PIEDMONT NATURAL GAS CO INC - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - PIEDMONT NATURAL GAS CO INC	Financial_Report.xls
EX-31.1 - EX-31.1 - PIEDMONT NATURAL GAS CO INC	a2014731exhibit311.htm
EX-31.2 - EX-31.2 - PIEDMONT NATURAL GAS CO INC	a2014731exhibit312.htm
EX-32.1 - EX-32.1 - PIEDMONT NATURAL GAS CO INC	a2014731exhibit321.htm
EX-32.2 - EX-32.2 - PIEDMONT NATURAL GAS CO INC	a2014731exhibit322.htm
EX-10.1 - EX-10.1 - PIEDMONT NATURAL GAS CO INC	a2014731exhibit101.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended July 31, 2014

¨ 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. ýYes ¨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). ýYes ¨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 o
Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

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



Class		Outstanding at September 2, 2014
Common Stock, no par value		78,339,849

Table of Contents

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

July 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	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	45

Part II.	Other Information

Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6.	Exhibits	46

	Signatures	47

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Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)



	July 31, 2014		October 31, 2013
ASSETS
Utility Plant:
Utility plant in service	$	4,896,850	$	4,421,937
Less accumulated depreciation	1,147,480		1,088,331
Utility plant in service, net	3,749,370		3,333,606
Construction work in progress	157,476		297,717
Plant held for future use	3,155		3,155
Total utility plant, net	3,910,001		3,634,478
Other Physical Property, at cost (net of accumulated depreciation of $897 in 2014 and $876 in 2013)	362		382
Current Assets:
Cash and cash equivalents	18,449		8,063
Trade accounts receivable (less allowance for doubtful accounts of $3,646 in 2014 and $1,604 in 2013)	75,780		79,210
Income taxes receivable	26,023		31,065
Other receivables	4,098		1,988
Unbilled utility revenues	8,946		24,967
Inventories:
Gas in storage	79,149		73,929
Materials, supplies and merchandise	1,695		1,725
Gas purchase derivative assets, at fair value	1,023		1,834
Regulatory assets	28,715		77,204
Prepayments	33,595		35,038
Deferred income taxes	30,452		12,695
Other current assets	434		338
Total current assets	308,359		348,056
Noncurrent Assets:
Equity method investments in non-utility activities	163,473		128,469
Goodwill	48,852		48,852
Regulatory assets	170,624		169,102
Marketable securities, at fair value	3,642		2,995
Overfunded postretirement asset	48,183		28,258
Other noncurrent assets	5,963		8,017
Total noncurrent assets	440,737		385,693
Total	$	4,659,459	$	4,368,609

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)



	July 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: 78,327 in 2014 and 76,099 in 2013	629,896			561,644
Retained earnings	706,016			627,236
Accumulated other comprehensive loss	(108		)	(284		)
Total stockholders’ equity	1,335,804			1,188,596
Long-term debt	1,174,861			1,174,857
Total capitalization	2,510,665			2,363,453
Current Liabilities:
Current maturities of long-term debt	—			100,000
Short-term debt	490,000			400,000
Trade accounts payable	85,150			96,281
Other accounts payable	39,528			43,855
Income taxes accrued	595			—
Accrued interest	19,543			28,205
Customers’ deposits	20,051			19,831
General taxes accrued	16,909			21,454
Regulatory liabilities	61,956			—
Other current liabilities	7,326			7,024
Total current liabilities	741,058			716,650
Noncurrent Liabilities:
Deferred income taxes	786,479			681,369
Unamortized federal investment tax credits	1,240			1,402
Accumulated provision for postretirement benefits	11,925			12,042
Regulatory liabilities	553,030			541,897
Conditional cost of removal obligations	28,169			27,016
Other noncurrent liabilities	26,893			24,780
Total noncurrent liabilities	1,407,736			1,288,506
Commitments and Contingencies (Note 9)
Total	$	4,659,459		$	4,368,609

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands, except per share amounts)



	Three Months Ended July 31						Nine Months Ended July 31
	2014			2013			2014			2013
Operating Revenues	$	164,187		$	162,943		$	1,284,167		$	1,078,229
Cost of Gas	59,340			65,943			706,285			565,749
Margin	104,847			97,000			577,882			512,480
Operating Expenses:
Operations and maintenance	68,605			62,950			199,437			183,869
Depreciation	29,960			28,599			87,947			82,168
General taxes	9,352			8,307			27,958			26,903
Utility income taxes	(6,324		)	(3,447		)	89,668			81,232
Total operating expenses	101,593			96,409			405,010			374,172
Operating Income	3,254			591			172,872			138,308
Other Income (Expense):
Income from equity method investments	5,043			3,652			29,345			23,244
Non-operating income	862			667			66			1,857
Non-operating expense	(1,660		)	(897		)	(3,711		)	(2,355		)
Income taxes	(1,718		)	(603		)	(10,050		)	(8,152		)
Total other income (expense)	2,527			2,819			15,650			14,594
Utility Interest Charges:
Interest on long-term debt	14,920			12,656			45,416			37,983
Allowance for borrowed funds used during construction	(4,543		)	(7,507		)	(15,960		)	(25,758		)
Other	2,748			554			6,298			1,257
Total utility interest charges	13,125			5,703			35,754			13,482
Net Income (Loss)	(7,344		)	(2,293		)	152,768			139,420
Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($7) and ($21) for the three months ended July 31, 2014 and 2013, respectively, and $328 and $17 for the nine months ended July 31, 2014 and 2013, respectively	(10		)	(36		)	516			23
Reclassification adjustment of realized gain (loss) from hedging activities of equity method investments included in net income, net of tax of ($59) and ($33) for the three months ended July 31, 2014 and 2013, respectively, and ($199) and $30 for the nine months ended July 31, 2014 and 2013, respectively	(93		)	(52		)	(315		)	45
Net current period benefit activities of equity method investments, net of tax of ($16) for the three months ended July 31, 2014 and ($16) for the nine months ended July 31, 2014	(25		)				(25		)
Total other comprehensive income (loss)	(128		)	(88		)	176			68
Comprehensive Income (Loss)	$	(7,472	)	$	(2,381	)	$	152,944		$	139,488
Average Shares of Common Stock:
Basic	78,185			75,774			77,715			74,521
Diluted	78,185			75,774			78,027			74,987
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.09	)	$	(0.03	)	$	1.97		$	1.87
Diluted	$	(0.09	)	$	(0.03	)	$	1.96		$	1.86

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)



	Nine Months Ended July 31
	2014			2013
Cash Flows from Operating Activities:
Net income	$	152,768		$	139,420
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	95,550			87,250
Allowance for doubtful accounts	2,042			1,252
Net gain on sale of property	(75		)	(18		)
Income from equity method investments	(29,345		)	(23,244		)
Distributions of earnings from equity method investments	17,443			18,464
Deferred income taxes, net	87,078			65,015
Changes in assets and liabilities:
Gas purchase derivatives, at fair value	811			2,170
Receivables	15,376			(4,565		)
Inventories	(5,190		)	3,799
Settlement of legal asset retirement obligations	(2,284		)	(1,784		)
Other assets	53,590			34,004
Accounts payable	(9,670		)	(26,551		)
Provision for postretirement benefits, net	(20,042		)	(19,459		)
Other liabilities	55,985			10,118
Net cash provided by operating activities	414,037			285,871
Cash Flows from Investing Activities:
Utility capital expenditures	(348,416		)	(443,312		)
Allowance for borrowed funds used during construction	(15,960		)	(25,758		)
Contributions to equity method investments	(31,872		)	(15,008		)
Distributions of capital from equity method investments	9,060			5,980
Proceeds from sale of property	792			891
Investments in marketable securities	(550		)	(477		)
Other	1,685			2,198
Net cash used in investing activities	(385,261		)	(475,486		)

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)



	Nine Months Ended July 31
	2014			2013
Cash Flows from Financing Activities:
Borrowings under credit facility	$	—		$	10,000
Repayments under credit facility	—			(10,000		)
Net borrowings – commercial paper	90,000			150,000
Repayment of long-term debt	(100,000		)	—
Expenses related to issuance of debt	(456		)	(151		)
Proceeds from issuance of common stock, net of expenses	47,290			92,282
Issuance of common stock through dividend reinvestment and employee stock plans	18,840			18,890
Dividends paid	(74,076		)	(68,605		)
Other	12			21
Net cash (used in) provided by financing activities	(18,390		)	192,437
Net Increase in Cash and Cash Equivalents	10,386			2,822
Cash and Cash Equivalents at Beginning of Period	8,063			1,959
Cash and Cash Equivalents at End of Period	$	18,449		$	4,781
Cash Paid During the Year for:
Interest	$	55,998		$	48,982
Income Taxes:
Income taxes paid	$	6,867		$	5,267
Income taxes refunded	19			—
Income taxes, net	$	6,848		$	5,267
Noncash Investing and Financing Activities:
Accrued capital expenditures	$	33,491		$	44,701

See notes to condensed consolidated financial statements.

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Piedmont Natural Gas Company, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands, except per share amounts)



								Accumulated
								Other
	Common Stock				Retained			Comprehensive
	Shares	Amount			Earnings			Income (Loss)				Total
Balance, October 31, 2012	72,250	$	442,461		$	584,848		$	(305	)	$	1,027,004
Net Income					139,420						139,420
Other Comprehensive Income								68			68
Common Stock Issued	3,667	113,832									113,832
Expenses from Issuance of Common Stock		(358		)							(358		)
Tax Benefit from Dividends Paid on ESOP Shares					88						88
Dividends Declared ($.92 per share)					(68,605		)				(68,605		)
Balance, July 31, 2013	75,917	$	555,935		$	655,751		$	(237	)	$	1,211,449

Balance, October 31, 2013	76,099	$	561,644		$	627,236		$	(284	)	$	1,188,596
Net Income					152,768						152,768
Other Comprehensive Income								176			176
Common Stock Issued	2,228	68,264									68,264
Expenses from Issuance of Common Stock		(12		)							(12		)
Tax Benefit from Dividends Paid on ESOP Shares					88						88
Dividends Declared ($.95 per share)					(74,076		)				(74,076		)
Balance, July 31, 2014	78,327	$	629,896		$	706,016		$	(108	)	$	1,335,804

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 July 31, 2014 and October 31, 2013, the results of operations for three months and nine months ended July 31, 2014 and 2013, and cash flows and stockholders’ equity for the nine months ended July 31, 2014 and 2013. Our business is seasonal in nature. The results of operations for the three months and nine months ended July 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, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of 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, which are evaluated on a continual basis.

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 nine months ended July 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. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of regulatory assets and regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive 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.

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Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of July 31, 2014 and October 31, 2013 are as follows.



In thousands	July 31, 2014		October 31, 2013
Regulatory Assets:
Current:
Unamortized debt expense	$	1,383	$	1,274
Amounts due from customers	16,304		66,321
Environmental costs	1,558		1,480
Deferred operations and maintenance expenses	916		739
Deferred pipeline integrity expenses	3,470		3,149
Deferred pension and other retirement benefit costs	2,769		2,768
Robeson liquefied natural gas (LNG) development costs	382		382
Other	1,933		1,091
Total current	28,715		77,204
Noncurrent:
Unamortized debt expense	13,524		14,149
Environmental costs	6,801		7,936
Deferred operations and maintenance expenses	4,911		5,637
Deferred pipeline integrity expenses	22,420		16,300
Deferred pension and other retirement benefit costs	19,488		17,968
Amounts not yet recognized as a component of pension and other retirement benefit costs	76,371		80,604
Regulatory cost of removal asset	24,213		22,974
Robeson LNG development costs	1,140		1,426
Other	1,756		2,108
Total noncurrent	170,624		169,102
Total	$	199,339	$	246,306



Regulatory Liabilities:
Current:
Amounts due to customers	$	61,956	$	—
Noncurrent:
Regulatory cost of removal obligations	502,557		493,111
Deferred income taxes	50,345		48,647
Amounts not yet recognized as a component of pension and other retirement benefit costs	128		139
Total noncurrent	553,030		541,897
Total	$	614,986	$	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.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value in the Condensed Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year.

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Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that 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 derivative 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 July 31, 2014.

Recently Issued Accounting Guidance

In July 2013, the Financial Accounting Standards Board (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 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.

In May 2014, the FASB and the International Accounting Standards Board issued converged accounting guidance on the recognition of revenue from contracts with customers. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. The new guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those periods, which for us is our fiscal year 2018. We are currently evaluating the effect on our financial position, results of operations and cash flows.

In June 2014, the FASB amended accounting guidance to eliminate certain financial reporting requirements for development stage entities, including an amendment to variable interest entity (VIE) guidance. The modification to the guidance may change the consolidation analysis, consolidation decision and disclosure requirements for a reporting entity that has an interest in an entity in the development stage. The amendments in the update are effective for annual periods, and interim periods within those periods, beginning after December 15, 2015, with early adoption permitted. We will consider this guidance regarding one of our current joint venture investments where the investment infrastructure is under development and any future investments that are development stage projects, particularly any disclosures about risks and uncertainties of the development of the project and our equity method investment.


2.	Regulatory Matters

North Carolina

In April 2014, we filed a petition with the North Carolina Utilities Commission (NCUC) for a limited waiver of certain billing provisions of our tariff related to emergency service and unauthorized gas taken by customers in January 2014. A hearing was held on June 17, 2014. On August 11, 2014, we and the NCUC Public Staff filed a joint stipulation of settlement. The terms of the settlement include the granting of a waiver of the commodity index pricing mechanism for January 2014, that we should not be penalized for our conduct in varying from the tariff in this instance as that conduct was solely for the benefit of our

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customers, and that we and the Public Staff would work together to develop mutually agreeable revisions to our tariff to address the situation that led to this petition. We are waiting on a ruling from the NCUC at this time.

In August 2014, we filed testimony with the NCUC in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2014. A hearing has been scheduled for October 7, 2014. We are waiting on a ruling from the NCUC at this time.

South Carolina

In June 2014, we filed testimony with the Public Service Commission of South Carolina (PSCSC) in support of our annual review of purchased gas adjustment (PGA) and gas purchasing policies for the twelve months ended March 31, 2014. In July 2014, a settlement agreement with the Office of Regulatory Staff (ORS) was filed in this matter. On August 6, 2014, the PSCSC approved the settlement agreement, finding that our gas purchasing policies and practices were reasonable and prudent, that we properly adhered to the gas cost recovery provisions of our tariff and relevant PSCSC orders and that we managed our hedging program in a manner consistent with PSCSC orders. The PSCSC issued its order on this matter on August 12, 2014.

In June 2014, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2014 and a cost and revenue study under the Rate Stabilization Act requesting a change in rates. On September 3, 2014, a settlement agreement with the ORS was filed with the PSCSC that stipulates a $2.9 million annual decrease in margin based on a return on equity of 10.2%, effective November 1, 2014. We are waiting on a ruling from the PSCSC at this time.

In July 2014, we filed a petition with the PSCSC requesting a limited waiver of certain billing provisions of our tariff related to emergency service for customers in January 2014. On August 6, 2014, the PSCSC granted our request and ordered us to continue to collaborate with the ORS to revise our tariff to address the situation that led to this petition. The PSCSC issued its written order on this matter on August 21, 2014.

Tennessee

In August 2013, we filed a petition with the Tennessee Regulatory Authority (TRA) seeking authority to implement an integrity management rider (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 and the Tennessee Attorney General’s Consumer Advocate Division filed an IMR settlement with the TRA. A hearing on this matter was held December 18, 2013, and the TRA approved the IMR settlement as filed. A written order was issued May 13, 2014.

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.

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.

In August 2014, 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, 2014 under the Tennessee Incentive Plan (TIP). We are waiting on a ruling from the TRA at this time.

In September 2014, we filed a petition with the TRA seeking authority to implement a compressed natural gas infrastructure rider to recover the costs of our capital investments in infrastructure and equipment associated with this alternative motor vehicle transportation fuel. We proposed that the rider be effective October 1, 2014 with an initial rate adjustment on November 1, 2014 based on capital expenditures incurred through June 2014 and for rates to be updated annually outside of general rate cases for the return of and on these capital investments. We are waiting on a ruling from the TRA at this time.


3.	Earnings per Share

We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive

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compensation plans are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS. A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest or stock agreements settle, for the three months and nine months ended July 31, 2014 and 2013 is presented below.



	Three Months						Nine Months
In thousands, except per share amounts	2014			2013			2014		2013
Net Income (Loss)	$	(7,344	)	$	(2,293	)	$	152,768	$	139,420

Average shares of common stock outstanding for basic earnings per share	78,185			75,774			77,715		74,521
Contingently issuable shares under incentive compensation plans *	—			—			312		330
Contingently issuable shares under forward sale agreements **				—					136
Average shares of dilutive stock	78,185			75,774			78,027		74,987
Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.09	)	$	(0.03	)	$	1.97	$	1.87
Diluted	$	(0.09	)	$	(0.03	)	$	1.96	$	1.86

* For the three months ended July 31, 2014 and 2013, the inclusion of 301 and 316 contingently issuable shares under incentive compensation plans, respectively, would have been antidilutive.

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


4.	Long-Term Debt Instruments

We 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.


5.	Short-Term Debt Instruments

We have an $850 million five-year revolving syndicated credit facility that expires on October 1, 2017. 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 July 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 $850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. 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 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 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 July 31, 2014, we had $490 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 60 days from their dates of issuance at a weighted average interest rate of .17%. 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.

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



In millions	Three Months			Nine Months
Minimum amount outstanding during period	$	330		$	325
Maximum amount outstanding during period	$	495		$	625
Minimum interest rate during period	.11		%	.10		%
Maximum interest rate during period	.18		%	.43		%
Weighted average interest rate during period	.16		%	.20		%

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%. At July 31, 2014, our actual ratio was 56%.


6.	Stockholders’ Equity

Capital Stock

Changes in common stock for the nine months ended July 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)	25	832
Issued to the Dividend Reinvestment and Stock Purchase Plan	510	17,084
Issued to participants in the Incentive Compensation Plan (ICP)	93	3,046
Issued through forward sale agreements, net of expenses	1,600	47,290
Balance, July 31, 2014	78,327	$	629,896

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



	Three Months				Nine Months
	2014		2013		2014		2013
Cash dividends paid per share of common stock	$	0.32	$	0.31	$	0.95	$	0.92

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. Beginning this quarter, another component of our accumulated OCIL is the allocation of retirement benefits to SouthStar Energy Services, LLC (SouthStar) by its majority member. Changes in each component of accumulated OCIL are presented below for the three months and nine months ended July 31, 2014 and 2013.

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	Changes in Accumulated OCIL⁽¹⁾
	Three Months						Nine Months
In thousands	2014			2013			2014			2013
Accumulated OCIL beginning balance, net of tax	$	20		$	(149	)	$	(284	)	$	(305	)
Hedging activities of equity method investments:
OCIL before reclassifications, net of tax	(10		)	(36		)	516			23
Amounts reclassified from accumulated OCIL, net of tax	(93		)	(52		)	(315		)	45
Total current period activity of hedging activities of equity method investments, net of tax	(103		)	(88		)	201			68
Net current period benefit activities of equity method investments, net of tax	(25		)				(25		)
Accumulated OCIL ending balance, net of tax	$	(108	)	$	(237	)	$	(108	)	$	(237	)

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

A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the three months and nine months ended July 31, 2014 and 2013.



	Reclassification Out of Accumulated OCIL ⁽¹⁾												Affected Line Items on Condensed Statements of Operations and Comprehensive Income
	Three Months						Nine Months
In thousands	2014			2013			2014			2013
Hedging activities of equity method investments	$	(152	)	$	(85	)	$	(514	)	$	75		Income from equity method investments
Income tax expense	59			33			199			(30		)	Income taxes
Hedging activities of equity method investments	(93		)	(52		)	(315		)	45
Net benefit activities of equity method investments	(41		)				(41		)				Income from equity method investments
Income tax expense	16						16						Income taxes
Net benefit activities of equity method investments	(25		)				(25		)
Total reclassification for the period, net of tax	$	(118	)	$	(52	)	$	(340	)	$	45

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


7.	Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 10 to the 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 asset portion is 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 July 31, 2014 and October 31, 2013 is as follows.



	July 31, 2014				October 31, 2013
In thousands	Cost		Fair Value		Cost		Fair Value
Current trading securities:
Money markets	$	22	$	22	$	—	$	—
Mutual funds	172		286		134		199
Total current trading securities	194		308		134		199
Noncurrent trading securities:
Money markets	452		452		380		380
Mutual funds	2,574		3,190		1,995		2,615
Total noncurrent trading securities	3,026		3,642		2,375		2,995
Total trading securities	$	3,220	$	3,950	$	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 July 31, 2014 and October 31, 2013, we had long gas purchase options providing total coverage of 10.8 million dekatherms and 25.4 million dekatherms, respectively. The long gas purchase options held at July 31, 2014 are for the period from September 2014 through July 2015.

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 July 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 may affect the valuation of fair value assets and liabilities and their consideration within the fair value hierarchy levels. We have had no transfers between any level during the three months ended July 31, 2014 and 2013. We present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of purchased call options held for our utility operations. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our derivatives held for utility operations. Our derivatives held for utility operations are held with one broker as our counterparty.

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Recurring Fair Measurements as of July 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	$	1,023	$	—	$	—	$	—	$	1,023
Debt and equity securities held as trading securities:
Money markets	474		—		—		—		474
Mutual funds	3,476		—		—		—		3,476
Total fair value assets	$	4,973	$	—	$	—	$	—	$	4,973

Recurring Fair 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 PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due 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.

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 July 31, 2014	$	1,175,000	$	1,327,019
As of October 31, 2013	1,275,000		1,409,892

* Excludes discount on issuance of notes of $139 and $143 as of July 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

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accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value of our financial options is presented on a gross basis with only asset positions for all periods presented. There are no derivative contracts in a liability position, and we have posted no cash collateral nor received any cash collateral under our master netting arrangements; therefore, we have no offsetting disclosures for financial assets or liabilities for our financial option derivatives.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of July 31, 2014 and October 31, 2013.

Fair Value of Derivative Instruments

	July 31,		October 31,
In thousands	2014		2013
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets – Gas purchase derivative assets (September 2014-July 2015)	$	1,023
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 are to use these financial instruments to reduce gas cost volatility for our customers. 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 from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in Note 1 to the condensed consolidated financial statements and recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income as a component of “Cost of Gas” when the related costs are recovered through our rates.

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



In thousands	Amount of Gain (Loss) Recognized on Derivatives and Deferred Under PGA Procedures											Location of Gain (Loss) Recognized through PGA Procedures
	Three Months Ended July 31						Nine Months Ended July 31
	2014			2013			2014		2013
Gas purchase options	$	(515	)	$	(829	)	$	7,311	$	(5,120	)	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 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.

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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 $2.8 million, or approximately 4%, of our gross trade accounts receivable at July 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, our policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

We also enter into contracts with third parties to manage some of our supply and capacity assets for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is unable to perform under these arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations that were incurred while under the management of this third party. We believe, based on our credit policies as of July 31, 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.

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, which is overseen by the Finance and Enterprise Risk Committee of our Board of Directors. 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-one years. The time periods for gas supply contracts are up to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to five 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 Operations and Comprehensive Income as part of gas purchases and included in “Cost of Gas.”

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Leases

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

Legal

We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect, 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 July 31, 2014. Additional information concerning letters of credit is included in Note 5 to the condensed consolidated financial statements in this Form 10-Q.

Surety Bonds

In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of July 31, 2014, we had open surety bonds with a total contingent obligation of $4.7 million.

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 nine months ended July 31, 2014.

As of July 31, 2014, our estimated undiscounted environmental liability totaled $1.2 million and consisted of $1.1 million for manufactured gas production sites for which we retain remediation responsibility and $.1 million for our Huntersville LNG facility 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 July 31, 2014 and 2013 are presented below.



	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2014			2013			2014		2013		2014			2013
Service cost	$	2,600		$	2,704		$	—	$	—	$	277		$	332
Interest cost	2,950			2,509			45		39		362			282
Expected return on plan assets	(5,475		)	(5,229		)	—		—		(457		)	(416		)
Amortization of transition obligation	—			—			—		—		—			167
Amortization of prior service (credit) cost	(550		)	(548		)	20		21		—			—
Amortization of actuarial loss	2,025			2,901			12		40		—			—
Total	$	1,550		$	2,337		$	77	$	100	$	182		$	365

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2014 and 2013 are presented below.



	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2014			2013			2014		2013		2014			2013
Service cost	$	8,100		$	9,004		$	—	$	—	$	831		$	995
Interest cost	8,850			7,459			135		118		1,086			848
Expected return on plan assets	(16,875		)	(15,829		)	—		—		(1,372		)	(1,247		)
Amortization of transition obligation	—			—			—		—		—			500
Amortization of prior service (credit) cost	(1,650		)	(1,648		)	61		61		—			—
Amortization of actuarial loss	5,775			8,401			35		120		—			—
Total	$	4,200		$	7,387		$	231	$	299	$	545		$	1,096

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 nine months ended July 31, 2014, we contributed $.3 million to the nonqualified pension plans. We anticipate that we will contribute the following additional amounts to our plans during the fourth quarter of 2014.



In thousands

Nonqualified pension plans	$	112
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 funded annually. For the nine months ended July 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 July 31, 2014, we have a liability of $4.3 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

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three months and nine months ended July 31, 2014 and 2013, we recorded compensation expense, and as of July 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 settled in the same month with payment in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. We recorded compensation expense for the three months and nine months ended July 31, 2013 and a liability as of October 31, 2013 with compensation expense recorded in fiscal 2014 until December 2013 when the award was settled. The liability, which we accrued for this award based on the fair market value of our stock at the end of each quarter, 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 and nine months ended July 31, 2014 and 2013, we recorded compensation expense, and as of July 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 and in Note 6 to the condensed consolidated financial statements in this Form 10-Q.

The compensation expense related to the incentive compensation plans for the three months and nine months ended July 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 July 31, 2014 and October 31, 2013 are presented below.



	Three Months				Nine Months
In thousands	2014		2013		2014		2013
Compensation expense	$	822	$	1,848	$	5,025	$	5,505



	July 31, 2014		October 31, 2013
Liability	$	12,104	$	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 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 Operations and Comprehensive Income.

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Cardinal Pipeline Company, L.L.C.

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

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

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



	Three Months				Nine Months
In thousands	2014		2013		2014		2013
Transportation costs	$	2,204	$	2,240	$	6,607	$	6,534



	July 31, 2014		October 31, 2013
Trade accounts payable	$	747	$	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. Pine Needle owns an interstate LNG storage facility in North Carolina and is regulated by the FERC.

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

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



	Three Months				Nine Months
In thousands	2014		2013		2014		2013
Gas storage costs	$	2,935	$	2,791	$	8,429	$	8,307



	July 31, 2014		October 31, 2013
Trade accounts payable	$	989	$	940

SouthStar Energy Services LLC

We own 15% of the membership interests in 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.

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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. Beginning in this quarter, retirement benefits were allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. Our share of movements in the market value of these derivative contracts recorded as a hedge and the activity of the retirement benefit items are reflected in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Condensed Consolidated Balance Sheets; the detail of our share of the market value of these contracts and the retirement benefits are combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Condensed Consolidated Statements of Operations and Comprehensive Income.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Condensed Consolidated Statements of Operations and Comprehensive Income. For each period of the three months and nine months ended July 31, 2014 and 2013, our operating revenues from these sales and the amounts SouthStar owed us as of July 31, 2014 and October 31, 2013 are as follows.



	Three Months				Nine Months
In thousands	2014		2013		2014		2013
Operating revenues	$	1,402	$	1,469	$	2,309	$	2,053



	July 31, 2014		October 31, 2013
Trade accounts receivable	$	432	$	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 Operations and Comprehensive Income. For each period of the three months and nine months ended July 31, 2014 and 2013, these gas storage costs and the amounts we owed Hardy Storage as of July 31, 2014 and October 31, 2013 are as follows.



	Three Months				Nine Months
In thousands	2014		2013		2014		2013
Gas storage costs	$	2,322	$	2,425	$	7,139	$	7,276



	July 31, 2014		October 31, 2013
Trade accounts payable	$	774	$	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. Our contributions for the quarter and fiscal year 2014 were $13.3 million and $31.9 million, respectively, with our total equity contribution for the project totaling $47.8 million to date.


13.	Variable Interest Entities

As of July 31, 2014, we have determined that we are not the primary beneficiary under 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 impact the VIE’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 July 31, 2014 and October 31, 2013, our investment balances are as

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follows.



In thousands	July 31, 2014		October 31, 2013
Cardinal	$	16,275	$	18,207
Pine Needle	19,057		20,270
SouthStar	41,368		38,372
Hardy Storage	36,382		34,681
Constitution	50,391		16,939
Total equity method investments in non-utility activities	$	163,473	$	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. Although the operations of our regulated utility segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics within one 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 Operations and Comprehensive Income. Operations of the non-utility activities segment are included in the Condensed Consolidated Statements of Operations and Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”

Our chief operating decision maker is the executive management team. We produce consolidated financial information internally that is supplemented with separate non-utility activity reporting that is used regularly to make operating decisions and assess performance of the two business segments. 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 and nine months ended July 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	$	164,187		$	162,943		$	—		$	—		$	164,187		$	162,943
Margin	104,847			97,000			—			—			104,847			97,000
Operations and maintenance expenses	68,605			62,950			56			35			68,661			62,985
Income from equity method investments	—			—			5,043			3,652			5,043			3,652
Operating loss before income taxes	(3,070		)	(2,856		)	(126		)	(117		)	(3,196		)	(2,973		)
Income (loss) before income taxes	(16,867		)	(8,673		)	4,917			3,536			(11,950		)	(5,137		)
Nine Months
Revenues from external customers	$	1,284,167		$	1,078,229		$	—		$	—		$	1,284,167		$	1,078,229
Margin	577,882			512,480			—			—			577,882			512,480
Operations and maintenance expenses	199,437			183,869			102			155			199,539			184,024
Income from equity method investments	—			—			29,345			23,244			29,345			23,244
Operating income (loss) before income taxes	262,540			219,540			(260		)	(322		)	262,280			219,218
Income before income taxes	223,401			205,882			29,085			22,922			252,486			228,804

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



In thousands	Three Months						Nine Months
	2014			2013			2014			2013
Operating Income (Loss):
Segment operating income (loss) before income taxes	$	(3,196	)	$	(2,973	)	$	262,280		$	219,218
Utility income taxes	6,324			3,447			(89,668		)	(81,232		)
Non-utility activities before income taxes	126			117			260			322
Operating income	$	3,254		$	591		$	172,872		$	138,308

Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(11,950	)	$	(5,137	)	$	252,486		$	228,804
Income taxes	4,606			2,844			(99,718		)	(89,384		)
Net income (loss)	$	(7,344	)	$	(2,293	)	$	152,768		$	139,420


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.

On September 2, 2014, Piedmont, Duke Energy Corporation (Duke Energy), Dominion Resources, Inc. (Dominion), and AGL Resources, Inc. (AGL) announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which will be regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP will be substantially subscribed by utilities and related companies, including us, under twenty-year contracts, subject to state regulatory approval.

We entered into an agreement through a wholly owned subsidiary to become a 10% equity member of ACP. The other members are subsidiaries of Duke Energy, Dominion and AGL. A Dominion subsidiary will be the operator of the pipeline. The cost for the development and construction of the pipeline is expected to be between $4.5 billion to $5 billion.

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

The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and related notes in this Form 10-Q, as well as with our Form 10-K for the year ended October 31, 2013. Results for interim periods presented are not necessarily indicative of the results to be expected for the full fiscal year due to seasonal and other factors.

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


•	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

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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.

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 segment 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 July 31, 2014 and earnings before taxes by segments for the nine months ended July 31, 2014 are presented below.



	Assets		Earnings Before Taxes
Regulated Utility	96	%	88	%
Non-utility Activities:
Regulated non-utility activities	3	%	4	%
Unregulated non-utility activities	1	%	8	%
Total non-utility activities	4	%	12	%

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 (FERC) 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.

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

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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, and the North Carolina IMR was recognized in earnings 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 nine months ended July 31, 2014.



Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers, IMRs and fixed-rate contracts)	71	%
Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)	17	%
Volumetric or periodic renegotiation (including secondary marketing activity)	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.

Executive Summary

Financial Performance – Quarter Ended 2014 Compared with Quarter Ended 2013

We reported a net loss of $7.3 million for the three months ended July 31, 2014 as compared to a net loss of $2.3 million for the same period in 2013. The following tables provide a comparison of the components of operations and comprehensive income and statistical information for the three months ended July 31, 2014 as compared with the three months ended July 31, 2013.

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Comprehensive Statement of Operations Components

	Three Months Ended July 31						Variance			Percent Change
In thousands, except per share amounts	2014			2013			Variance			Percent Change
Operating Revenues	$	164,187		$	162,943		$	1,244		0.8	%
Cost of Gas	59,340			65,943			(6,603		)	(10.0	)%
Margin	104,847			97,000			7,847			8.1	%
Operations and Maintenance	68,605			62,950			5,655			9.0	%
Depreciation	29,960			28,599			1,361			4.8	%
General Taxes	9,352			8,307			1,045			12.6	%
Utility Income Taxes	(6,324		)	(3,447		)	(2,877		)	(83.5	)%
Total Operating Expenses	101,593			96,409			5,184			5.4	%
Operating Income	3,254			591			2,663			450.6	%
Other Income (Expense), net of tax	2,527			2,819			(292		)	(10.4	)%
Utility Interest Charges	13,125			5,703			7,422			130.1	%
Net Loss	$	(7,344	)	$	(2,293	)	$	(5,051	)	(220.3	)%
Average Shares of Common Stock:
Basic	78,185			75,774			2,411			3.2	%
Diluted	78,185			75,774			2,411			3.2	%
Loss Per Share of Common Stock:
Basic	$	(0.09	)	$	(0.03	)	$	(0.06	)	200.0	%
Diluted	$	(0.09	)	$	(0.03	)	$	(0.06	)	200.0	%

Margin by Customer Class

	Three Months Ended July 31
In thousands	2014				2013
Sales and Transportation:
Residential	$	41,333	39	%	$	42,015	43	%
Commercial	25,800		25	%	22,914		24	%
Industrial	10,994		11	%	10,021		10	%
Power Generation	19,323		18	%	16,503		17	%
For Resale	2,743		3	%	1,665		2	%
Total	100,193		96	%	93,118		96	%
Secondary Market Sales	3,223		3	%	1,330		1	%
Miscellaneous	1,431		1	%	2,552		3	%
Total	$	104,847	100	%	$	97,000	100	%

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Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Three Months Ended July 31
	2014		2013		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Residential	2,651		3,175		(524	)	(16.5	)%
Commercial	5,349		5,177		172		3.3	%
Industrial	21,064		21,212		(148	)	(0.7	)%
Power Generation	56,845		52,681		4,164		7.9	%
For Resale	858		867		(9	)	(1.0	)%
Throughput	86,767		83,112		3,655		4.4	%
Secondary Market Volumes	1,461		2,782		(1,321	)	(47.5	)%
Customers Billed (at period end)	998,850		985,034		13,816		1.4	%
Gross Residential, Commercial and Industrial Customer Additions	3,671		3,232		439		13.6	%
Degree Days
Actual	33		77		(44	)	(57.1	)%
Normal	49		49		—		—	%
Percent (warmer) colder than normal	(32.7	)%	57.1	%	n/a		n/a
Number of Employees (at period end)	1,868		1,795		73		4.1	%

We ended our third quarter with a 220% decrease in net income. Margin increased 8% due to: customer growth, new rates effective January 1, 2014 in North Carolina under a rate case settlement, the Tennessee and North Carolina IMR rate adjustments, transportation services under a new power generation delivery contract, rate design changes for industrial customers as a result of the rate case settlement in North Carolina, a contract margin true-up and higher margin sales from secondary market activity. The margin earned from power generation customers is largely based on fixed monthly demand charge contracts and does not vary significantly based on the volumes transported. Operations and maintenance (O&M) expenses and depreciation expense increased 9% and 5%, respectively. The increase in O&M expenses was related to increases in payroll, bad debt, contract labor and regulatory expenses. Depreciation was higher due to increases in plant in service from our capital expansion program, particularly related to system integrity. General taxes increased 13% due to increased state franchise taxes and property taxes. SouthStar Energy Services LLC (SouthStar) increased its income contribution from our equity method investment. Utility interest charges increased 130% from increases in long-term debt outstanding, a decrease in capitalized interest recorded as income and the recording of interest expense on amounts due to customers.

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Financial Performance – Nine Months Ended 2014 Compared with Nine Months Ended 2013

We reported net income of $152.8 million for the nine months ended July 31, 2014 as compared to $139.4 million for the same period in 2013. The following tables provide a comparison of the components of operations and comprehensive income and statistical information for the nine months ended July 31, 2014 as compared with the nine months ended July 31, 2013.



Comprehensive Statement of Operations Components
	Nine Months Ended July 31				Variance		Percent Change
In thousands, except per share amounts	2014		2013		Variance		Percent Change
Operating Revenues	$	1,284,167	$	1,078,229	$	205,938	19.1	%
Cost of Gas	706,285		565,749		140,536		24.8	%
Margin	577,882		512,480		65,402		12.8	%
Operations and Maintenance	199,437		183,869		15,568		8.5	%
Depreciation	87,947		82,168		5,779		7.0	%
General Taxes	27,958		26,903		1,055		3.9	%
Utility Income Taxes	89,668		81,232		8,436		10.4	%
Total Operating Expenses	405,010		374,172		30,838		8.2	%
Operating Income	172,872		138,308		34,564		25.0	%
Other Income (Expense), net of tax	15,650		14,594		1,056		7.2	%
Utility Interest Charges	35,754		13,482		22,272		165.2	%
Net Income	$	152,768	$	139,420	$	13,348	9.6	%
Average Shares of Common Stock:
Basic	77,715		74,521		3,194		4.3	%
Diluted	78,027		74,987		3,040		4.1	%
Earnings Per Share of Common Stock:
Basic	$	1.97	$	1.87	$	0.10	5.3	%
Diluted	$	1.96	$	1.86	$	0.10	5.4	%



Margin by Customer Class
	Nine Months Ended July 31
In thousands	2014				2013
Sales and Transportation:
Residential	$	299,850	52	%	$	284,135	56	%
Commercial	141,025		24	%	129,282		25	%
Industrial	39,427		7	%	41,427		8	%
Power Generation	58,275		10	%	36,803		7	%
For Resale	7,100		1	%	5,807		1	%
Total	545,677		94	%	497,454		97	%
Secondary Market Sales	23,809		4	%	6,618		1	%
Miscellaneous	8,396		2	%	8,408		2	%
Total	$	577,882	100	%	$	512,480	100	%

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Gas Deliveries, Customers, Weather Statistics and Number of Employees

	Nine Months Ended July 31
	2014		2013		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Residential	58,480		51,774		6,706		13.0	%
Commercial	38,138		33,434		4,704		14.1	%
Industrial	73,697		72,639		1,058		1.5	%
Power Generation	150,808		136,374		14,434		10.6	%
For Resale	6,005		5,722		283		4.9	%
Throughput	327,128		299,943		27,185		9.1	%
Secondary Market Volumes	17,864		33,448		(15,584	)	(46.6	)%
Customers Billed (at period end)	998,850		985,034		13,816		1.4	%
Gross Residential, Commercial and Industrial Customer Additions	11,626		10,032		1,594		15.9	%
Degree Days
Actual	3,391		3,186		205		6.4	%
Normal	3,070		3,078		(8	)	(0.3	)%
Percent colder than normal	10.5	%	3.5	%	n/a		n/a
Number of Employees (at period end)	1,868		1,795		73		4.1	%

We ended the first three quarters of fiscal year 2014 with a 10% increase in net income. Margin increased 13% due to: customer growth, higher volumes delivered to residential and commercial customers due to colder weather, new rates effective January 1, 2014 in North Carolina under a rate case settlement, the Tennessee and North Carolina IMR rate adjustments, transportation services under a new power generation delivery contract and higher margin sales from secondary market activity. O&M expenses and depreciation expense increased 8% and 7%, respectively. The increase in O&M expenses was related to increases in payroll, regulatory, bad debt and contract labor expenses. Depreciation was higher due to increases in plant in service from our capital expansion program, as discussed above for the quarter. General taxes increased 4% primarily due to increased state franchise taxes and payroll taxes. Other Income (Expense) increased 7% primarily due to an increase in income from equity method investments, primarily from SouthStar and Constitution Pipeline Company, LLC (Constitution), partially offset by a write-off of an investment that had been accounted for under the cost method and increased charitable contributions. Utility interest charges increased 165% from increases in long-term debt outstanding, a decrease in capitalized interest recorded as income and the recording of interest expense on amounts due to customers.

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 strong investment grade credit ratings with a goal of maintaining a total debt to capital ratio between 50% and 60%. As reflected in this quarterly report, we revised this target to include both short- and long-term debt as we believe it provides a more accurate representation of our overall leverage and our financing targets. To meet our short-term liquidity needs, we continue to rely on our commercial paper (CP) program. 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 common 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 this transaction, see the following discussion of “Cash Flows from Financing Activities.”

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Customer Growth – We continued to accelerate the rate at which we added customers during the current period compared to the prior year period. Affordable and stable wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. With continued improvement in economic conditions resulting in growth in both the residential and commercial markets and targeted marketing programs on the benefits of natural gas, total new customers increased during the nine months ended July 31, 2014 as compared to the same period in 2013 as presented below.



	2014	2013	Percent Change
Residential new home construction	8,372	7,235	15.7	%
Residential conversion	1,969	1,739	13.2	%
Commercial	1,272	1,044	21.8	%
Industrial	13	14	(7.1	)%
Total new customers	11,626	10,032	15.9	%

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

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

With significant capital costs incurred under our ongoing system integrity programs, we have implemented new regulatory mechanisms that will allow us to recover and earn on those investments in a more 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 $.4 million recorded through the third quarter. 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 $8.6 million recorded through the third 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 is expected to create operating efficiencies and facilitate compliance with pipeline safety and integrity regulations. Implementation began in April 2014. Several phases of the program are expected to be implemented through our fiscal year 2016.

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, 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 is late 2015 or 2016. We expect our total 24% equity contributions will be an estimated $175 million. We contributed $31.9 million during the nine months ended July 31, 2014 for a total of $47.8 million to date.

To further our strategy of expanding our complementary energy-related businesses, on September 2, 2014, we became a 10% equity member of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate

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and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. For further information on this equity method investment, see Note 15 to the condensed consolidated financial statements and "Cash Flows from Investing Activities" in Management's Discussion and Analysis in this Form 10-Q.

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 and nine months ended July 31, 2014 follows.

Operating Revenues

Changes in operating revenues for the three months and nine months ended July 31, 2014 compared with the same periods in 2013 are presented below.

Changes in Operating Revenues - Increase (Decrease)

In millions	Three Months			Nine Months
Residential and commercial customers	$	3.6		$	197.1
Industrial customers	(0.9		)	2.5
Power generation customers	2.8			22.0
Secondary market	(4.7		)	24.3
Margin decoupling mechanism	(1.5		)	(39.0		)
WNA mechanisms	—			(11.4		)
IMR mechanisms	1.7			9.0
Other revenue	0.2			1.4
Total	$	1.2		$	205.9


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

•

Industrial customers – the decrease for the three months is primarily due to decreased volumes and transportation revenues from decreased industrial rates in North Carolina as a result of the general rate case in North Carolina effective January 1, 2014. The increase for the nine months is primarily due to colder weather and higher wholesale gas costs passed through to customers, slightly offset by decreased transportation revenues.


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

•

Secondary market – the decrease for the three months is primarily due to decreased activity, partially offset by slightly higher margins. The increase for the nine months 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 decreases for the three months and nine months are primarily related to adjustments included in the general rate case mentioned above, and for the nine months, from 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 three months comparability is due to actual degree days being similar to normal degree days in the quarter. The decrease for the nine months 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.


•	IMR mechanisms – the increases for the three months and nine months are due to the IMR rate adjustments in Tennessee effective January 1, 2014 and North Carolina effective February 1, 2014.

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Cost of Gas

Changes in cost of gas for the three months and nine months ended July 31, 2014 compared with the same periods in 2013 are presented below.

Changes in Cost of Gas - Increase (Decrease)

In millions	Three Months			Nine Months
Commodity gas costs passed through to sales customers	$	3.5		$	133.1
Commodity gas costs in secondary market transactions	(5.7		)	8.0
Pipeline demand charges	(2.8		)	(4.1		)
Regulatory-approved gas cost mechanisms	(1.6		)	3.5
Total	$	(6.6	)	$	140.5


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


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


•	Regulatory-approved gas cost mechanisms – the decrease for the three months is primarily due to a decrease in commodity gas cost true-ups, slightly offset by other regulatory mechanisms. The increase for the nine months is primarily due to demand cost true-ups, slightly offset by other regulatory mechanisms.

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 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 43% of revenues for the nine months ended July 31, 2014, and our pipeline transportation and storage costs accounted for 9%.

In general rate proceedings, state regulatory commissions authorize us to recover our margin in our monthly fixed demand charges and on each unit of gas delivered under our generally applicable sales and transportation tariffs and special service contracts. We negotiate special service contracts with some industrial customers that may include the use of volumetric rates with minimum margin commitments and fixed monthly demand charges. These individually negotiated agreements are subject to review and approval by the applicable state regulatory commission and allow us to make an economic extension or expansion of natural gas service to larger industrial customers.

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Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document. These regulatory mechanisms by jurisdiction are presented below.



Regulatory Mechanism	North Carolina	South Carolina	Tennessee
WNA mechanism		X	X
Margin decoupling mechanism *	X
Natural gas rate stabilization		X
Secondary market activity **	X	X	X
Incentive plan for gas supply **			X
IMR mechanism	X		X
Negotiated margin loss treatment	X	X
Uncollectible gas cost recovery	X	X	X

* Residential and commercial customers only.

** In all jurisdictions, we retain 25% of secondary market margins generated through off-system sales and capacity release activity, with 75% credited to customers through the incentive plans. Our share of net gains or losses in Tennessee is subject to an annual cap of $1.6 million.

Changes in margin for the three months and nine months ended July 31, 2014 compared with the same periods in 2013 are presented below.

Changes in Margin - Increase (Decrease)

In millions	Three Months			Nine Months
Residential and commercial customers	$	2.2		$	27.5
Industrial customers	2.0			(0.7		)
Power generation customers	2.8			21.4
Secondary market activity	1.0			16.3
Net gas cost adjustments	(0.2		)	0.9
Total	$	7.8		$	65.4

•

Residential and commercial customers – the increase for the three months is primarily due to the general rate case increase in North Carolina effective January 1, 2014, IMR rate adjustments in Tennessee effective January 1, 2014 and North Carolina effective February 1, 2014, and customer growth in all three states. The increase for the nine months is primarily due to increased volumes delivered due to colder weather, the general rate case increase in North Carolina effective January 1, 2014, the IMR rate adjustments mentioned above, and customer growth in all three states.

•

Industrial customers – the increase for the three months is primarily due to rate design changes for industrial customers in North Carolina under the general rate case settlement effective January 1, 2014 as well as a contract margin true-up. The decrease for the nine months 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 increases for the three months and nine months are primarily due to increased transportation services due to a new contract placed in service in June 2013.


•	Secondary market activity – the increases for the three months and nine months are due to higher margin sales related to increased wholesale market volatility, and for the nine months, sustained colder-than-normal weather.

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Operations and Maintenance Expenses

Changes in O&M expenses for the three months and nine months ended July 31, 2014 compared with the same periods in 2013 are presented below.

Changes in Operations and Maintenance Expenses - Increase (Decrease)

In millions	Three Months			Nine Months
Payroll	$	2.0		$	7.8
Regulatory	1.1			2.8
Bad debt	1.9			2.4
Contract labor	1.1			1.1
Other	(0.4		)	1.5
Total	$	5.7		$	15.6


•	Payroll – the increase for the three months is primarily due to additional employees and incentive plan accruals. The increase for the nine months is primarily due to additional employees, employee overtime and incentive plan accruals.


•	Regulatory – the increases for the three months and nine months are primarily due to increased amortization of regulatory assets with approved amortization amounts established in the North Carolina general rate proceeding, effective January 1, 2014, and an increase in the North Carolina regulatory fee due to increased revenues.


•	Bad Debt – the increases for the three months and nine months are primarily due to a higher level of projected charge-offs from customer receivables due to the colder weather experienced this past winter and fewer current period customer service disconnections for non-payment of customer bills than in prior periods.


•	Contract labor – the increases for the three months and nine months are primarily due to increased call volume and collection efforts for customer receivables resulting from a colder winter, increased process improvement projects and pipeline integrity maintenance and safety programs.

Depreciation

Depreciation expense increased $1.4 million and $5.8 million for the three months and nine months ended July 31, 2014, respectively, compared with the same periods in 2013 primarily due to increases in plant in service, particularly related to major additions related to system integrity investments.

General Taxes

General taxes increased $1 million and $1.1 million for the three months and nine months ended July 31, 2014, respectively, compared with the same periods in 2013 primarily due to increases in state franchise taxes and property taxes due to increased investment in plant in the three-month period, and an increase in payroll taxes for the nine-month period.

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.

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Changes in other income (expense) for the three months and nine months ended July 31, 2014 compared with the same periods in 2013 are presented below.

Changes in Other Income (Expense) - Increase (Decrease)

In millions	Three Months			Nine Months
Income from equity method investments:
SouthStar	$	1.0		$	5.0
Constitution	.5			1.0
Other	(.1		)	.1
Total	1.4			6.1
Non-operating income	.2			(1.8		)
Non-operating expense	(.8		)	(1.3		)
Income Taxes	(1.1		)	(1.9		)
Total	$	(.3	)	$	1.1

•

Income from equity method investments from SouthStar – the increase for the three months is primarily due to the expansion of the business into Illinois markets beginning in September 2013 and favorable Illinois margin, partially offset by higher operating and general and administrative expenses. The increase for the nine months is primarily due to the expansion into the Illinois markets discussed above and favorable Georgia weather and customer usage, partially offset by higher operating and general and administrative 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.


•	Income from equity method investments from Constitution – the increase for the nine months is primarily due to higher capitalized interest associated with increased capital expenditures on the project.


•	Non-operating income – the decrease for the nine months is primarily due to a $2 million write-off of an investment that we accounted for on the cost basis. This investment was presented in “Other noncurrent assets” in “Noncurrent Assets” in the Condensed Consolidated Balance Sheets.


•	Non-operating expense – the increase for the nine months is primarily due to higher charitable contributions in the current period.

Utility Interest Charges

Changes in utility interest charges for the three months and nine months ended July 31, 2014 compared with the same periods in 2013 are presented below.

Changes in Utility Interest Charges - Increase (Decrease)

In millions	Three Months			Nine Months
Interest expense on long-term debt	$	2.3		$	7.4
Borrowed allowance for funds used during construction (AFUDC)	3.0			9.8
Regulatory interest expense, net	2.2			5.3
Other	(0.1		)	(0.2		)
Total	$	7.4		$	22.3


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


•	Borrowed AFUDC – the increases for the three months and nine months are due to a decrease in capitalized interest on a lower base of construction expenditures in the current periods resulting from the timing of projects being placed into service.


•	Regulatory interest expense, net – the increases for the three months and nine months are primarily due to a decrease in interest income due to the recording of interest expense on amounts due to customers.

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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.

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, capital 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, as well as the ability to recover and earn on investments in infrastructure related to our pipeline integrity programs through IMRs in North Carolina and Tennessee.

Short-Term Debt. We have an $850 million five-year revolving syndicated credit facility that expires in October 2017. 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.

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



In thousands
End of period (July 31, 2014):
Amount outstanding	$	490,000
Weighted average interest rate	.17		%

During the period (May 1, 2014 – July 31, 2014):
Average amount outstanding	$	395,700
Minimum amount outstanding	$	330,000
Maximum amount outstanding	$	495,000
Minimum interest rate	.11		%
Maximum interest rate	.18		%
Weighted average interest rate	.16		%

Maximum amount outstanding:
May 2014	$	390,000
June 2014	$	420,000
July 2014	$	495,000

As of July 31, 2014, we have $10 million available for letters of credit under our revolving syndicated credit facility, of which $1.8 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of July 31, 2014, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $358.2 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 increases to reflect amounts due to our natural gas suppliers for commodity and pipeline capacity. The cost of the natural gas can vary significantly from period to period due to changes in the price of natural gas, which is a function of market fluctuations in the commodity cost of natural gas, along with our changing requirements for storage volumes. Differences between natural gas costs that we have paid to suppliers and amounts that we have collected from customers are included in regulatory deferred accounts in amounts due to or from customers. These natural gas costs can cause cash flows to vary significantly from period to period along with variations in the timing of collections from customers under our gas cost recovery mechanisms.

Cash flows from operations are impacted by weather, which affects gas purchases and sales. Warmer weather can lead to lower revenues from fewer volumes of natural gas sold or transported. Colder weather can increase volumes sold to weather-sensitive customers but may lead to conservation by customers in order to reduce their heating bills. 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, 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.

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Net cash provided by operating activities was $414 million and $285.9 million for the nine months ended July 31, 2014 and 2013, respectively. Net cash provided by operating activities reflects an increase of $13.3 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 decreased $17.4 million from October 31, 2013 primarily due to the decrease in unbilled volumes and amounts billed to customers reflecting lower gas costs. Volumes sold to weather-sensitive residential and commercial customers increased 11.4 million dekatherms as compared with the same prior period primarily due to 6.4% colder weather in the current period. Total throughput increased 27.2 million dekatherms as compared with the same prior period, largely from 14.4 million dekatherms, or 10.6%, increased deliveries to power generation customers as well as increased sales to residential and commercial customers.


•	Net amounts due from customers decreased $112 million from October 31, 2013 primarily due to higher margin decoupling, WNA and deferred gas cost amounts due to customers from colder winter weather.


•	Gas in storage increased $5.2 million in the current period primarily due to an increase in the weighted average cost of gas purchased for injections, slightly offset by 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 $2.8 million in the current period primarily due to gas being made available for sale during the period. Under some gas supply asset management contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.


•	Trade accounts payable decreased $11.1 million from October 31, 2013 primarily due to decreased utility capital expenditures and natural gas purchases.

Primarily due to bonus depreciation, we generated a federal net operating loss (NOL) in our 2013 tax year. We used the carryforward of the 2013 NOL to offset our 2014 federal 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 $9 million and charges to customers of $2.4 million in the nine months ended July 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 $39.7 million and $.7 million in the nine months ended July 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.

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.

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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 $385.3 million and $475.5 million for the nine months ended July 31, 2014 and 2013, respectively. Net cash used in investing activities was primarily for utility capital expenditures. Gross utility capital expenditures for the nine months ended July 31, 2014 were $348.4 million, primarily for system integrity projects and customer growth, as compared to $443.3 million in the same prior period, which was primarily due to additional expenditures on system integrity projects.

We have a substantial capital expansion program for the construction of transmission and distribution facilities, purchase of equipment and other general improvements. Our program primarily supports our system infrastructure and the growth in our customer base. We continue to spend large amounts for pipeline integrity, safety and compliance programs, and systems and technology infrastructure to enhance our pipeline system and integrity, including 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 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 50 – 60% in total debt and 40 – 50% 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.



In millions	2014		2015		2016
Customer growth and other	$	195	$	195	$	270
System integrity	295		250		235
Total forecasted capital expenditures	$	490	$	445	$	505

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 installation of a major transmission line in Nashville, the construction of which began in 2013 and concluded in the third quarter of 2014.

In June 2014, we executed an agreement to construct approximately 1.5 miles of natural gas transmission pipeline and associated compression to serve Duke Energy Corporation’s (Duke Energy) W.S. Lee power generation facility near Anderson, South Carolina. Our total investment is estimated to be $38 million, with $8 million and $30 million in our fiscal years 2015 and 2016, respectively, and is included in the table above in the line “Customer growth and other.” This agreement is supported by a long-term natural gas service agreement with fixed monthly charges.

On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL Resources, Inc. (AGL) announced the formation of Atlantic Coast Pipeline, LLC (ACP), a Delaware limited liability company. ACP intends to construct, operate and maintain a 550 mile natural gas pipeline, with associated compression, from West Virginia through Virginia into eastern North Carolina. The pipeline will provide wholesale natural gas transportation services for Marcellus and Utica gas supplies into southeastern markets. ACP, which will be regulated by the FERC, will be designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date of late 2018. The capacity of ACP will be substantially subscribed by utilities and related companies, including us, under twenty-year contracts, subject to state regulatory approval.

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In conjunction with our investment in ACP, we plan to make additional utility capital investments in our natural gas delivery system of approximately $190 million in order to redeliver ACP gas supplies to local North Carolina markets we serve.

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. Our contributions for the nine months ended July 31, 2014 were $31.9 million with our total equity contribution for the project totaling $47.8 million as of July 31, 2014. The forecasted in-service date of the project is late 2015 or 2016. We expect our equity contributions will be an estimated $40 million, $89 million, and $30 million in our fiscal years 2014, 2015 and 2016, respectively, for a total of $175 million. 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 (used in) provided by financing activities was $(18.4) million and $192.4 million for the nine months ended July 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 40 – 50% equity to total capital. In recent years, bonus depreciation has been a source of funds in that it has decreased our federal income tax payments. 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 for other general corporate purposes.

Outstanding debt under our CP program increased from $400 million as of October 31, 2013 to $490 million as of July 31, 2014 primarily due to natural gas purchases, repayment of our long-term debt and investments in one of our equity method investments, partially offset by net proceeds received from the issuance of our common stock, reduced utility capital expenditures and cash flow stemming from colder-than-normal weather. On November 1, 2013, we entered into an agreement with the lenders of our five-year revolving syndicated credit facility to increase the aggregate commitment from $650 million to $850 million with an expiration date of 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.”

On June 6, 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on the same date. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes. 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 50– 60% in total debt and 40 – 50% 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, see Note 6 to the condensed consolidated financial statements in this Form 10-Q.

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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 consolidated financial statements in our Form 10-K for the year ended October 31, 2013.

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 nine months ended July 31, 2014 and 2013, we issued $18.8 million and $18.9 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 July 31, 2014, our ability to pay dividends was not restricted. On September 5, 2014, the Board of Directors declared a quarterly dividend on common stock of $.32 per share, payable October 15, 2014 to shareholders of record at the close of business on September 24, 2014.

Our targeted capitalization ratio is 50 – 60% in total debt and 40 – 50% in common equity. The components of our total debt outstanding (short-term debt and long-term debt) to our total capitalization as of July 31, 2014 and 2013, and October 31, 2013, are summarized in the table below.



	July 31				October 31				July 31
In thousands	2014		Percentage		2013		Percentage		2013		Percentage
Short-term debt	$	490,000	16	%	$	400,000	14	%	$	515,000	19	%
Current portion of long-term debt	—		—		100,000		3	%	100,000		4	%
Long-term debt	1,174,861		39	%	1,174,857		41	%	875,000		32	%
Total debt	1,664,861		55	%	1,674,857		58	%	1,490,000		55	%
Common stockholders’ equity	1,335,804		45	%	1,188,596		42	%	1,211,449		45	%
Total capitalization (including short-term debt)	$	3,000,665	100	%	$	2,863,453	100	%	$	2,701,449	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 July 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 July 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 “A2” by Moody’s Investors Service (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on our CP program at “A1” and “P1,” respectively. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, a significant negative change in our capital structure, a change from the constructive regulatory environments in which we operate, a significant reduction in our liquidity or a methodological change at the rating agencies themselves 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.

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Estimated Future Contractual Obligations

During the three months ended July 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, surety bonds and operating leases. The letters of credit and surety bonds are discussed in Note 5 and Note 9, respectively, 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 (ERM) program and with the direction of the Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.

During the nine months ended July 31, 2014, the Board of Directors' level of oversight of risk and the ERM program was delegated to the Finance and Enterprise Risk Committee. All other committees of our Board of Directors have enhanced monitoring of those risks relating to areas where they have oversight responsibility. In addition, the Board of Directors approved risk tolerances for major areas of risk exposure and will monitor against those tolerances beginning in the fourth quarter 2014. Our exposure to, and management of, interest rate risk, commodity price risk and weather risk has remained the same during the nine months ended July 31, 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 July 31, 2014, we had $490 million of short-term debt outstanding as commercial paper at an interest rate of .17%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest

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rate for our short-term debt would have caused a change in interest expense of approximately $3.4 million during the nine months ended July 31, 2014.

Item 4. Controls and Procedures

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

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

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



	c)	Issuer Purchases of Equity Securities.

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program during the three months ended July 31, 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
5/1/14 – 5/31/14	—	$	—	—	2,910,074
6/1/14 – 6/30/14	—	$	—	—	2,910,074
7/1/14 – 7/31/14	—	$	—	—	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. On that date, the Board also approved an amendment of the Common Stock Open Market Purchase Program to provide for the purchase of up to four million additional shares of common stock to maintain our debt-to-equity capitalization ratios at target levels. The additional four million shares were referred to as our accelerated share repurchase (ASR) program. On March 6, 2009, the Board of Directors authorized the repurchase of up to an additional four million shares under the Common Stock Open Market Purchase Program and the ASR program, which were consolidated.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of July 31, 2014, our ability to pay dividends was not restricted.

Item 6. Exhibits



10.1	Resolution of Board of Directors, June 6, 2014, establishing compensation for non-management directors
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer
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 July 31, 2014 and October 31, 2013; (3) Condensed Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2014 and 2013; (4) Condensed Consolidated Statements of Cash Flows for the nine months ended July 31, 2014 and 2013; (5) Condensed Consolidated Statements of Stockholders’ Equity for the nine months ended July 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 September 5, 2014				/s/ Karl W. Newlin
				Karl W. Newlin
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)



Date September 5, 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 July 31, 2014

Exhibits



10.1			Resolution of Board of Directors, June 6, 2014, establishing compensation for non-management directors

31.1			Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Executive Officer

31.2			Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of the Chief Financial Officer

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

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

PIEDMONT NATURAL GAS CO INC - FORM 10-Q - September 5, 2014

Attached files

PIEDMONT NATURAL GAS CO INC Reports