compared to $121.8 million for the same period in 2012. The following table provides a comparison of the components of the Consolidated Statements of Operations and Comprehensive Income for the nine months ended July 31, 2013 as compared with the nine months ended July 31, 2012.

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Comprehensive Statement of Operations Components

	Nine Months Ended July 31				Variance			Percent Change
In thousands, except per share amounts	2013		2012
Operating Revenues	$	1,078,229	$	941,395	$	136,834			14.5	%
Cost of Gas		565,749		462,748		103,001			22.3	%
Margin		512,480		478,647		33,833			7.1	%
Operations and Maintenance		183,869		178,155		5,714			3.2	%
Depreciation		82,168		76,980		5,188			6.7	%
General Taxes		26,903		26,196		707			2.7	%
Utility Income Taxes		81,232		71,228		10,004			14.0	%
Total Operating Expenses		374,172		352,559		21,613			6.1	%
Operating Income		138,308		126,088		12,220			9.7	%
Other Income (Expense), net of tax		14,594		12,664		1,930			15.2	%
Utility Interest Charges		13,482		16,946		(3,464	)		(20.4	)%
Net Income	$	139,420	$	121,806	$	17,614			14.5	%
Average Shares of Common Stock:
Basic		74,521		71,933		2,588			3.6	%
Diluted		74,987		72,233		2,754			3.8	%
Earnings Per Share of Common Stock:
Basic	$	1.87	$	1.69	$	0.18			10.7	%
Diluted	$	1.86	$	1.69	$	0.17			10.1	%

The following table provides the components of our margin by customer class for the three months ended July 31, 2013 and 2012.

Margin by Customer Class

	Three Months Ended July 31
In thousands	2013				2012
Sales and Transportation:
Residential	$	42,015	43	%	$	40,468	47	%
Commercial		22,914	24	%		21,713	25	%
Industrial		10,021	10	%		9,528	11	%
Power Generation		16,503	17	%		8,734	10	%
For Resale		1,665	2	%		1,670	2	%
Total		93,118	96	%		82,113	95	%
Secondary Market Sales		1,330	1	%		2,761	3	%
Miscellaneous		2,552	3	%		1,586	2	%
Total	$	97,000	100	%	$	86,460	100	%

The following table provides the components of our margin by customer class for the nine months ended July 31, 2013 and 2012.

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Margin by Customer Class

	Nine Months Ended July 31
In thousands	2013				2012
Sales and Transportation:
Residential	$	284,135	56	%	$	274,196	57	%
Commercial		129,282	25	%		124,980	26	%
Industrial		41,427	8	%		37,954	8	%
Power Generation		36,803	7	%		20,544	4	%
For Resale		5,807	1	%		5,789	1	%
Total		497,454	97	%		463,463	96	%
Secondary Market Sales		6,618	1	%		7,602	2	%
Miscellaneous		8,408	2	%		7,582	2	%
Total	$	512,480	100	%	$	478,647	100	%

Key statistics are shown in the table below for the three months ended July 31, 2013 and 2012.

Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Three Months Ended July 31
	2013			2012			Variance			Percent Change
Deliveries in Dekatherms (in thousands):
Sales Volumes		9,184			7,905			1,279			16.2	%
Transportation Volumes		73,928			67,913			6,015			8.9	%
Throughput		83,112			75,818			7,294			9.6	%
Secondary Market Volumes		2,782			14,045			(11,263	)		(80.2	)%
Customers Billed (at period end)		985,034			969,492			15,542			1.6	%
Gross Customer Additions		3,226			2,670			556			20.8	%
Degree Days
Actual		77			13			64			492.3	%
Normal		49			49			-			-	%
Percent colder (warmer) than normal		57.1	%		(73.5	)%		n/a			n/a
Number of Employees (at period end)		1,795			1,773			22			1.2	%

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Key statistics are shown in the table below for the nine months ended July 31, 2013 and 2012.

Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Nine Months Ended July 31
	2013			2012			Variance			Percent Change
Deliveries in Dekatherms (in thousands):
Sales Volumes		89,058			70,526			18,532			26.3	%
Transportation Volumes		210,885			178,204			32,681			18.3	%
Throughput		299,943			248,730			51,213			20.6	%
Secondary Market Volumes		33,448			38,531			(5,083	)		(13.2	)%
Customers Billed (at period end)		985,034			969,492			15,542			1.6	%
Gross Customer Additions		10,018			8,728			1,290			14.8	%
Degree Days
Actual		3,186			2,446			740			30.3	%
Normal		3,078			3,111			(33	)		(1.1	)%
Percent colder (warmer) than normal		3.5	%		(21.4	)%		n/a			n/a
Number of Employees (at period end)		1,795			1,773			22			1.2	%

Operating Revenues

Changes in operating revenues for the three months and nine months ended July 31, 2013 compared with the same periods in 2012 are presented below.

Changes in Operating Revenues - Increase (Decrease)

In millions		Three Months			Nine Months
Residential and commercial customers		$	19.7		$	134.0
Industrial customers			3.7			13.3
Power generation customers			8.2			20.4
Secondary market			(28.3	)		24.2
Margin decoupling mechanism			(1.8	)		(44.3	)
WNA mechanisms			-			(11.3	)
Other	��		.3			.5
Total		$	1.8		$	136.8

• Residential and commercial customers – the increases for the three months and nine 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 nine months are primarily due to colder weather and customer growth.

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

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• Secondary market – the decrease for the three months is primarily due to decreased activity, partially offset by higher commodity costs. The increase for the nine months is primarily due to higher commodity costs, partially offset by decreased activity. 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 nine 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 decrease for the nine months is due to colder weather in South Carolina and Tennessee.

Cost of Gas

Changes in cost of gas for the three months and nine months ended July 31, 2013 compared with the same period in 2012 are presented below.

Changes in Cost of Gas - Increase (Decrease)

In millions	Three Months			Nine Months
Commodity gas costs passed through to sales customers	$	14.5		$	93.6
Commodity gas costs in secondary market transactions		(27.8	)		24.3
Pipeline demand charges		5.0			17.4
Regulatory approved gas cost mechanisms		(.4	)		(32.3	)
Total	$	(8.7	)	$	103.0

• Commodity gas costs passed through to sales customers – the increases for the three months and nine months are primarily 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 decrease for the three months is primarily due to decreased activity, partially offset by higher gas costs. The increase for the nine months is primarily due to increased average wholesale gas costs, partially offset by decreased activity.

• Pipeline demand charges – the increases for the three months are due to increased demand costs, decreased asset manager payments and increased capacity release revenues. The increases for the nine months are due to increased demand costs and decreased asset manager payments, slightly offset by decreased capacity release revenues.

• Regulatory approved gas cost mechanisms – the decreases for the three months and nine 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.

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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 42% of revenues for the nine months ended July 31, 2013, and our pipeline transportation and storage costs accounted for 11%.

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.

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 nine months ended July 31, 2013 compared with the same periods in 2012 are presented below.

Changes in Margin – Increase (Decrease)

In millions	Three Months			Nine Months
Residential and commercial customers	$	2.7		$	14.2
Industrial customers		.5			3.5
Power generation customers		7.8			16.3
Secondary market activity		(.5	)		(.1	)
Net gas cost adjustments		-			(.1	)
Total	$	10.5		$	33.8

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

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

• Power generation customers – the increases for the three months and nine months are primarily due to increased transportation services due to new contracts placed in service in June 2012 and June 2013.

• Secondary market activity – the decreases for the three and nine months are primarily due to lower commodity price volatility and decreased activity.

Operations and Maintenance Expenses

Changes in operations and maintenance expenses for the three months and nine months ended July 31, 2013 compared with the same periods in 2012 are presented below.

Changes in Operations and Maintenance Expenses – Increase (Decrease)

In millions	Three Months			Nine Months
Utilities	$	.8		$	1.0
Employee benefits		.5			(1.8	)
Contract labor		.2			2.5
Regulatory		(.1	)		1.0
Other		2.3			3.0
Total	$	3.7		$	5.7

• Utilities – the increase for the nine months is primarily due to increases in telecommunication and electric costs due to higher usage.

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

• Contract labor – the increase for the nine months is primarily due to pipeline integrity and maintenance programs, safety programs and process improvement projects.

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

Depreciation

Depreciation expense increased $3.1 million and $5.2 million for the three months and nine months ended July 31, 2013, respectively, compared with the same periods in 2012 primarily due to increases in plant in service, particularly related to a power generation project being completed.

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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 July 31, 2013 compared with the same period in 2012 was comparable.

The primary change to Other Income (Expense) for the nine months ended July 31, 2013 compared with the same period in 2012 was income from equity method investments, primarily from SouthStar Energy Services LLC (SouthStar) and Constitution Pipeline Company, LLC (Constitution). Income from equity method investments from SouthStar increased $1.4 million primarily due to increased average customer usage in Georgia from colder weather compared 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. Beginning November 1, 2012 with our initial investment in Constitution, we recorded earnings of $.6 million due to AFUDC, partially offset by operating expenses.

Utility Interest Charges

Changes in utility interest charges for the three months and nine months ended July 31, 2013 compared with the same periods in 2012 are presented below.

Changes in Utility Interest Charges – Increase (Decrease)

In millions	Three Months			Nine Months
Interest expense on long-term debt	$	2.5		$	7.8
Borrowed Allowance for Funds Used During Construction (AFUDC)		(.9	)		(8.6	)
Interest expense on short-term debt		(.1	)		(1.3	)
Other		.1			(1.4	)
Total	$	1.6		$	(3.5	)

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

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

• Interest expense on short-term debt – the decrease for the three months is primarily due to interest rates being on average 13 basis points lower than the same prior period on slightly lower borrowings in the current period. The decrease for the nine months is primarily due to interest rates that are on average 43 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.

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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 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. For information on the issuance of long-term debt and equity securities, see Note 4 and Note 6, respectively, 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 provide 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 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.

Highlights for our short-term debt as of July 31, 2013 and for the quarter ended July 31, 2013 are presented below.

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Short-Term Debt

As of July 31, 2013

In thousands	Credit Facility			Commercial Paper			Total Borrowings
End of period (July 31, 2013):
Amount outstanding	$	-		$	515,000		$	515,000
Weighted average interest rate		-	%		.25	%		.25	%
During the period (May 1, 2013 – July 31, 2013):
Average amount outstanding	$	-		$	408,100		$	408,100
Minimum amount outstanding		-			330,000			330,000
Maximum amount outstanding		-			515,000			515,000
Minimum interest rate		-	%		.23	%		.23	%
Maximum interest rate		-	%		.30	%		.30	%
Weighted average interest rate		-	%		.26	%		.26	%
Maximum amount outstanding:
May 2013	$	-		$	380,000		$	380,000
June 2013		-			435,000			435,000
July 2013		-			515,000			515,000

As of July 31, 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 July 31, 2013, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $132.9 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.

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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 $285.9 million and $266.1 million for the nine months ended July 31, 2013 and 2012, respectively. Net cash provided by operating activities reflects an increase of $17.6 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 $4.5 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 18.3 million dekatherms as compared with the same prior period primarily due to 30% colder weather in the current period. Total throughput increased 51.2 million dekatherms as compared with the same prior period, including 26.7 million dekatherms, or 24%, increased deliveries to power generation customers.

• Net amounts due from customers decreased $32.8 million from October 31, 2012 primarily due to margin decoupling and deferred gas costs collections through rates.

• Gas in storage decreased $3.9 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 $1.8 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 nine months ended July 31, 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 $.7 million and increased margin by $43.6 million in the nine months ended July 31, 2013 and 2012, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanisms.

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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 approximately $27 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. From the carryforward of 2013 NOLs, we anticipate we will completely offset 2014 taxable income and will generate taxable income sufficient to utilize all NOLs prior to the expiration of the loss carryforward periods.

As previously discussed in “Regulatory Activity” in the “Executive Summary,” as a result of the corporate income tax rate reductions under the new North Carolina tax legislation, we adjusted our noncurrent deferred income tax balances by approximately $24 million for temporary differences expected to reverse at a lower tax rate than under the prior law and recognized a tax benefit of approximately $1 million in net income, the majority of which relates to our non-utility activities segment, with the balance recorded as a regulatory liability of approximately $23 million reflecting a future benefit to our customers.

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.

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

Cash Flows from Investing Activities. Net cash used in investing activities was $475.5 million and $359.5 million for the nine months ended July 31, 2013 and 2012, respectively. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures for the nine months ended July 31, 2013 were $443.3 million as compared to $351 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. Our program primarily supports our system infrastructure and the growth in our customer base. We are increasing our spending for pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity. 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 $610 – $650 million in our fiscal year 2013, including approximately $265 million for system integrity projects and $85 million for the Sutton power generation delivery project that we placed in service on June 1, 2013. Our estimates of utility capital expenditures shown below for 2013 – 2015 include system integrity projects of approximately $225 – $275 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	$	525 – 565	$	425 – 475	$	375 – 425
Sutton power generation project		85 – 85		-		-
Total forecasted capital expenditures	$	610 – 650	$	425 – 475	$	375 – 425

Our estimates for utility capital expenditures in 2013-2015, particularly those associated with system integrity, have increased compared to previous estimates in prior periods. These increases are primarily due to costs associated with the development and enhancement of programs and processes designed to mitigate risk on our system to comply with federally mandated pipeline safety and integrity requirements. Such programs include retrofitting transmission lines to facilitate internal inspections, transmission line replacements, corrosion control, casing remediation and distribution integrity management. The increased expenditures in 2014 also include costs associated with the replacement of a major transmission line in Nashville, the construction of which began in 2013.

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, as stated above. Our investment in the pipeline and compression facilities is supported by a long-term service agreement with fixed monthly payments.

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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.

On July 1, 2013, we acquired for $2.9 million an additional 5% membership interest in Pine Needle LNG, L.L.C. from Hess Corporation, which increased our membership interest from 40% to 45%. For further information regarding this transaction, see Note 12 to the consolidated financial statements in this Form 10-Q.

In November 2012, we became a 24% equity member of 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 July 31, 2013 were $12.1 million, 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. 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 financing activities was $192.4 million and $92.3 million for the nine months ended July 31, 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 finance capital expenditures, retire long-term debt maturities, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program, pay quarterly dividends on our common stock and general corporate purposes.

Outstanding debt under our syndicated revolving credit facility and CP program increased to $515 million as of July 31, 2013 from $365 million as of October 31, 2012 primarily due to increased utility capital expenditures and investments in our equity method investments, partially offset by 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.”

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. 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 1.6 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, the original offering price, 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.

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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 to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program 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 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. On August 1, 2013, we issued unsecured senior notes in the amount of $300 million with an interest rate of 4.65% under our open debt and equity shelf registration statement. These notes will mature on August 1, 2043. We intend to use the net proceeds of $297.2 million to finance capital expenditures, to repay $100 million of our 5% medium-term notes due December 19, 2013 at maturity, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes. For further information on our long-term debt instruments, see Note 4 to the consolidated financial statements in this Form 10-Q.

During the nine months ended July 31, 2013 and 2012, we issued $18.9 million and $16.5 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 years 2013 and 2014. During the nine months ended July 31, 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 July 31, 2013, our retained earnings were not restricted. On September 5, 2013, the Board of Directors declared a quarterly dividend on common stock of $.31 per share, payable October15, 2013 to shareholders of record at the close of business on September 24, 2013.

Our long-term targeted capitalization ratio is 45 – 50% in long-term debt and 50 – 55% in common equity. As of July 31, 2013, our capitalization, including current maturities of long-term debt, if any, consisted of 45% in long-term debt and 55% in common equity.

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

	July 31					October 31					July 31
In thousands	2013		Percentage			2012		Percentage			2012		Percentage
Short-term debt	$	515,000		19	%	$	365,000		16	%	$	200,000		9	%
Current portion of long-term debt		100,000		4	%		-		-	%		-		-	%
Long-term debt		875,000		32	%		975,000		41	%		975,000		44	%
Total debt		1,490,000		55	%		1,340,000		57	%		1,175,000		53	%
Common stockholders’ equity		1,211,449		45	%		1,027,004		43	%		1,044,771		47	%
Total capitalization (including short-term debt)	$	2,701,449		100	%	$	2,367,004		100	%	$	2,219,771		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.

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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 July 31, 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 July 31, 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 July 31, 2013, there has been no event of default giving rise to acceleration of our debt.

Estimated Future Contractual Obligations

During the three months ended July 31, 2013, there were no material changes other than the issuance of long-term debt discussed below 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. On August 1, 2013, we issued notes in the amount of $300 million with an interest rate of 4.65%, which will mature on August 1, 2043. As previously disclosed, in November 2012, we are contractually committed to fund the development and construction of a new pipeline in proportion to our 24% membership interest in Constitution. As of July 31, 2013, we have funded $12.1 million based on current cost estimates for the pipeline. For further information about these contractual obligations, see Note 4 and 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.

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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.

During the nine months ended July 31, 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 nine months ended July 31, 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 July 31, 2013, we had $515 million of debt outstanding under our CP program at an interest rate of .25%, which at July 31, 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 $3.2 million during the nine months ended July 31, 2013.

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Item 4. Controls and Procedures

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

We routinely review our internal control over financial reporting and from time to time make changes intended to enhance the effectiveness of our internal control over financial reporting. There were no changes to our internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the third quarter of fiscal 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 immaterial litigation or routine litigation in the normal course of business.

Item 1A. Risk Factors

During the nine months ended July 31, 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.

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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 July 31, 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
5/1/13 – 5/31/13		-	$	-		-		2,910,074
6/1/13 – 6/30/13		-	$	-		-		2,910,074
7/1/13 – 7/31/13		-	$	-		-		2,910,074
Total		-	$	-		-

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

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of July 31, 2013, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

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Item 6. Exhibits

10.1	Resolution of Board of Directors, June 7, 2013, establishing compensation for non-management directors
10.2	Underwriting Agreement, dated July 29, 2013, among the Company, Merrill Lynch, Pierce, Fenner & Smith Incorporated, U.S. Bancorp Investments, Inc., individually and acting as representatives of each of the other underwriters named in Schedule A thereto (incorporated by reference to Exhibit 1.1, Form 8-K dated August 1, 2013)
10.3	Second Amendment to Amended and Restated Limited Liability Company Agreement of Constitution Pipeline Company, LLC, dated as of May 29, 2013, by and among Constitution Pipeline Company, LLC, Williams Partners Operating LLC, Cabot Pipeline Holdings LLC, Piedmont Constitution Pipeline Company, LLC, and Capitol Energy Ventures Corp. (incorporated by reference to Exhibit 99.1, Form 8-K dated September 4, 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
99.1	Instrument of Amendment for Piedmont Natural Gas Company, Inc. 401k Plan dated as of March 13, 2013, by Piedmont Natural Gas Company, Inc.
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 July 31, 2013 and October 31, 2012; (3) Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2013 and 2012; (4) Consolidated Statements of Cash Flows for the nine months ended July 31, 2013 and 2012; (5) Consolidated Statements of Stockholders’ Equity for the nine months ended July 31, 2013 and 2012; and (6) Notes to Consolidated Financial Statements.

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SIGNATURES

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

Piedmont Natural Gas Company, Inc.

(Registrant)

Date September 5, 2013	/s/ Karl W. Newlin
	Karl W. Newlin
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Date September 5, 2013	/s/ Jose M. Simon
	Jose M. Simon
	Vice President and Controller (Principal Accounting Officer)

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Piedmont Natural Gas Company, Inc.

Form 10-Q

For the Quarter Ended July 31, 2013

Exhibits

10.1	Resolution of Board of Directors, June 7, 2013, establishing compensation for non-management directors.
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
99.1	Instrument of Amendment for Piedmont Natural Gas Company, Inc. 401k Plan dated as of March 13, 2013, by Piedmont Natural Gas Company, Inc.