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 January 31, 2014

or

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

For the transition period from                                  to                                 

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

Class	Outstanding at February 28, 2014
Common Stock, no par value	77,937,255

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

January 31, 2014

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		27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		46
Item 4.	Controls and Procedures		47
Part II.	Other Information
Item 1.	Legal Proceedings		47
Item 1A.	Risk Factors		47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		47
Item 6.	Exhibits		49
	Signatures		50

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)

	January 31, 2014		October 31, 2013
ASSETS
Utility Plant:
Utility plant in service	$	4,520,204	$	4,421,937
Less accumulated depreciation		1,112,399		1,088,331
Utility plant in service, net		3,407,805		3,333,606
Construction work in progress		331,235		297,717
Plant held for future use		3,155		3,155
Total utility plant, net		3,742,195		3,634,478
Other Physical Property, at cost (net of accumulated depreciation of $883 in 2014 and $876 in 2013)		375		382
Current Assets:
Cash and cash equivalents		16,234		8,063
Trade accounts receivable (less allowance for doubtful accounts of $3,648 in 2014 and $1,604 in 2013)		270,559		79,210
Income taxes receivable		28,099		31,065
Other receivables		1,725		1,988
Unbilled utility revenues		119,750		24,967
Inventories:
Gas in storage		66,066		73,929
Materials, supplies and merchandise		1,716		1,725
Gas purchase derivative assets, at fair value		6,369		1,834
Regulatory assets		24,449		77,204
Prepayments		9,615		35,038
Deferred income taxes		14,009		12,695
Other current assets		365		338
Total current assets		558,956		348,056
Noncurrent Assets:
Equity method investments in non-utility activities		144,444		128,469
Goodwill		48,852		48,852
Regulatory assets		171,186		169,102
Marketable securities, at fair value		3,530		2,995
Overfunded postretirement asset		48,258		28,258
Other noncurrent assets		8,463		8,017
Total noncurrent assets		424,733		385,693
Total	$	4,726,259	$	4,368,609

See notes to condensed consolidated financial statements.

1

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)

	January 31, 2014		October 31, 2013
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: 77,922 in 2014 and 76,099 in 2013		615,993		561,644
Retained earnings		700,724		627,236
Accumulated other comprehensive income (loss)		27		(284	)
Total stockholders’ equity		1,316,744		1,188,596
Long-term debt		1,174,858		1,174,857
Total capitalization		2,491,602		2,363,453
Current Liabilities:
Current maturities of long-term debt		-		100,000
Short-term debt		570,000		400,000
Trade accounts payable		174,235		96,281
Other accounts payable		33,121		43,855
Income taxes accrued		736		-
Accrued interest		19,456		28,205
Customers’ deposits		21,516		19,831
General taxes accrued		8,950		21,454
Regulatory liabilities		31,312		-
Other current liabilities		23,554		7,024
Total current liabilities		882,880		716,650
Noncurrent Liabilities:
Deferred income taxes		742,951		681,369
Unamortized federal investment tax credits		1,343		1,402
Accumulated provision for postretirement benefits		11,968		12,042
Regulatory liabilities		545,619		541,897
Conditional cost of removal obligations		27,395		27,016
Other noncurrent liabilities		22,501		24,780
Total noncurrent liabilities		1,351,777		1,288,506
Commitments and Contingencies (Note 9)
Total	$	4,726,259	$	4,368,609

See notes to condensed consolidated financial statements.

2

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

(In thousands except per share amounts)

	Three Months Ended January 31
	2014			2013
Operating Revenues	$	657,733		$	515,875
Cost of Gas		396,221			284,252
Margin		261,512			231,623
Operating Expenses:
Operations and maintenance		60,639			55,882
Depreciation		29,643			26,701
General taxes		9,109			9,528
Utility income taxes		59,802			53,299
Total operating expenses		159,193			145,410
Operating Income		102,319			86,213
Other Income (Expense):
Income from equity method investments		9,941			7,155
Non-operating income		250			448
Non-operating expense		(608	)		(762	)
Income taxes		(3,728	)		(2,674	)
Total other income (expense)		5,855			4,167
Utility Interest Charges:
Interest on long-term debt		15,593			12,675
Allowance for borrowed funds used during construction		(5,952	)		(8,313	)
Other		961			95
Total utility interest charges		10,602			4,457
Net Income		97,572			85,923
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $111 and ($114) for the three months ended January 31, 2014 and 2013, respectively,		174			(179	)
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $88 and $14 for the three months ended January 31, 2014 and 2013, respectively		137			21
Total other comprehensive income (loss)		311			(158	)
Comprehensive Income	$	97,883		$	85,765
Average Shares of Common Stock:
Basic		76,988			72,356
Diluted		77,327			72,725
Earnings Per Share of Common Stock:
Basic	$	1.27		$	1.19
Diluted	$	1.26		$	1.18

See notes to condensed consolidated financial statements.

3

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Three Months Ended January 31
	2014			2013
Cash Flows from Operating Activities:
Net income	$	97,572		$	85,923
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31,798			28,392
Allowance for doubtful accounts		2,044			1,681
Net gain on sale of property		-			(18	)
Income from equity method investments		(9,941	)		(7,155	)
Distributions of earnings from equity method investments		2,431			1,962
Deferred income taxes, net		60,010			59,044
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		(4,535	)		2,429
Receivables		(287,945	)		(183,621	)
Inventories		7,872			(5,916	)
Settlement of legal asset retirement obligations		(697	)		(328	)
Other assets		78,698			43,067
Accounts payable		63,207			19,436
Provision for postretirement benefits, net		(20,074	)		(19,833	)
Other liabilities		28,491			(12,429	)
Net cash provided by operating activities		48,931			12,634
Cash Flows from Investing Activities:
Utility capital expenditures		(124,999	)		(137,211	)
Allowance for borrowed funds used during construction		(5,952	)		(8,313	)
Contributions to equity method investments		(9,960	)		(7,548	)
Distributions of capital from equity method investments		2,005			110
Proceeds from sale of property		283			370
Investments in marketable securities		(520	)		(418	)
Other		732			38
Net cash used in investing activities		(138,411	)		(152,972	)

4

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	Three Months Ended January 31
	2014			2013
Cash Flows from Financing Activities:
Borrowings under credit facility	$	-		$	10,000
Repayments under credit facility		-			(10,000	)
Net borrowings – commercial paper		170,000			165,000
Repayment of long-term debt		(100,000	)		-
Expenses related to issuance of debt		(459	)		(4	)
Proceeds from issuance of common stock		47,302			-
Issuance of common stock through dividend reinvestment and employee stock plans		4,924			5,680
Dividends paid		(24,113	)		(21,702	)
Other		(3	)		-
Net cash provided by financing activities		97,651			148,974
Net Increase in Cash and Cash Equivalents		8,171			8,636
Cash and Cash Equivalents at Beginning of Period		8,063			1,959
Cash and Cash Equivalents at End of Period	$	16,234		$	10,595
Cash Paid During the Year for:
Interest	$	25,094		$	22,352
Income Taxes:
Income taxes paid	$	219		$	790
Income taxes refunded		19			-
Income taxes, net	$	200		$	790
Noncash Investing and Financing Activities:
Accrued capital expenditures	$	43,377		$	32,755

See notes to condensed consolidated financial statements.

5

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed 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, 2012		72,250	$	442,461		$	584,848		$	(305	)	$	1,027,004
Net Income							85,923						85,923
Other Comprehensive Loss										(158	)		(158	)
Common Stock Issued		262		7,916									7,916
Expenses from Issuance of Common Stock				(202	)								(202	)
Tax Benefit from Dividends Paid on ESOP Shares							29						29
Dividends Declared ($.30 per share)							(21,702	)					(21,702	)
Balance, January 31, 2013		72,512	$	450,175		$	649,098		$	(463	)	$	1,098,810
Balance, October 31, 2013		76,099	$	561,644		$	627,236		$	(284	)	$	1,188,596
Net Income							97,572						97,572
Other Comprehensive Income										311			311
Common Stock Issued		1,823		54,349									54,349
Tax Benefit from Dividends Paid on ESOP Shares							29						29
Dividends Declared ($.31 per share)							(24,113	)					(24,113	)
Balance, January 31, 2014		77,922	$	615,993		$	700,724		$	27		$	1,316,744

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Summary of Significant Accounting Policies

Unaudited Interim Financial Information

The condensed consolidated financial statements have not been audited. We have prepared the unaudited condensed 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, 2013.

Seasonality and Use of Estimates

The unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of the statement of financial position at January 31, 2014 and October 31, 2013, the results of operations for the three months ended January 31, 2014 and 2013, and cash flows and stockholders’ equity for the three months ended January 31, 2014 and 2013. Our business is seasonal in nature. The results of operations for the three months ended January 31, 2014 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 condensed 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 condensed 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, 2013. There were no significant changes to those accounting policies during the three months ended January 31, 2014.

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

7

effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and 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 Condensed Consolidated Balance Sheets as of January 31, 2014 and October 31, 2013 are as follows.

In thousands	January 31, 2014		October 31, 2013
Regulatory Assets:
Current:
Unamortized debt expense	$	1,384	$	1,274
Amounts due from customers		13,144		66,321
Environmental costs		1,647		1,480
Deferred operations and maintenance expenses		916		739
Deferred pipeline integrity expenses		3,469		3,149
Deferred pension and other retirement benefit costs		2,769		2,768
Robeson liquefied natural gas (LNG) development costs		382		382
Other		738		1,091
Total current		24,449		77,204
Noncurrent:
Unamortized debt expense		14,143		14,149
Environmental costs		7,557		7,936
Deferred operations and maintenance expenses		5,283		5,637
Deferred pipeline integrity expenses		17,373		16,300
Deferred pension and other retirement benefit costs		20,867		17,968
Amounts not yet recognized as a component of pension and other retirement benefit costs		79,243		80,604
Regulatory cost of removal asset		23,382		22,974
Robeson LNG development costs		1,330		1,426
Other		2,008		2,108
Total noncurrent		171,186		169,102
Total	$	195,635	$	246,306
Regulatory Liabilities:
Current:
Amounts due to customers	$	31,312	$	-
Noncurrent:
Regulatory cost of removal obligations		497,249		493,111
Deferred income taxes		48,235		48,647
Amounts not yet recognized as a component of pension and other retirement benefit costs		135		139
Total noncurrent		545,619		541,897
Total	$	576,931	$	541,897

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 condensed consolidated financial statements in this Form 10-Q.

8

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 Condensed 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 Condensed 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 condensed 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, 2013. 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, 2013. There were no significant changes to these fair value methodologies during the three months ended January 31, 2014.

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. These new disclosure requirements, which we adopted this quarter, are effective for annual periods beginning after January 1, 2013, and interim periods within those periods, and require retrospective application in all periods presented. The adoption of this guidance had 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 U.S. GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial

9

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

On December 17, 2013, the North Carolina Utilities Commission (NCUC) approved our general rate case settlement agreement with the NCUC Public Staff with new rates effective on January 1, 2014. In its order, the NCUC approved the following:

• Updated and increased rates and charges based on an overall rate base of $1.8 billion, an equity capital structure component of 50.7%, a return on common equity of 10% and an overall rate of return of 7.51%,

• Increased total annual revenues of $30.7 million, including $16.8 million related to gas utility margin and $13.8 million related to increased fixed gas costs,

• Implementation of a new integrity management rider (IMR) designed to track and recover annually outside of general rate cases the costs associated with capital expenditures incurred to comply with federal pipeline safety and integrity requirements,

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

• Updated and revised service regulations and tariffs,

• Amortization and collection of certain non-real estate costs associated with the initial development of the Robeson County LNG facility,

• Amortization and collection of certain environmental expenses and pipeline safety and integrity compliance expenses deferred since our last general rate case, and

• Recovery of ongoing annual contributions to help fund pipeline safety and integrity research.

In August 2013, we filed a petition with the Tennessee Regulatory Authority (TRA) seeking authority to implement an IMR 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 on January 1, 2014 of $13.1 million in annual margin revenue from tariff customers based on capital expenditures incurred through October 2013 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. In September 2013, the TRA issued an order suspending this proposed tariff through December 30, 2013. On November 27, 2013, we filed with the TRA a settlement with the Tennessee Attorney General’s Consumer Advocate Division agreeing to the IMR. A hearing on this matter was held December 18, 2013, and the TRA approved the IMR settlement as filed. A written order has not been issued 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 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.

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In January 2014, we filed a petition with the NCUC seeking authority to adjust rates effective February 1, 2014 under the IMR mechanism approved in the general rate case settlement agreement in December 2013 discussed above. The IMR provides for annual adjustments to our rates every February 1 for capital investments in integrity and safety projects as of October 31 of the preceding year. On February 5, 2014, the NCUC approved as filed an IMR adjustment totaling $.8 million in annual margin revenues to be reflected in our rates to customers.

In February 2014, we filed a petition with the TRA to authorize us to amortize and refund $4.7 million to customers for recorded excess deferred taxes. We proposed to refund this amount to customers over three years. We are waiting on a ruling from the TRA at this time.

3. Earnings per Share

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

A reconciliation of basic and diluted EPS for the three months ended January 31, 2014 and 2013 is presented below.

	Three Months
In thousands except per share amounts	2014		2013
Net Income	$	97,572	$	85,923
Average shares of common stock outstanding for basic earnings per share		76,988		72,356
Contingently issuable shares under incentive compensation plans		339		369
Average shares of dilutive stock		77,327		72,725
Earnings Per Share of Common Stock:
Basic	$	1.27	$	1.19
Diluted	$	1.26	$	1.18

4. Long-Term Debt Instruments

We repaid the balance of $100 million of our 5% medium-term notes in December 2013 as they became due.

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 condensed consolidated financial statements in this Form 10-Q.

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.

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5. Short-Term Debt Instruments

On November 1, 2013, we entered into an agreement with the lenders under our five-year revolving syndicated credit facility that expires on October 1, 2017 to exercise an option which increased our borrowing capacity from $650 million to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The facility provides a line of credit for letters of credit of $10 million, of which $1.8 million and $2.1 million were issued and outstanding as of January 31, 2014 and October 31, 2013, 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 an unsecured commercial paper (CP) program that is backstopped by the revolving syndicated credit facility. In conjunction with the exercise of the option in November 2013, the amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, have been increased to, but cannot exceed, $850 million. 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. 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 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 January 31, 2014, we have $570 million of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Condensed Consolidated Balance Sheets with original maturities ranging from 7 to 28 days from their dates of issuance at a weighted average interest rate of .25%. As of October 31, 2013, our outstanding notes under the CP program, included in the Condensed Consolidated Balance Sheets as stated above, were $400 million.

We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2014. A summary of the short-term debt activity under our CP program for the three months ended January 31, 2014 is as follows.

In millions
Minimum amount outstanding	$	415
Maximum amount outstanding	$	625
Minimum interest rate		.23	%
Maximum interest rate		.43	%
Weighted average interest rate		.26	%

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 57% at January 31, 2014.

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6. Stockholders’ Equity

Capital Stock

Changes in common stock for the three months ended January 31, 2014 are as follows.

In thousands	Shares		Amount
Balance, October 31, 2013		76,099	$	561,644
Issued to participants in the Employee Stock Purchase Plan (ESPP)		8		259
Issued to the Dividend Reinvestment and Stock Purchase Plan		147		4,600
Issued to participants in the Incentive Compensation Plan (ICP)		68		2,188
Issuance of common stock through public share offering		1,600		47,302
Balance, January 31, 2014		77,922	$	615,993

Cash dividends paid per share of common stock for the three months ended January 31, 2014 and 2013 are as follows.

	Three Months
	2014		2013
Cash dividends paid per share of common stock	$	.31	$	.30

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 of which 3 million direct shares were issued and settled on February 4, 2013 with proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.

The remaining 1.6 million shares under this same underwriting agreement were under forward sale agreements (FSAs) with 1 million shares borrowed by a forward counterparty and sold to the underwriters for resale to the public on February 4, 2013 at the same price as the direct shares; the remaining .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the underwriters exercised their option to purchase the full additional .6 million shares of our common stock where the shares were borrowed from third parties and sold to the underwriters by the forward counterparty. Both of the FSAs had to be settled no later than mid December 2013. Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreements.

On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments. We recorded this amount in “Stockholders’ equity” as an addition to “Common stock” in the Condensed Consolidated Balance Sheets. Upon settlement, we used 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.

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Upon physical settlement of the FSAs on December 16, 2013, delivery of our shares resulted in dilution to our EPS. In quarters prior to the settlement date, any dilutive effect of the FSAs on our EPS occurred during periods when the average market price per share of our common stock was above the per share adjusted forward sale price described above.

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 condensed consolidated financial statements in this Form 10-Q. Changes in each component of accumulated OCIL are presented below for the three months ended January 31, 2014 and 2013.

	Changes in Accumulated OCIL(1)
In thousands	2014			2013
Accumulated OCIL beginning balance, net of tax	$	(284	)	$	(305	)
OCIL before reclassifications, net of tax		174			(179	)
Amounts reclassified from accumulated OCIL, net of tax		137			21
Total current period activity, net of tax		311			(158	)
Accumulated OCIL ending balance, net of tax	$	27		$	(463	)

⁽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 ended January 31, 2014 and 2013.

	Reclassification Out of Accumulated OCIL (1)						Affected Line Items on  Condensed Statement of Comprehensive Income
In thousands	2014			2013
Hedging activities of equity method investments	$	(225	)	$	(35	)	Income from equity method investments
Income tax expense		88			14		Income taxes
Total reclassification for the period, net of tax	$	(137	)	$	(21	)

⁽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 condensed 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 on the Condensed 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 has been included in “Other current assets” in “Current Assets” in the Condensed Consolidated Balance Sheets.

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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 quoted market prices as traded on the exchanges. The composition of these securities as of January 31, 2014 and October 31, 2013 is as follows.

	January 31, 2014				October 31, 2013
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	-	$	-	$	-	$	-
Mutual funds		146		225		134		199
Total current trading securities		146		225		134		199
Noncurrent trading securities:
Money markets		472		472		380		380
Mutual funds		2,481		3,058		1,995		2,615
Total noncurrent trading securities		2,953		3,530		2,375		2,995
Total trading securities	$	3,099	$	3,755	$	2,509	$	3,194

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 January 31, 2014 and October 31, 2013, we had long gas purchase options providing total coverage of 13.8 million dekatherms and 25.4 million dekatherms, respectively. The long gas purchase options held at January 31, 2014 are for the period from March 2014 through October 2014.

Fair Value Measurements

We use financial instruments that are not designated as hedges for accounting purposes 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, 2013.

The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of January 31, 2014 and October 31, 2013. 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

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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 January 31, 2014 and 2013. The fair value of our derivatives held for utility operations is presented on a gross basis and does not reflect any netting of asset and liability amounts or cash collateral amounts under master netting arrangements; therefore, we have no offsetting disclosures of financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with a counterparty.

Recurring Fair Value Measurements as of January 31, 2014

In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level  3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives held for utility operations	$	6,369	$	-	$	-	$	-	$	6,369
Debt and equity securities held as trading securities:
Money markets		472		-		-		-		472
Mutual funds		3,283		-		-		-		3,283
Total fair value assets	$	10,124	$	-	$	-	$	-	$	10,124

Recurring Fair Value Measurements as of October 31, 2013

In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level  3)		Effects of Netting and Cash Collateral Receivables / Payables		Total Carrying Value
Assets:
Derivatives held for utility operations	$	1,834	$	-	$	-	$	-	$	1,834
Debt and equity securities held as trading securities:
Money markets		380		-		-		-		380
Mutual funds		2,814		-		-		-		2,814
Total fair value assets	$	5,028	$	-	$	-	$	-	$	5,028

Our utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the Public Service Commission of South Carolina (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 purchased gas adjustment (PGA) procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due from customers” or “Amounts due to customers” in Note 1 to the condensed consolidated financial statements. 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 Condensed 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.

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Our long-term debt is recorded at unamortized cost. 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.

In thousands	Carrying Amount *		Fair Value
As of January 31, 2014	$	1,175,000	$	1,306,365
As of October 31, 2013		1,275,000		1,409,892

* Excludes discount on issuance of notes of $142 and $143 as of January 31, 2014 and October 31, 2013, respectively.

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 January 31, 2014 and October 31, 2013.

Fair Value of Derivative Instruments

In thousands	Fair Value January 31, 2014		Fair Value October 31, 2013
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets – Gas purchase derivative assets (March 2014-October 2014)	$	6,369
Current Assets – Gas purchase derivative assets (December 2013-October 2014)			$	1,834

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 included as “Regulatory Assets” or “Regulatory Liabilities” in Note 1 to the condensed consolidated financial statements and recognized in the Condensed Consolidated Statements of Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.

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The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2014 and 2013, absent the regulatory treatment under our approved PGA procedures.

	Amount of Gain (Loss) Recognized on Derivatives Instruments					Amount of Gain (Loss) Deferred Under PGA Procedures					Location of Gain (Loss) Recognized through PGA Procedures
	Three Months Ended January  31					Three Months Ended January  31
In thousands	2014		2013			2014		2013
Gas purchase options	$	4,529	$	(2,475	)	$	4,529	$	(2,475	)		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 natural gas and related 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 Condensed Consolidated Balance Sheets attributable to these entities amounted to $65.1 million, or approximately 24% of our gross trade accounts receivable at January 31, 2014. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or 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 January 31, 2014, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.

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Natural gas distribution operating revenues and related trade accounts receivable are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can 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 nine months. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to four years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (FERC) in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Condensed Consolidated Statements of Comprehensive Income as part of gas purchases and included in “Cost of Gas.”

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.

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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, either individually or in the aggregate, on our financial position, results of operations or cash flows.

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $1.8 million in letters of credit that were issued and outstanding as of January 31, 2014. Additional information concerning letters of credit is included in Note 5 to the condensed 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. There were no material changes in the status of environmental-related matters during the three months ended January 31, 2014.

As of January 31, 2014, our estimated undiscounted environmental liability totaled $1.3 million and consisted of $1.1 million for manufactured gas production sites for which we retain remediation responsibility, $.1 million for groundwater remediation at our Huntersville LNG site, and $.1 million for LNG facilities and underground storage tanks 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.

Further evaluation of environmental liabilities 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, 2013.

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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 January 31, 2014 and 2013 are presented below.

	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2014			2013			2014		2013		2014			2013
Service cost	$	2,750		$	3,150		$	-	$	-	$	277		$	332
Interest cost		2,950			2,475			45		40		362			282
Expected return on plan assets		(5,700	)		(5,300	)		-		-		(457	)		(416	)
Amortization of transition obligation		-			-			-		-		-			167
Amortization of prior service (credit) cost		(550	)		(550	)		20		20		-			-
Amortization of actuarial loss		1,875			2,750			12		40		-			-
Total	$	1,325		$	2,525		$	77	$	100	$	182		$	365

In November 2013, we contributed $20 million to the qualified pension plan, and in January 2014, we contributed $.9 million to the money purchase pension plan. During the three months ended January 31, 2014, we contributed $.1 million to the nonqualified pension plans. We anticipate that we will contribute the following amounts to our plans in 2014.

In thousands
Nonqualified pension plans	$	340
OPEB plan		1,500

We have a non-qualified defined contribution restoration plan (DCR plan) for all officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. For the three months ended January 31, 2014, we contributed $.5 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 January 31, 2014, we have a liability of $3.8 million for these plans.

See Note 7 and Note 8 to the condensed 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 ended January 31, 2014 and 2013, we recorded compensation expense, and as of January 31, 2014 and October 31, 2013, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award vested for participants who met the retention requirements at the end of the three-year period ending in December 2013 and was paid in the

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form of shares of common stock and withholdings for payment of applicable taxes on the compensation. During the award period, the Compensation Committee of our Board of Directors had the discretion to accelerate the vesting of all or a portion of a participant’s units. For the three months ended January 31, 2014 and 2013, we recorded compensation expense, and as of October 31, 2013, we accrued a liability for this award based on the fair market value of our stock at the end of the quarter. The liability was re-measured to market value in December 2013, 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 ended January 31, 2014 and 2013, we recorded compensation expense, and as of January 31, 2014 and October 31, 2013, we 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 Condensed Consolidated Statements of Stockholders’ Equity.

The compensation expense related to the incentive compensation plans for the three months ended January 31, 2014 and 2013, and the amounts recorded as liabilities in “Other noncurrent liabilities” in “Noncurrent Liabilities” with the current portion recorded in “Other current liabilities” in “Current Liabilities” in the Condensed Consolidated Balance Sheets as of January 31, 2014 and October 31, 2013 are presented below.

	Three Months
In thousands	2014		2013
Compensation expense	$	2,100	$	1,856

	January 31, 2014		October 31, 2013
Liability	$	9,179	$	11,098

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

12. Equity Method Investments

The condensed 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

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ownership interest in each entity is included in “Equity method investments in non-utility activities” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Condensed Consolidated Statements of Comprehensive Income.

Cardinal Pipeline Company, L.L.C.

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

Cardinal enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive income (loss)” in “Stockholders’ equity” in the Condensed 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 Condensed Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.

We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of Gas” in the Condensed Consolidated Statements of Comprehensive Income. For each period of the three months ended January 31, 2014 and 2013, these transportation costs and the amounts we owed Cardinal as of January 31, 2014 and October 31, 2013 are as follows.

	Three Months
In thousands	2014		2013
Transportation costs	$	2,240	$	2,139

	January 31, 2014		October 31, 2013
Trade accounts payable	$	755	$	755

Pine Needle LNG Company, L.L.C.

We own 45% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. Our membership interest in Pine Needle increased on July 1, 2013 from 40% to 45% with the purchase of Hess Corporation’s 5% membership interest. Pine Needle owns an interstate LNG storage facility in North Carolina and is regulated by the FERC.

Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive income (loss)” in “Stockholders’ equity” in the Condensed 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 Condensed Consolidated Statements of 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 Condensed Consolidated Statements of Comprehensive Income. For each period of the three months ended January 31, 2014 and 2013, these gas storage costs and the amounts we owed Pine Needle as of January 31, 2014 and October 31, 2013 are as follows.

	Three Months
In thousands	2014		2013
Gas storage costs	$	2,793	$	2,785

	January 31, 2014		October 31, 2013
Trade accounts payable	$	941	$	940

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 in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily in Georgia and Illinois. 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’s business is seasonal in nature as variations in weather conditions generally result in greater revenue and earnings during the winter months when weather is colder and natural gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings, wholesale price and weather volatility can cause variations in the timing of the recognition of 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 income (loss)” in “Stockholders’ equity” in the Condensed 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 Condensed Consolidated Statements of Comprehensive Income.

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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 Condensed Consolidated Statements of Comprehensive Income. For each period of the three months ended January 31, 2014 and 2013, our operating revenues from these sales and the amounts SouthStar owed us as of January 31, 2014 and October 31, 2013 are as follows.

	Three Months
In thousands	2014		2013
Operating revenues	$	432	$	(9	)

	January 31, 2014		October 31, 2013
Trade accounts receivable	$	463	$	441

Hardy Storage Company, LLC

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

We have related party transactions as a customer of Hardy Storage, and we record the storage costs charged by Hardy Storage in “Cost of Gas” in the Condensed Consolidated Statements of Comprehensive Income. For each period of the three months ended January 31, 2014 and 2013, these gas storage costs and the amounts we owed Hardy Storage as of January 31, 2014 and October 31, 2013 are as follows.

	Three Months
In thousands	2014		2013
Gas storage costs	$	2,425	$	2,425

	January 31, 2014		October 31, 2013
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. A subsidiary of The Williams Companies is the operator of the project. The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and 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 in total. As of January 31, 2014, our contributions for the first quarter of fiscal year 2014 were $10 million with our total equity contribution for the project totaling $25.9 million to date.

13. Variable Interest Entities

As of January 31, 2014, we have determined that we are not the primary beneficiary under variable interest entity (VIE) accounting guidance in any of our equity method investments, as discussed in Note 12 to the condensed 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

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impact the variable interest entity’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of January 31, 2014 and October 31, 2013, our investment balances are as follows.

In thousands	January 31, 2014		October 31, 2013
Cardinal	$	16,840	$	18,207
Pine Needle		19,685		20,270
SouthStar		45,661		38,372
Hardy Storage		34,797		34,681
Constitution		27,461		16,939
Total equity method investments in non-utility activities	$	144,444	$	128,469

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” in the Condensed Consolidated Statements of Comprehensive Income. Operations of the non-utility activities segment are included in the Condensed Consolidated Statements of Comprehensive Income in “Other Income (Expense)” 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, 2013.

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Operations by segment for the three months ended January 31, 2014 and 2013 are presented below.

In thousands	Regulated Utility				Non-utility Activities						Total
	2014		2013		2014			2013			2014		2013
Three Months
Revenues from external customers	$	657,733	$	515,875	$	-		$	-		$	657,733	$	515,875
Margin		261,512		231,623		-			-			261,512		231,623
Operations and maintenance expenses		60,639		55,882		29			59			60,668		55,941
Income from equity method investments		-		-		9,941			7,155			9,941		7,155
Operating income (loss) before income taxes		162,121		139,512		(109	)		(135	)		162,012		139,377
Income before income taxes		151,269		134,877		9,833			7,019			161,102		141,896

Reconciliations to the Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2014 and 2013 are presented below.

In thousands	Three Months
	2014			2013
Operating Income:
Segment operating income before income taxes	$	162,012		$	139,377
Utility income taxes		(59,802	)		(53,299	)
Non-utility activities before income taxes		109			135
Operating income	$	102,319		$	86,213
Net Income:
Income before income taxes for reportable segments	$	161,102		$	141,896
Income taxes		(63,530	)		(55,973	)
Net income	$	97,572		$	85,923

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 disclosure items related to regulatory matters, see Note 2 to the condensed consolidated financial statements in this Form 10-Q.

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

Forward-Looking Statements

This report, as well as other documents we file with the Securities and Exchange Commission (SEC), may contain forward-looking statements. In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others. These statements are based on management’s current expectations from information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to the following, as well as those discussed in Part II. Item 1A. Risk Factors in this Form 10-Q:

• Economic conditions in our markets

• Wholesale price of natural gas

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• 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

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

• Elevated levels of capital expenditures

• 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

• 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,” “may,” “should,” “could,” “assume,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.

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

Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, 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 regulated 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.

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We operate with two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. 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. Factors critical to the success of the regulated utility include operating a safe and 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. For further information on equity method investments and business segments, see Note 12 and Note 14, respectively, to the condensed consolidated financial statements in this Form 10-Q. The percentages of the assets as of January 31, 2014 and earnings before taxes by segments for the three months ended January 31, 2014 are presented below.

	Assets			Earnings Before Taxes
Regulated Utility		97	%		94	%
Non-utility Activities:
Regulated non-utility activities		2	%		2	%
Unregulated non-utility activities		1	%		4	%
Total non-utility activities		3	%		6	%

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 purchased for our customers and our operating expenses and to earn a fair rate of return on invested capital for our shareholders. 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. By continually assessing alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy, we file requests with our regulatory commissions to implement alternative rate structures and cost recovery mechanisms designed to allow us to recover certain costs through tracking mechanisms or riders without the need to file general base rate cases. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag through rate stabilization adjustment (RSA) tariffs, integrity management riders (IMRs) or similar mechanisms 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. This allows a better alignment of the interests of our shareholders and customers.

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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 RSA tariff mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. Under the RSA tariff mechanism, we reset 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 and when weather is significantly warmer than normal or colder than normal. With approval in North Carolina and Tennessee in December 2013, we have IMRs that separately track and recover, on an annual basis outside general rate cases, costs associated with capital expenditures to comply with pipeline safety and integrity requirements. The Tennessee IMR rate adjustment was recognized in earnings beginning in January 2014 with the North Carolina IMR to be recorded beginning in February 2014.

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. Through the use of various tariff mechanisms and fixed-rate contracts, we are able to achieve a higher degree of margin stabilization. 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, 2013. The following table presents the breakdown of our gas utility margin for the three months ended January 31, 2014.

	2014
Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers, IMRs and fixed-rate contracts)		67	%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)		21	%
Volumetric or periodic renegotiation		12	%
Total		100	%

Our long-term strategic directives shape our annual business objectives and focus on our customers, our communities, our employees and our shareholders. They also reflect what we believe are the inherent advantages of natural gas compared to other types of energy. Our seven foundational strategic priorities 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 service provider of choice,

• Achieve excellence in customer service every time,

• Preserve financial strength and flexibility,

• Execute sustainable business practices, and

• Enhance our healthy high performance culture

With a focus on these priorities, we believe we will enhance long-term shareholder value. For a full discussion of our strategy and focus areas, see “Our Strategies” in Item 1. Business in our Form 10-K for the year ended October 31, 2013.

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Executive Summary

A summary of the components of our comprehensive income, margin by customer class and operating statistics for the three months ended January 31, 2014 as compared with the three months ended January 31, 2013 is as follows.

Comprehensive Income Statement Components

	Three Months Ended January 31				Variance			Percent Change
In thousands, except per share amounts	2014		2013
Operating Revenues	$	657,733	$	515,875	$	141,858			27.5	%
Cost of Gas		396,221		284,252		111,969			39.4	%
Margin		261,512		231,623		29,889			12.9	%
Operations and Maintenance		60,639		55,882		4,757			8.5	%
Depreciation		29,643		26,701		2,942			11.0	%
General Taxes		9,109		9,528		(419	)		(4.4	)%
Utility Income Taxes		59,802		53,299		6,503			12.2	%
Total Operating Expenses		159,193		145,410		13,783			9.5	%
Operating Income		102,319		86,213		16,106			18.7	%
Other Income (Expense), net of tax		5,855		4,167		1,688			40.5	%
Utility Interest Charges		10,602		4,457		6,145			137.9	%
Net Income	$	97,572	$	85,923	$	11,649			13.6	%
Average Shares of Common Stock:
Basic		76,988		72,356		4,632			6.4	%
Diluted		77,327		72,725		4,602			6.3	%
Earnings Per Share of Common Stock:
Basic	$	1.27	$	1.19	$	0.08			6.7	%
Diluted	$	1.26	$	1.18	$	0.08			6.8	%

Margin by Customer Class

	Three Months Ended January 31
In thousands	2014				2013
Sales and Transportation:
Residential	$	144,226	55	%	$	137,914	60	%
Commercial		63,389	24	%		59,855	26	%
Industrial		15,795	6	%		16,330	7	%
Power Generation		19,555	8	%		10,115	4	%
For Resale		2,207	1	%		2,106	1	%
Total		245,172	94	%		226,320	98	%
Secondary Market Sales		14,020	5	%		3,313	1	%
Miscellaneous		2,320	1	%		1,990	1	%
Total	$	261,512	100	%	$	231,623	100	%

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Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Three Months Ended January 31
	2014			2013			Variance			Percent Change
Deliveries in Dekatherms (in thousands):
Residential		33,814			26,317			7,497			28.5	%
Commercial		19,111			14,743			4,368			29.6	%
Industrial		26,847			25,673			1,174			4.6	%
Power Generation		54,576			38,651			15,925			41.2	%
For Resale		2,790			2,564			226			8.8	%
Throughput		137,138			107,948			29,190			27.0	%
Secondary Market Volumes		9,103			16,347			(7,244	)		(44.3	)%
Customers Billed (at period end)		1,009,313			994,577			14,736			1.5	%
Gross Residential and Commercial Customer Additions		4,232			3,746			486			13.0	%
Degree Days
Actual		2,064			1,691			373			22.1	%
Normal		1,843			1,849			(6.0	)		(0.3	)%
Percent colder (warmer) than normal		12.0	%		(8.5	)%		n/a			n/a
Number of Employees (at period end)		1,788			1,744			44			2.5	%

Financial Performance – Quarter Ended 2014 Compared with Quarter 2013

We ended our first quarter with a 14% increase in net income. Margin increased 13% primarily due to higher margin sales from secondary market activity, transportation services under a power generation delivery contract, higher volumes delivered to residential and commercial customers due to colder weather, customer growth, new rates effective January 1, 2014 in North Carolina under a rate case settlement and the Tennessee IMR rate adjustment. Operations and maintenance (O&M) expenses and depreciation expense increased 9% and 11%, respectively. The increase in O&M expenses was related to increases in payroll from merit increases, employee overtime and incentive accruals and employee benefits from increased group medical insurance, partially offset by decreased pension expense. Depreciation was higher due to increases in plant in service from our capital expansion program, particularly related to system integrity and infrastructure investments and an investment to serve a new power generation customer. Other Income (Expense) increased 41% with an increase in income from equity method investments, including additional markets served by our SouthStar Energy Services LLC (SouthStar) joint venture. Utility interest charges increased 138% from increases in long-term debt outstanding, a decrease in capitalized interest recorded as income and interest charged on lower amounts due from customers.

Business Summary for the Current Quarter

Our performance for the three months ended January 31, 2014 reflects our continued focus on the execution of our long-term business strategy. As discussed above, financial performance was solid for the period with increased earnings from power generation customers and secondary market activity, supplemented by earnings from equity method investments.

Financial Strength and Flexibility – In order to prudently fund our investment in growth and our ongoing capital needs, we execute 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 with a goal of maintaining a long-term debt to capital ratio between 45% and 50%. To meet our short-term liquidity needs, we continue to rely on our commercial paper (CP) program.

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In November 2013, we entered into an agreement with our revolving credit facility lenders to increase our borrowing capacity to $850 million. We issued 1.6 million shares in December 2013 under forward sale agreements (FSAs) entered into in February 2013, receiving net proceeds of $47.3 million. For further information on these transactions, see Note 5 and Note 6 to the condensed consolidated financial statements in this Form 10-Q and the following discussion of “Cash Flows from Financing Activities.”

Customer Growth – We continued to increase our customer additions during the current quarter compared to the prior year period. With continued improvement in economic conditions and targeted marketing programs on the benefits of natural gas, total new customers increased quarter to quarter as presented below.

	2014		2013		Percent Change
Residential new home construction		2,949		2,482		18.8	%
Residential conversion		810		823		(1.6	)%
Commercial		473		441		7.3	%
Total new customers		4,232		3,746		13.0	%

We forecast gross customer growth of 1.5% for fiscal 2014. Overall, total net customers billed increased 1.4% for the three months ended January 31, 2014 as compared to the same period in 2013.

Capital Expenditures – We continued to execute our capital expansion programs 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. Our capital expenditures are being driven by expenditures for pipeline integrity, safety and compliance programs, and investments for customer growth and systems and technology infrastructure, including a new comprehensive work and asset management system.

With significant capital costs incurred under our ongoing system integrity programs, we have sought new regulatory mechanisms that will allow us to recover and earn on those investments in a timely manner. In December 2013, the NCUC approved the settlement of our 2013 general rate case, including the implementation of an IMR to separately track and recover the costs associated with capital expenditures in order to comply with federal pipeline safety and integrity requirements. Under the IMR tariff, we will make annual filings every November to capture such costs closed to plant through October with revised rates effective the following February. For the annual period beginning February 1, 2014, the North Carolina IMR will increase our margin revenues by $.8 million. With its approval of the rate case settlement, the NCUC continued to allow regulatory asset treatment of our external pipeline integrity management O&M costs and recovery of these costs through future amortization in rates. Also in December 2013, the TRA approved the settlement of our August 2013 filing for an IMR in Tennessee to recover the costs of our capital investments associated with federal and state mandated safety and integrity programs. Under the Tennessee IMR, we will file to adjust rates every January 1 based on capital expenditures incurred through the previous October. For the twelve-month period beginning January 1, 2014, the Tennessee IMR will increase our margin revenues by $13.1 million with $2.3 million recorded in this quarter.

Business Process and Technology Improvements – We are executing a multi-year, multi-project program designed to bring additional technology and automation to our field operations to enable our employees to more effectively and efficiently manage our pipeline assets. This program will create operating efficiencies and facilitate compliance with pipeline safety and integrity regulations, and implementation will begin in fiscal year 2014.

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Regulatory and Legislative Activity – With the NCUC approval of the settlement of our 2013 general rate case, we implemented adjustments in our rates and charges, effective January 1, 2014, to provide incremental annual total revenues of $30.7 million, yielding an annual pre-tax income increase of $24.2 million. This revenue increase is a .7% annual rate increase for our customers since our last general rate proceeding in 2008. The new rates are based on a rate base in North Carolina of $1.8 billion as of September 30, 2013, an equity capital structure component of 50.7% and a return on common equity of 10%.

Equity Method Investments – Our investments in complementary energy-related businesses continue to be an attractive way to generate earnings growth and long-term shareholder returns. We are a 24% equity member of Constitution Pipeline Company, LLC (Constitution), a proposed interstate natural gas pipeline that will transport natural gas produced from the Marcellus shale basin in Pennsylvania to northeast markets. The forecasted in-service date of the project has been extended to late 2015 or 2016 as a result of a longer than expected regulatory and permitting process. With an estimated total cost of $680 million, we expect our total 24% equity contributions will be an estimated $163 million. We contributed $10 million during the three months ended January 31, 2014 for a total of $25.9 million to date.

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

Additional information on operating results for the three months ended January 31, 2014 follows.

Operating Revenues

Changes in operating revenues for the three months ended January 31, 2014 compared with the same period in 2013 are presented below.

Changes in Operating Revenues - Increase (Decrease)

In millions	Three Months
Residential and commercial customers	$	146.2
Industrial customers		4.5
Power generation customers		9.8
Secondary market		24.0
Margin decoupling mechanism		(32.9	)
WNA mechanisms		(12.0	)
Integrity management rider		2.3
Total	$	141.9

• Residential and commercial customers – the increase is primarily due to higher consumption from colder weather, higher wholesale gas costs passed through to customers and customer growth.

• Industrial customers – the increase is primarily due to colder weather and higher wholesale gas costs passed through to customers.

• Power generation customers – the increase is primarily due to increased transportation services from a new contract placed into service in June 2013.

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• Secondary market – the increase is due to higher margin sales related to sustained colder-than-normal weather and increased wholesale market volatility. Secondary market transactions consist of off-system sales and capacity release and asset management 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 decrease is 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 is due to colder weather in South Carolina and Tennessee. As discussed in “Financial Condition and Liquidity,” the WNA mechanisms partially offset the impact of colder- or warmer-than-normal weather on bills rendered.

• Integrity management rider – the increase is due to the IMR rate adjustment in Tennessee effective as of January 1, 2014.

Cost of Gas

Changes in cost of gas for the three months ended January 31, 2014 compared with the same period in 2013 are presented below.

Changes in Cost of Gas - Increase (Decrease)

In millions	Three Months
Commodity gas costs passed through to sales customers	$	78.2
Commodity gas costs in secondary market transactions		13.3
Pipeline demand charges		4.4
Regulatory approved gas cost mechanisms		16.1
Total	$	112.0

• Commodity gas costs passed through to sales customers – the increase is primarily due to higher volumes sold due to colder weather and higher wholesale gas costs passed through to sales customers.

• Commodity gas costs in secondary market transactions – the increase is primarily due to increased average wholesale gas costs.

• Pipeline demand charges – the increase is due to increased demand costs and decreased asset manager payments, partially offset by increases in capacity release revenues.

• Regulatory approved gas cost mechanisms – the increase is primarily due to an increase in unbilled revenues due to the colder-than-normal temperatures as well as 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 in current “Regulatory assets” or current “Regulatory liabilities” in the Condensed Consolidated

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Balance Sheets. For the amounts included in “Amounts due from customers” or “Amounts due to customers,” see “Rate-Regulated Basis of Accounting” in Note 1 to the condensed consolidated financial statements in this Form 10-Q.

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the regulatory passthrough of changes in wholesale commodity 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 three months ended January 31, 2014, and our pipeline transportation and storage costs accounted for 6%.

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.

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 and the gas supply Incentive Plan in Tennessee and the IMR mechanism in Tennessee effective January 1, 2014, the margin decoupling mechanism in North Carolina and the North Carolina IMR mechanism effective February 1, 2014, negotiated margin 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 with our share of net gains or losses in Tennessee subject to an annual cap of $1.6 million.

Changes in margin for the three months ended January 31, 2014 compared with the same period in 2013 are presented below.

Changes in Margin – Increase (Decrease)

In millions	Three Months
Residential and commercial customers	$	9.9
Industrial customers		(.4	)
Power generation customers		9.4
Secondary market activity		10.7
Net gas cost adjustments		.3
Total	$	29.9

• Residential and commercial customers – the increase is primarily due to increased volumes delivered due to colder weather, the general rate case increase in North Carolina effective January 1, 2014 and customer growth in all three states.

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• Industrial customers – the decrease is primarily due to the change in cost allocation and rate design of industrial customers in North Carolina under the general rate case settlement effective January 1, 2014.

• Power generation customers – the increase is primarily due to increased transportation services due to a new contract placed in service in June 2013.

• Secondary market activity – the increase is due to higher margin sales related to sustained colder-than-normal weather and increased wholesale market volatility.

Operations and Maintenance Expenses

Changes in O&M expenses for the three months ended January 31, 2014 compared with the same period in 2013 are presented below.

Changes in Operations and Maintenance Expenses – Increase (Decrease)

In millions	Three Months
Payroll	$	2.1
Employee benefits		1.1
Other		1.6
Total	$	4.8

• Payroll – the increase is primarily due to merit increases, employee overtime and incentive plan accruals.

• Employee benefits – the increase is primarily due to group medical insurance expense from increases in medical costs and claims, partially offset by a decrease in pension expense.

Depreciation

Depreciation expense increased $2.9 million for the three months ended January 31, 2014 compared with the same period in 2013 primarily due to increases in plant in service, particularly related to new power generation customers and system integrity investments.

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 January 31, 2014 compared with the same period in 2013 was comparable.

The primary change to Other Income (Expense) for the three months ended January 31, 2014 compared with the same period in 2013 was income from equity method investments, primarily from SouthStar. Income from equity method investments from SouthStar increased $2.2 million primarily due to the expansion of the business

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into Illinois markets beginning in September 2013 and favorable customer mix and price spreads in the Georgia markets, partially offset by higher operating expenses. For further information on the contribution of the Illinois business to SouthStar and our cash contribution in our equity method investment, see Note 12 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2013.

Utility Interest Charges

Changes in utility interest charges for the three months ended January 31, 2014 compared with the same period in 2013 are presented below.

Changes in Utility Interest Charges – Increase (Decrease)

In millions	Three Months
Interest expense on long-term debt	$	2.9
Borrowed allowance for funds used during construction (AFUDC)		2.4
Regulatory interest expense		1.0
Other		(.2	)
Total	$	6.1

• Interest expense on long-term debt – the increase is primarily due to higher amounts of debt outstanding in the current period.

• Borrowed AFUDC – the increase is due to a decrease in capitalized interest primarily as a result of decreased construction expenditures in the current period.

• Regulatory interest expense, net – the increase is primarily due to lower interest income on lower amounts due from customers.

Financial Condition and Liquidity

Our financial strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities. The need for long-term capital is driven by the level of and timing of capital expenditures and long-term debt maturities. Our issuance of long-term debt and equity securities is subject to regulation by the NCUC.

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 investments in customer growth, pipeline integrity programs, system infrastructure and contributions to our joint ventures.

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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. If wholesale gas prices increase, we may incur more short-term debt for natural gas inventory and other operating costs since collections from customers could be slower and some customers may not be able to pay their gas bills on a timely basis.

We believe that the capacity of short-term credit available to us under our revolving syndicated credit facility and our 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.

Short-Term Debt. On November 1, 2013, we entered into an agreement with the lenders under our five-year revolving syndicated credit facility that expires in October 2017 to exercise an option which increased our borrowing capacity from $650 million to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount. The five-year revolving syndicated credit facility contains normal and customary financial covenants.

At January 31, 2014, we have an unsecured CP program that is backstopped by the revolving syndicated credit facility. In conjunction with the exercise of the option in November 2013, the amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt.

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We did not have any borrowings under the revolving syndicated credit facility for the three months ended January 31, 2014. Highlights for our short-term debt under our CP program as of January 31, 2014 and for the quarter ended January 31, 2014 are presented below.

In thousands
End of period (January 31, 2014):
Amount outstanding	$	570,000
Weighted average interest rate		.25	%
During the period (November 1, 2013 – January 31, 2014):
Average amount outstanding	$	506,800
Minimum amount outstanding		415,000
Maximum amount outstanding		625,000
Minimum interest rate		.23	%
Maximum interest rate		.43	%
Weighted average interest rate		.26	%
Maximum amount outstanding:
November 2013	$	460,000
December 2013		600,000
January 2014		625,000

As of January 31, 2014, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $1.8 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 January 31, 2014, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $278.2 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.

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

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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 decoupled tariffs and 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 $48.9 million and $12.6 million for the three months ended January 31, 2014 and 2013, respectively. Net cash provided by operating activities reflects an increase of $11.6 million in net income for 2014 compared with 2013 primarily due to increased margin, partially offset by higher operating expenses and utility interest charges. 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 $288.2 million from October 31, 2013 primarily due to colder weather and higher consumption of natural gas. Volumes sold to weather-sensitive residential and commercial customers increased 11.9 million dekatherms as compared with the same prior period primarily due to 22% colder weather in the current period. Total throughput increased 29.2 million dekatherms as compared with the same prior period, largely from 15.9 million dekatherms, or 41%, increased deliveries to power generation customers.

• Net amounts due from customers decreased $84.5 million from October 31, 2013 primarily due to margin decoupling and deferred gas costs collections through rates.

• Gas in storage decreased $7.9 million in the current period primarily due to decreased volumes of gas in storage from higher customer sales during the winter heating season of 2013-2014 due to colder weather as discussed above.

• Prepaid gas costs decreased $28.3 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.

• Trade accounts payable increased $78 million from October 31, 2013 primarily due to natural gas purchases for higher consumption due to colder weather as discussed above.

Primarily due to bonus depreciation, we generated a federal net operating loss (NOL) in our 2013 tax year. We anticipate that the carryforward of the 2013 NOL will completely offset our 2014 taxable income. We anticipate that we will generate future taxable income sufficient to utilize the portion of the 2013 NOL not used to offset our fiscal 2014 taxable income prior to the expiration of the loss carryforward period.

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 credits to customers of $7 million and charges to customers of $5 million in the three months ended January 31, 2014 and 2013, 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 “Regulatory Assets” or “Amounts due to customers” in “Regulatory Liabilities” in Note 1 to the condensed consolidated financial statements in this Form 10-Q 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 $25.6 million and increased margin by $7.3 million in the three months ended January 31, 2014 and 2013, 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 financial condition of the natural gas marketers and pipelines that supply and deliver natural gas to our distribution system can increase our exposure to supply and price fluctuations. We believe our risk exposure to the financial condition of the marketers and pipelines is not significant based on our receipt of the products and services prior to payment and the availability of other marketers of natural gas to meet our firm supply needs if necessary. We have regulatory commission approval in North Carolina, South Carolina and Tennessee that places tighter credit requirements on the retail natural gas marketers that schedule gas for transportation service on our system.

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

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

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

Cash Flows from Investing Activities. Net cash used in investing activities was $138.4 million and $153 million for the three months ended January 31, 2014 and 2013, respectively. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures for the three months ended January 31, 2014 were $125 million primarily for system integrity projects as compared to $137.2 million in the same prior period, which included expenditures for system integrity projects and the construction of power generation delivery 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 continue to spend large amounts 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.

Detail of our forecasted 2014 – 2016 capital expenditures, including AFUDC, is presented below. 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.

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In millions	2014		2015		2016
Customer growth and other	$	200	$	190	$	190
System integrity		250		225		215
Total forecasted capital expenditures	$	450	$	415	$	405

Our estimates for utility capital expenditures associated with system integrity have increased compared to similar expenditures in years prior to our fiscal year 2013. 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 expenditures in 2014 also include costs associated with the replacement of a major transmission line in Nashville, the construction of which began in 2013.

We are a 24% equity member of Constitution, a Delaware limited liability company. The purpose of the joint venture is to develop, construct, own and operate approximately 120 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and 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 in total. As of January 31, 2014, our contributions were $10 million for the first quarter of our fiscal year 2014 with our total equity contribution for the project totaling $25.9 million to date. The forecasted in-service date of the project has been extended to late 2015 to 2016 as a result of a longer than expected regulatory and permitting process. With the revised forecasted in-service date, we now expect our equity contributions will be an estimated $40 million, $89 million, and $18.1 million in our fiscal years 2014, 2015 and 2016, respectively. For further information regarding this agreement, see Note 12 to the condensed consolidated financial statements in this Form 10-Q.

Cash Flows from Financing Activities. Net cash provided by financing activities was $97.7 million and $149 million for the three months ended January 31, 2014 and 2013, respectively. Funds are primarily provided from long-term debt securities, short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). 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. In recent years, bonus depreciation has been a source of funds in that it has decreased our federal income tax payments.

Outstanding debt under our CP program increased from $400 million as of October 31, 2013 to $570 million as of January 31, 2014 primarily due to increased utility capital expenditures, natural gas purchases and investments in one of our equity method investments, partially offset by the net proceeds received from the issuance of our common stock. On November 1, 2013, we entered into an agreement with the lenders to increase the aggregate commitment of our five-year revolving syndicated credit facility from $650 million to $850 million. Our revolving credit facility expires on October 1, 2017. Our unsecured CP program is backstopped by this credit facility. For further information on short-term debt, see Note 5 to the condensed consolidated financial statements in this Form 10-Q and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”

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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. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities. We plan to issue new long-term debt and equity capital over fiscal years 2014 and 2015, at such amounts to support our capital investment program and maintain our target capital structure of 45 – 50% in long-term debt and 50 – 55% in common equity.

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 of which 3 million direct shares were issued and settled on February 4, 2013 with net proceeds of $92.6 million received. The shares were purchased by the underwriters at the net price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share.

Under this same underwriting agreement, we had two FSAs totaling 1.6 million shares that had to be settled no later than mid December 2013. Under the terms of these FSAs, at our election, we could physically settle in shares, cash or net share settle for all or a portion of our obligation under the agreements. On December 16, 2013, we physically settled the FSAs by issuing 1.6 million shares of our common stock to the forward counterparty and received net proceeds of $47.3 million based on the net settlement price of $30.88 per share, the original offering price, less certain adjustments.

We used the net proceeds from the equity transactions discussed above to finance capital expenditures, repay outstanding unsecured notes under the CP program and for general corporate purposes. For further information on our common stock and for more details on these equity issuance transactions, see Note 6 to the condensed 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. We repaid the balance of $100 million of our 5% medium-term notes in December 2013 as they became due. For further information on our long-term debt instruments, see Note 4 to the condensed consolidated financial statements in this Form 10-Q.

From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2 in this Form 10-Q. We do not anticipate repurchasing any of our common stock in our fiscal year 2014.

During the three months ended January 31, 2014 and 2013, we issued $4.9 million and $5.7 million, respectively, of common stock through DRIP and ESPP.

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 January 31, 2014, our retained earnings were not restricted. On March 6, 2014, the Board of Directors declared a quarterly dividend on common stock of $.32 per share, payable April 15, 2014 to shareholders of record at the close of business on March 25, 2014.

Our long-term targeted capitalization ratio is 45 – 50% in long-term debt and 50 – 55% in common equity. As of January 31, 2014, our capitalization, including current maturities of long-term debt, if any, consisted of 47% in long-term debt and 53% in common equity.

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The components of our total debt outstanding (short-term debt and long-term debt) to our total capitalization as of January 31, 2014 and 2013, and October 31, 2013, are summarized in the table below.

	January 31					October 31					January 31
In thousands	2014		Percentage			2013		Percentage			2013		Percentage
Short-term debt	$	570,000		19	%	$	400,000		14	%	$	530,000		20	%
Current portion of long-term debt		-		-	%		100,000		3	%		100,000		4	%
Long-term debt		1,174,858		38	%		1,174,857		41	%		875,000		34	%
Total debt		1,744,858		57	%		1,674,857		58	%		1,505,000		58	%
Common stockholders’ equity		1,316,744		43	%		1,188,596		42	%		1,098,810		42	%
Total capitalization (including short-term debt)	$	3,061,602		100	%	$	2,863,453		100	%	$	2,603,810		100	%

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

The lenders under our revolving credit facility and our CP program are major financial institutions, all of which have investment grade credit ratings as of January 31, 2014. 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 January 31, 2014, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P), and Moody’s Investors Service (Moody’s) has upgraded our rating to “A2” from “A3.” Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P has issued a credit rating on our CP program at “A1,” and Moody’s has upgraded our credit rating to “P1” from “P2.” 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 conservative 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 the 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 January 31, 2014, there has been no event of default giving rise to acceleration of our debt.

Estimated Future Contractual Obligations

During the three months ended January 31, 2014, there were no material changes to our estimated future contractual obligations in Management’s Discussion and Analysis in this Form 10-Q compared to the disclosure provided in our Form 10-K for the year ended October 31, 2013.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than letters of credit and operating leases. The letters of

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credit are discussed in Note 5 to the condensed 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, 2013.

Critical Accounting Policies and Estimates

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

Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made, and changes in the estimate or a different estimate that could have been used would have had a material impact on our financial condition or results of operations. We consider regulatory accounting, revenue recognition, and pension and postretirement benefits to be our critical accounting estimates. Management is responsible for the selection of these critical accounting estimates presented in our Form 10-K for the year ended October 31, 2013 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, 2013.

Accounting Guidance

For information regarding recently issued accounting guidance, see Note 1 to the condensed 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 and also an 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 three months ended January 31, 2014, 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 three months ended January 31, 2014. Our annual discussion of market risk was included in Item 7A of our Form 10-K as of October 31, 2013.

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 January 31, 2014, we had $570 million of short-term debt outstanding as commercial paper at an interest rate of .25%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $1.3 million during the three months ended January 31, 2014.

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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 first quarter of fiscal 2014 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 three months ended January 31, 2014, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2013.

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

c) Issuer Purchases of Equity Securities.

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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 January 31, 2014.

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
11/1/13 – 11/30/13		-	$	-		-		2,910,074
12/1/13 – 12/31/13		-	$	-		-		2,910,074
1/1/14 – 1/31/14		-	$	-		-		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 January 31, 2014, 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	Increasing Lender Agreement dated as of November 1, 2013 among Wells Fargo Bank, National Association, Bank of America, N.A., Branch Banking and Trust Company, JPMorgan Chase Bank, N.A., PNC Bank, National Association, U.S. Bank National Association and Royal Bank of Canada, each as a Lender (incorporated by reference to Exhibit 10.1, Form 8-K dated November 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	Piedmont Natural Gas Company, Inc. 401(k) Plan, Amended and Restated as of January 1, 2013, dated January 28, 2014.
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) Condensed Consolidated Balance Sheets at January 31, 2014 and October 31, 2013; (3) Condensed Consolidated Statements of Comprehensive Income for the three months ended January 31, 2014 and 2013; (4) Condensed Consolidated Statements of Cash Flows for the three months ended January 31, 2014 and 2013; (5) Condensed Consolidated Statements of Stockholders’ Equity for the three months ended January 31, 2014 and 2013; and (6) Notes to Condensed 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 March 6, 2014	/s/ Karl W. Newlin
	Karl W. Newlin
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

Date March 6, 2014	/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 January 31, 2014

Exhibits

31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
99.1	Piedmont Natural Gas Company, Inc. 401(k) Plan, Amended and Restated as of January 1, 2013, dated January 28, 2014.