PIEDMONT NATURAL GAS CO INC (Form: 10-Q, Received: 09/07/2012 06:04:31)

September 7, 2012

/s/ Thomas E. Skains

Thomas E. Skains

Chairman of the Board, President

and Chief Executive Officer

(Principal Executive Officer)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended July 31, 2012

¨	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. þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ 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 þ	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No

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


Class		Outstanding at September 4, 2012
Common Stock, no par value		72,076,431

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

July 31, 2012

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		46
Item 4.	Controls and Procedures		47

Part II.	Other Information

Item 1.	Legal Proceedings		47
Item 1A.	Risk Factors		47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		47
Item 6.	Exhibits		48

	Signatures		49

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)


	July 31, 2012		October 31, 2011

ASSETS
Utility Plant:
Utility plant in service	$	3,576,171	$	3,377,310
Less accumulated depreciation		1,024,023		974,631

Utility plant in service, net		2,552,148		2,402,679
Construction work in progress		377,567		217,832
Plant held for future use		6,751		6,751

Total utility plant, net		2,936,466		2,627,262


Other Physical Property, at cost (net of accumulated depreciation of $834 in 2012 and $806 in 2011)		424		452


Current Assets:
Cash and cash equivalents		5,721		6,777
Trade accounts receivable (less allowance for doubtful accounts of $2,441 in 2012 and $1,347 in 2011)		66,155		57,035
Income taxes receivable		45,163		15,966
Other receivables		1,241		2,547
Unbilled utility revenues		4,851		28,715
Inventories:
Gas in storage		72,366		91,124
Materials, supplies and merchandise		1,023		1,368
Gas purchase derivative assets, at fair value		3,565		2,772
Amounts due from customers		64,909		38,649
Prepayments		23,845		39,128
Deferred income taxes		—		1,793
Other current assets		296		147

Total current assets		289,135		286,021


Noncurrent Assets:
Equity method investments in non-utility activities		85,707		85,121
Goodwill		48,852		48,852
Marketable securities, at fair value		2,137		1,439
Overfunded postretirement asset		22,936		22,879
Regulatory asset for postretirement benefits		77,649		81,073
Unamortized debt expense		12,791		11,315
Regulatory cost of removal asset		20,672		19,336
Other noncurrent assets		61,153		58,791

Total noncurrent assets		331,897		328,806


Total	$	3,557,922	$	3,242,541

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)


	July 31, 2012			October 31, 2011

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: 72,063 in 2012 and 72,318 in 2011		436,821			446,791
Retained earnings		608,404			550,584
Accumulated other comprehensive loss		(454	)		(452	)

Total stockholders’ equity		1,044,771			996,923
Long-term debt		975,000			675,000

Total capitalization		2,019,771			1,671,923


Current Liabilities:
Short-term debt		200,000			331,000
Trade accounts payable		87,847			85,721
Other accounts payable		30,086			43,959
Accrued interest		10,887			20,038
Customers’ deposits		22,215			25,462
Deferred income taxes		25,847			—
General taxes accrued		15,140			21,262
Amounts due to customers		1,830			2,617
Other current liabilities		4,412			4,073

Total current liabilities		398,264			534,132


Noncurrent Liabilities:
Deferred income taxes		591,538			512,961
Unamortized federal investment tax credits		1,744			2,004
Accumulated provision for postretirement benefits		14,816			14,671
Cost of removal obligations		486,679			466,000
Other noncurrent liabilities		45,110			40,850

Total noncurrent liabilities		1,139,887			1,036,486


Commitments and Contingencies (Note 9)


Total	$	3,557,922		$	3,242,541

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Operations and Comprehensive Income (Unaudited)

(In thousands except per share amounts)


	Three Months Ended July 31						Nine Months Ended July 31
	2012			2011			2012			2011

Operating Revenues	$	161,123		$	197,274		$	941,395		$	1,241,897
Cost of Gas		74,663			115,311			462,748			756,997


Margin		86,460			81,963			478,647			484,900


Operating Expenses:
Operations and maintenance		59,248			53,351			178,155			163,344
Depreciation		25,532			26,128			76,980			76,601
General taxes		8,275			9,206			26,196			29,767
Utility income taxes		(4,082	)		(7,111	)		71,228			71,003


Total operating expenses		88,973			81,574			352,559			340,715


Operating Income (Loss)		(2,513	)		389			126,088			144,185


Other Income (Expense):
Income from equity method investments		3,290			2,360			21,234			22,500
Non-operating income		267			711			909			1,349
Non-operating expense		(342	)		(303	)		(1,389	)		(1,481	)
Income taxes		(1,238	)		(482	)		(8,090	)		(8,149	)


Total other income (expense)		1,977			2,286			12,664			14,219


Utility Interest Charges:
Interest on long-term debt		10,164			11,269			30,192			35,440
Allowance for borrowed funds used during construction		(6,656	)		(1,928	)		(17,131	)		(5,603	)
Other		569			2,037			3,885			5,422


Total utility interest charges		4,077			11,378			16,946			35,259


Net Income (Loss)		(4,613	)		(8,703	)		121,806			123,145


Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $10 and ($125) for the three months ended July 31, 2012 and 2011, respectively, and ($535) and ($70) for the nine months ended July 31, 2012 and 2011, respectively		18			(191	)		(837	)		(110	)
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $268 and $47 for the three months ended July 31, 2012 and 2011, respectively, and $533 and $355 for the nine months ended July 31, 2012 and 2011, respectively		420			73			835			553

Total other comprehensive income (loss)		438			(118	)		(2	)		443


Comprehensive Income (Loss)	$	(4,175	)	$	(8,821	)	$	121,804		$	123,588


Average Shares of Common Stock:
Basic		71,936			72,007			71,933			72,010
Diluted		71,936			72,007			72,233			72,235

Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.06	)	$	(0.12	)	$	1.69		$	1.71
Diluted	$	(0.06	)	$	(0.12	)	$	1.69		$	1.70

Cash Dividends Per Share of Common Stock	$	0.30		$	0.29		$	0.89		$	0.86

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)


	Nine Months Ended July 31
	2012			2011

Cash Flows from Operating Activities:
Net income	$	121,806		$	123,145
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		81,038			79,707
Amortization of investment tax credits		(260	)		(122	)
Allowance for doubtful accounts		1,094			1,929
Income from equity method investments		(21,234	)		(22,500	)
Distributions of earnings from equity method investments		13,988			14,961
Deferred income taxes, net		106,218			67,292
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		(793	)		1,406
Receivables		14,873			(10,494	)
Inventories		19,103			11,445
Amounts due from/to customers		(27,047	)		48,202
Settlement of legal asset retirement obligations		(1,156	)		(1,137	)
Overfunded postretirement asset		(57	)		(22,807	)
Regulatory asset for postretirement benefits		3,424			1,558
Other assets		(16,109	)		15,258
Accounts payable		(15,243	)		(12,461	)
Provision for postretirement benefits		145			607
Other liabilities		(13,648	)		(16,015	)

Net cash provided by operating activities		266,142			279,974


Cash Flows from Investing Activities:
Utility construction expenditures		(350,986	)		(137,591	)
Allowance for funds used during construction		(17,131	)		(5,603	)
Contributions to equity method investments		(3,566	)		(6,222	)
Distributions of capital from equity method investments		10,222			8,968
Proceeds from sale of property		734			885
Investments in marketable securities		(687	)		(466	)
Other		1,911			2,065

Net cash used in investing activities		(359,503	)		(137,964	)

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)


	Nine Months Ended July 31
	2012			2011

Cash Flows from Financing Activities:
Borrowings under credit facility	$	350,000		$	1,451,000
Repayments under credit facility		(681,000	)		(1,423,500	)
Net borrowings - commercial paper		400,000			—
Proceeds from issuance of long-term debt		100,000			200,000
Retirement of long-term debt		—			(196,922	)
Expenses related to issuance of debt		(2,548	)		(3,924	)
Issuance of common stock through dividend reinvestment and employee stock plans		16,483			15,392
Repurchases of common stock		(26,528	)		(23,004	)
Dividends paid		(64,068	)		(61,980	)
Other		(34	)		(6	)

Net cash provided by (used in) financing activities		92,305			(42,944	)


Net (Decrease) Increase in Cash and Cash Equivalents		(1,056	)		99,066
Cash and Cash Equivalents at Beginning of Period		6,777			5,619

Cash and Cash Equivalents at End of Period	$	5,721		$	104,685


Cash Paid During the Year for:
Interest	$	43,075		$	46,904

Income Taxes:
Income taxes paid	$	4,215		$	4,935
Income taxes refunded		88			1,893

Income taxes, net	$	4,127		$	3,042


Noncash Investing and Financing Activities:
Accrued construction expenditures	$	3,384		$	4,937

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity (Unaudited)

(In thousands except per share amounts)


	Common Stock						Retained			Accumulated Other Comprehensive
	Shares			Amount			Earnings			Income (Loss)			Total

Balance, October 31, 2010		72,282		$	445,640		$	519,831		$	(530	)	$	964,941

Comprehensive Income:
Net income								123,145						123,145
Other comprehensive income											443			443

Total comprehensive income														123,588
Common Stock Issued		648			18,623									18,623
Common Stock Repurchased		(800	)		(23,004	)								(23,004	)
Costs of Rescission Offer								(6	)					(6	)
Tax Benefit from Dividends Paid on ESOP Shares								76						76
Dividends Declared ($.86 per share)								(61,980	)					(61,980	)

Balance, July 31, 2011		72,130		$	441,259		$	581,066		$	(87	)	$	1,022,238


Balance, October 31, 2011		72,318		$	446,791		$	550,584		$	(452	)	$	996,923

Comprehensive Income:
Net income								121,806						121,806
Other comprehensive loss											(2	)		(2	)

Total comprehensive income														121,804
Common Stock Issued		545			16,558									16,558
Common Stock Repurchased		(800	)		(26,528	)								(26,528	)
Tax Benefit from Dividends Paid on ESOP Shares								82						82
Dividends Declared ($.89 per share)								(64,068	)					(64,068	)

Balance, July 31, 2012		72,063		$	436,821		$	608,404		$	(454	)	$	1,044,771

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

1. Summary of Significant Accounting Policies

Unaudited Interim Financial Information

The consolidated financial statements have not been audited. We have prepared the unaudited consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements prepared in conformity with generally accepted accounting principles 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, 2011.

Seasonality and Use of Estimates

The unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair statement of financial position at July 31, 2012 and October 31, 2011, the results of operations for the three months and nine months ended July 31, 2012 and 2011, cash flows for the nine months ended July 31, 2012 and 2011 and stockholders’ equity for the nine months ended July 31, 2012 and 2011. Our business is seasonal in nature. The results of operations for the three months and nine months ended July 31, 2012 do not necessarily reflect the results to be expected for the full year.

We make estimates and assumptions when preparing the consolidated financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates.

Significant Accounting Policies

Our accounting policies are described in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2011. There were no significant changes to those accounting policies during the nine months ended July 31, 2012.

Rate-Regulated Basis of Accounting

Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods.

Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and regulatory liabilities that would result in an adjustment to net income. Our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or future rate proceedings.

Regulatory assets and liabilities in the consolidated balance sheets as of July 31, 2012 and October 31, 2011 are as follows.


In thousands	July 31, 2012		October 31, 2011

Regulatory assets	$	227,886	$	200,135
Regulatory liabilities		485,368		466,953

Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. For information on related party transactions, see Note 12 to the consolidated financial statements in this Form 10-Q.

Fair Value Measurements

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

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

For the fair value measurements of our derivatives and marketable securities, see Note 8 to the consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 9 to our Form 10-K for the year ended October 31, 2011. 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, 2011. There were no significant changes to these fair value methodologies during the three months ended July 31, 2012.

Recently Issued Accounting Guidance

In December 2011, the Financial Accounting Standards Board issued accounting guidance to improve disclosures and make information more comparable to International Financial Reporting Standards regarding

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

2. Regulatory Matters

On February 26, 2010, we filed a petition with the Tennessee Regulatory Authority (TRA) to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would deny us recovery of $1.5 million. In October 2011, the TRA issued an order denying us the recovery of $1.5 million of franchise fees consistent with its April 2010 motion, and we recorded $1.5 million in operations and maintenance expenses. In November 2011, we filed for reconsideration, which was granted on November 21, 2011. On February 13, 2012, a hearing on this matter was held before the TRA. On May 7, 2012, the TRA approved the recovery of an additional $.5 million in under-collected Nashville franchise fees covering years 2002 through May 2005, which we recorded as a reduction in operations and maintenance expenses.

On June 15, 2012, we filed with the Public Service Commission of South Carolina (PSCSC) a quarterly monitoring report for the twelve months ended March 31, 2012 and a cost and revenue study as permitted by the Natural Gas Rate Stabilization Act of 2005 requesting a change in rates from those approved by the PSCSC in the October 2011 order. On August 31, 2012, a settlement agreement with the Office of Regulatory Staff was filed with the PSCSC addressing our proposed rate changes. The settlement, if approved, will result in a $1.1 million annual decrease in margin based on a return on equity of 11.3%, effective November 1, 2012. We are waiting on a ruling by the PSCSC at this time.

On July 12, 2012, the PSCSC held a hearing on the annual review of our purchased gas costs and gas purchasing policies for the twelve months ended March 31, 2012. Prior to this hearing, on July 2, 2012, we and the Office of Regulatory Staff filed a joint settlement agreement that stated that our gas purchasing policies and practices during the review period were reasonable and prudent, that we had properly followed the gas cost recovery tariff provisions and relevant PSCSC orders and that we had managed our hedging program in a reasonable and prudent manner. On August 15, 2012, the PSCSC approved our purchased gas adjustments and found our gas purchasing policies to be prudent for the period under review.

On August 1, 2012, we filed testimony with the North Carolina Utilities Commission (NCUC) in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2012. A hearing on this matter has been scheduled for October 2, 2012. We are waiting on a ruling by the NCUC at this time.

3. Earnings per Share

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

A reconciliation of basic and diluted EPS for the three months and nine months ended July 31, 2012 and 2011 is presented below.


	Three Months						Nine Months
In thousands except per share amounts	2012			2011			2012		2011

Net Income (Loss)	$	(4,613	)	$	(8,703	)	$	121,806	$	123,145


Average shares of common stock outstanding for basic earnings per share		71,936			72,007			71,933		72,010
Contingently issuable shares under incentive compensation plans *		—			—			300		225

Average shares of dilutive stock		71,936			72,007			72,233		72,235


Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.06	)	$	(0.12	)	$	1.69	$	1.71
Diluted	$	(0.06	)	$	(0.12	)	$	1.69	$	1.70

*	For the three months ended July 31, 2012 and 2011, the inclusion of 300 and 204 contingently issuable shares, respectively, would have been antidilutive.

4. Long-Term Debt Instruments

On March 27, 2012, we entered into an agreement to issue $300 million of fifteen-year senior unsecured notes in a private placement with a blended interest rate of 3.54%. On July 16, 2012, we issued $100 million with an interest rate of 3.47%. On or around October 15, 2012, we will issue the remaining $200 million with an interest rate of 3.57%. Both issuances will mature on July 16, 2027. These proceeds will be used for general corporate purposes, including the repayment of short-term debt incurred in part for the funding of capital expenditures.

5. Short-Term Debt Instruments

We have a $650 million three-year revolving syndicated credit facility that expires on January 25, 2014. The credit facility has an option to expand up to $850 million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million. The facility provides a line of credit for letters of credit of $10 million, of which $2.9 million and $3.5 million were issued and outstanding at July 31, 2012 and October 31, 2011, 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 LIBOR rate plus from 65 to 150 basis points, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2014 provided that we are in compliance with all terms of the agreement. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the period.

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

As of July 31, 2012, we have $400 million of notes outstanding under the CP program with original maturities ranging from 11 to 28 days from their dates of issuance. A portion of these notes in the amount of $200 million will be repaid from the proceeds received from the notes we will issue in October 2012, as discussed in Note 4 to the consolidated financial statements in this Form 10-Q. Since the amount of $200 million of the notes outstanding under the CP program are expected to be refinanced with long-term debt, this amount has been reclassified as “Long-term debt” in the consolidated balance sheets as of July 31, 2012. The remaining balance of $200 million under the CP program is included in “Short-term debt.”

Our outstanding short-term bank borrowings, as included in “Short-term debt” in the consolidated balance sheets, were $331 million, as of October 31, 2011, under our revolving syndicated credit facility in LIBOR cost-plus loans.

A summary of the short-term debt activity for the three and nine months ended July 31, 2012 is as follows.


	Commercial Paper						Credit Facility						Total Borrowings
In millions	Three Months			Nine Months			Three Months			Nine Months			Three Months			Nine Months

Minimum amount outstanding during period ⁽¹⁾	$	375		$	—		$	—		$	—		$	375		$	328.5
Maximum amount outstanding during period ⁽¹⁾		480			480			5			475.5			480			480
Minimum interest rate during period ⁽²⁾		0.35	%		0.22	%		1.15	%		1.15	%		0.35	%		0.22	%
Maximum interest rate during period		0.41	%		0.41	%		1.15	%		1.20	%		1.15	%		1.20	%
Weighted average interest rate during period		0.39	%		0.38	%		1.15	%		1.17	%		0.39	%		0.76	%

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

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

Our revolving syndicated credit facility’s financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and our actual ratio was 53% at July 31, 2012.

For information on discussions regarding a proposed amendment and extension of our credit facility, see Note 15 to the consolidated financial statements in this Form 10-Q.

6. Capital Stock

Changes in common stock for the nine months ended July 31, 2012 are as follows.


In thousands	Shares			Amount

Balance, October 31, 2011		72,318		$	446,791
Issued to participants in the Employee Stock Purchase Plan (ESPP)		22			657
Issued to the Dividend Reinvestment and Stock Purchase Plan		499			15,138
Issued to participants in the Incentive Compensation Plan (ICP)		24			763
Shares repurchased under Accelerated Share Repurchase agreement		(800	)		(26,528	)

Balance, July 31, 2012		72,063		$	436,821

7. Marketable Securities

We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see Note 10 to the consolidated financial statements in this Form 10-Q.

We have classified these marketable securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value on the consolidated balance sheets with any gains or losses recognized currently in earnings. We do not intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their investments at any time. We have matched the current portion of the deferred compensation liability with the current asset and the noncurrent deferred compensation liability with the noncurrent asset; the current portion is included in “Other current assets” in the consolidated balance sheets.

The money market investments in the trust approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on the quoted market prices as traded on the exchanges. The composition of these securities as of July 31, 2012 and October 31, 2011 is as follows.


	July 31, 2012				October 31, 2011
In thousands	Cost		Fair Value		Cost		Fair Value

Current trading securities:
Money markets	$	—	$	—	$	—	$	—
Mutual funds		149		167		47		52

Total current trading securities		149		167		47		52


Noncurrent trading securities:
Money markets		238		238		217		217
Mutual funds		1,731		1,899		1,107		1,222

Total noncurrent trading securities		1,969		2,137		1,324		1,439


Total trading securities	$	2,118	$	2,304	$	1,371	$	1,491

8. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our derivative instruments and the fair value of the right to reclaim cash collateral. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of July 31, 2012 and October 31, 2011, we had long gas purchase options providing total coverage of 40.3 million dekatherms and 38.1 million dekatherms, respectively. The long gas purchase options held at July 31, 2012 are for the period from September 2012 through July 2013.

Fair Value Measurements

We use financial instruments 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, 2011.

The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2012 and October 31, 2011. 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, 2012 and 2011.

Fair Value Measurements as of July 31, 2012


In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value

Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	3,565	$	—	$	—	$	3,565
Debt and equity securities held as trading securities:
Money markets		238		—		—		238
Mutual funds		2,066		—		—		2,066

Total recurring fair value assets	$	5,869	$	—	$	—	$	5,869

Fair Value Measurements as of October 31, 2011


In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value

Recurring Fair Value Measurements:
Assets:
Derivatives held for distribution operations	$	2,772	$	—	$	—	$	2,772
Debt and equity securities held as trading securities:
Money markets		217		—		—		217
Mutual funds		1,274		—		—		1,274

Total recurring fair value assets	$	4,263	$	—	$	—	$	4,263

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

“Amounts due from customers” in the consolidated balance sheets. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.

Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at fair value” in the consolidated balance sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.

In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury bench mark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.


In thousands	Carrying Amount		Fair Value

As of July 31, 2012 ⁽¹⁾	$	775,000	$	955,671
As of October 31, 2011		675,000		831,323

⁽¹⁾	This amount excludes $200,000 of debt under the CP program reclassified to “Long-term debt” in the consolidated balance sheets for presentation purposes, which approximates fair value. See Note 5 - Short-Term Debt Instruments for additional information.

Quantitative and Qualitative Disclosures

The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs approved by our state regulatory commissions, and thus are not accounted for as hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value amounts are presented on a gross basis and do not reflect any netting of asset and liability amounts or cash collateral amounts under master netting arrangements.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of July 31, 2012 and October 31, 2011.

Fair Value of Derivative Instruments


In thousands	Fair Value July 31, 2012		Fair Value October 31, 2011

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments:
Current Assets — Gas purchase derivative assets (September 2012-July 2013)	$	3,565

Current Assets — Gas purchase derivative assets (December 2011-October 2012)			$	2,772

We purchase natural gas for our regulated operations for resale under tariffs approved by state regulatory commissions. We recover the cost of gas purchased for regulated operations through PGA procedures. Our risk management policies allow us to use financial instruments to hedge commodity price risks, but not for

speculative trading. The strategy and objective of our hedging programs is to use these financial instruments to provide some level of protection against significant price increases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these financial derivatives is initially recorded as a component of deferred gas costs and recognized in the consolidated statements of operations and comprehensive income as a component of cost of gas when the related costs are recovered through our rates.

The following table presents the impact that financial instruments not designated as hedging instruments under derivative accounting standards would have had on our consolidated statements of operations and comprehensive income for the three months and nine months ended July 31, 2012 and 2011, absent the regulatory treatment under our approved PGA procedures.


In thousands	Amount of Loss Recognized on Derivatives and Deferred Under PGA Procedures								Location of Loss Recognized through PGA Procedures
	Three Months Ended July 31				Nine Months Ended July 31
	2012		2011		2012		2011

Gas purchase options	$	1,445	$	1,687	$	6,733	$	7,812		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 Tennessee Incentive Plan approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.

Risk Management

Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.

We seek to identify, assess, monitor and manage risk in accordance with defined policies and procedures under an Enterprise Risk Management program. In addition, we have an Energy Price Risk Management Committee that monitors compliance with our hedging programs, policies and procedures.

9. Commitments and Contingent Liabilities

Long-term contracts

We routinely enter into long-term gas supply commodity and capacity commitments and other agreements that commit future cash flows to acquire services we need in our business. These commitments include pipeline and storage capacity contracts and gas supply contracts to provide service to our customers and telecommunication and information technology contracts and other purchase obligations. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are generally fully recoverable through our PGA procedures. The time periods for pipeline and storage capacity contracts are up to twenty years. The time periods for gas supply contracts are up to 15 months. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service are up to four years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.

Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (FERC) in order to maintain our right to access the natural gas storage or the pipeline capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the consolidated statements of operations and comprehensive income as part of gas purchases and included in cost of gas.

Leases

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

Legal

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

Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $2.9 million in letters of credit that were issued and outstanding at July 31, 2012. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements in this Form 10-Q.

Environmental Matters

Our three regulatory commissions have authorized us to utilize deferral accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded.

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

There are four MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated and for which we have an investigation and remediation liability. In fiscal year 2012, we have performed soil remediation work at our Reidsville site. In July 2012, the North Carolina Department of Environment and Natural Resources (NCDENR) approved our proposed groundwater investigation work plan, which includes installing five monitoring wells scheduled to be completed in our fiscal year 2012. We have incurred $.6 million of remediation costs through July 31, 2012.

As part of a voluntary agreement with the NCDENR, we conducted and completed soil remediation for the Hickory, North Carolina MGP site. The soil remediation report was filed with the NCDENR in October 2010. We continue to conduct quarterly groundwater monitoring at this site in accordance with our site remediation plan. We have incurred $1.4 million of remediation costs on this site through July 31, 2012.

In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been completed, and a

final consent order imposing land usage restrictions on the property was approved and signed by the TDEC in June 2010. The final consent order required two years of semi-annual groundwater monitoring, which has been completed. We have incurred $1.5 million of remediation costs through July 31, 2012.

During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville liquefied natural gas (LNG) facility. The molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required at the site for this issue. In September 2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site. On April 11, 2012, we entered into a no admit/no deny ACO that imposed a fine of $40,000, unpaid annual fees totaling $18,000 and $1,860 for investigative and administrative costs. As part of the ACO, we are required to develop a site assessment plan to determine the extent of the groundwater contamination related to the sieve burial, a groundwater remediation strategy and a groundwater and surface water site wide monitoring program. Upon acceptance by the NCDENR of the groundwater remediation plan, we will then be required to develop a program for implementation of the plan within thirty days. Site assessment activities began in July 2012. Our estimate of the total cost of the groundwater remediation at this site is $.4 million for which we have recorded a liability.

The Huntersville LNG facility also was originally coated with lead-based paint. As a precautionary measure to ensure that no lead contamination occurs, removal of lead-based paint from the site was initiated in spring 2010. Lead-based paint removal began in July 2012 on the LNG tank. Additional facilities at our Huntersville LNG plant site are being evaluated for lead-based paint removal with work scheduled for our fiscal year 2012. We have incurred $3.2 million of remediation costs through July 31, 2012 for the Huntersville LNG facility.

Our Nashville LNG facility was also originally coated with lead-based paint. We completed the remediation of the facility in May 2012 and incurred $.5 million of remediation costs.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina resource center continues to operate USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina resource centers had their tanks removed, and we do not anticipate significant environmental remediation with respect to the removal process. The South Carolina Department of Health and Environmental Control requested that we conduct an initial groundwater assessment at our Greenville, South Carolina site to determine its current groundwater quality condition. This assessment is scheduled to be completed in our fiscal year 2012. As of July 31, 2012, our estimated undiscounted environmental liability for USTs for which we retain remediation responsibility is $.3 million.

For all matters discussed above, as of July 31, 2012, our estimated undiscounted environmental liability totaled $2.8 million consisting of $1.1 million for the MGP sites for which we retain remediation responsibility, $1 million for the LNG facilities, $.4 million for the groundwater remediation at the Huntersville LNG site and $.3 million for the USTs not yet remediated. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others.

Further evaluation of the MGP and UST sites, removal of lead-based paint at our LNG site, and groundwater remediation 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, 2011.

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, 2012 and 2011 are presented below.


	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2012			2011			2012		2011		2012			2011

Service cost	$	2,230		$	1,931		$	10	$	11	$	347		$	350
Interest cost		2,680			2,869			51		52		337			374
Expected return on plan assets		(4,967	)		(5,157	)		—		—		(388	)		(384	)
Amortization of transition obligation		—			—			—		—		167			167
Amortization of prior service (credit) cost		(548	)		(548	)		20		5		—			—
Amortization of actuarial loss		1,724			1,110			12		11		—			—

Total	$	1,119		$	205		$	93	$	79	$	463		$	507

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2012 and 2011 are presented below.


	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2012			2011			2012		2011		2012			2011

Service cost	$	7,180		$	6,381		$	29	$	34	$	1,040		$	1,049
Interest cost		7,980			8,268			153		156		1,011			1,121
Expected return on plan assets		(15,217	)		(15,456	)		—		—		(1,163	)		(1,150	)
Amortization of transition obligation		—			—			—		—		500			500
Amortization of prior service (credit) cost		(1,648	)		(1,648	)		61		15		—			—
Amortization of actuarial loss		4,474			2,660			37		31		—			—

Total	$	2,769		$	205		$	280	$	236	$	1,388		$	1,520

In January 2012, we contributed $.5 million to the money purchase pension plan. We anticipate that we will contribute the following amounts to our other plans in 2012.


In thousands

Nonqualified pension plan	$	517
Qualified pension plan		—
OPEB plan		1,600

We have a defined contribution restoration (DCR) plan that we fund annually and that covers all officers at the vice president level and above. For the nine months ended July 31, 2012, we contributed $.4 million to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral plan for the benefit of all director-level employees and officers; company contributions are not made to this plan. Both deferred compensation plans are funded through rabbi trusts with a bank as the trustee. As of July 31, 2012, we have a liability of $2.5 million for these plans.

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

11. Employee Share-Based Plans

Under our shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the three months and nine months ended July 31, 2012 and 2011, we recorded compensation expense, and as of July 31, 2012 and October 31, 2011, we have accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. The liability is re-measured to market value at the settlement date.

In December 2010, a long-term retention stock unit award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award will vest for participants who have met the retention requirements at the end of a three-year period ending in December 2013 in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation Committee of our Board of Directors has the discretion to accelerate the vesting of all or a portion of a participant’s units. For the three months and nine months ended July 31, 2012 and 2011, we recorded compensation expense, and as of July 31, 2012 and October 31, 2011, we have accrued a liability for these awards based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value at the settlement date.

Also under our approved 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, 2012, we recorded compensation expense, and as of July 31, 2012, we have accrued a liability for this award based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value at the settlement date.

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

The compensation expense related to the incentive compensation plans for the three months and nine months ended July 31, 2012 and 2011, and the amounts recorded as liabilities as of July 31, 2012 and October 31, 2011 are presented below.


	Three Months					Nine Months

In thousands	2012		2011			2012		2011

Compensation expense	$	2,119	$	(1,106	)	$	4,195	$	1,060

	July 31,		October 31,
	2012		2011

Liability	$	9,096	$	5,015

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

12. Equity Method Investments

The consolidated financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method investments in non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in the consolidated statements of operations and comprehensive income.

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

In October 2009, we reached an agreement with Progress Energy Carolinas, Inc., now a subsidiary of Duke Energy Corporation, to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide delivery service, we executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement on Cardinal by 149,000 dekatherms per day to serve Progress Energy Carolinas. This required Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system by up to 199,000 dekatherms per day of firm capacity for us and another customer. As an equity venture partner of Cardinal, we made capital contributions related to this system expansion beginning in January 2011 and continued on a periodic basis through June 2012. Since the project is complete and in service, we do not anticipate making any additional contributions related to this expansion. As of July 31, 2012, our current fiscal year contributions related to this expansion were $3.6 million, and our total contributions related to this expansion were $9.8 million. Cardinal’s expansion service for the project was placed into service on June 1, 2012.

Our natural gas delivery service for the Progress Energy Carolinas’ Wayne County generation project was placed into service on June 1, 2012, and our service subscription to Cardinal’s capacity following the system expansion increased from approximately 37% to approximately 53%. Subsequent to the project being placed into service, members’ capital was replaced with $45 million of long-term debt issued by Cardinal on June 22, 2012, and we received a distribution of $5.4 million as a partial return of our capital contributions.

We have related party transactions as a transportation customer of Cardinal, and we record in cost of gas the transportation costs charged by Cardinal. For each period of the three months and nine months ended July 31, 2012 and 2011, these transportation costs and the amounts we owed Cardinal as of July 31, 2012 and October 31, 2011 are as follows.


	Three Months				Nine Months
In thousands	2012		2011		2012		2011

Transportation costs	$	2,030	$	1,035	$	4,077	$	3,070

	July 31, 2012		October 31, 2011

Trade accounts payable	$	855	$	349

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

We have related party transactions as a customer of Pine Needle, and we record in cost of gas the storage costs charged by Pine Needle. For each period of the three months and nine months ended July 31, 2012 and 2011, these gas storage costs and the amounts we owed Pine Needle as of July 31, 2012 and October 31, 2011 are as follows.


	Three Months				Nine Months
In thousands	2012		2011		2012		2011

Gas storage costs	$	2,714	$	2,518	$	7,696	$	8,159

	July 31, 2012		October 31, 2011

Trade accounts payable	$	914	$	849

We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly-owned subsidiary of AGL Resources, Inc. SouthStar primarily sells natural gas to residential, commercial and industrial customers in the southeastern United States and Ohio with most of its business being conducted in the unregulated retail gas market in Georgia. We account for our investment in SouthStar using the equity method, as we have board representation with voting rights equal to GNGC on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For each period of the three months and nine months ended July 31, 2012 and 2011, our operating revenues from these sales and the amounts SouthStar owed us as of July 31, 2012 and October 31, 2011 are as follows.


	Three Months				Nine Months
In thousands	2012		2011		2012		2011

Operating revenues	$	1,017	$	2,184	$	1,247	$	2,819

	July 31, 2012		October 31, 2011

Trade accounts receivable	$	351	$	736

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

We have related party transactions as a customer of Hardy Storage and record in cost of gas the storage costs charged by Hardy Storage. For each period of the three months and nine months ended July 31, 2012 and 2011, these gas storage costs and the amounts we owed Hardy Storage as of July 31, 2012 and October 31, 2011 are as follows.


	Three Months				Nine Months
In thousands	2012		2011		2012		2011

Gas storage costs	$	2,425	$	2,425	$	7,276	$	7,276

	July 31, 2012		October 31, 2011

Trade accounts payable	$	808	$	808

13. Variable Interest Entities

Under accounting guidance, a variable interest entity (VIE) is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor is the entity that has the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As of July 31, 2012, we have determined that we are not the primary beneficiary, as defined by the authoritative guidance related to consolidations, in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements in this Form 10-Q. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of July 31, 2012 and October 31, 2011, our investment balances are as follows.


In thousands	July 31, 2012		October 31, 2011

Cardinal	$	17,355	$	18,323
Pine Needle		18,637		18,690
SouthStar		17,661		17,536
Hardy Storage		32,054		30,572

Total equity method investments in non-utility activities	$	85,707	$	85,121

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, including the operations of merchandising and its related service work and home warranty programs, with activities conducted by the parent company. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures that are held by our wholly owned subsidiaries.

Operations of the regulated utility segment are reflected in “Operating Income (Loss)” in the consolidated statements of operations and comprehensive income. Operations of the non-utility activities segment are included in the consolidated statements of operations and comprehensive income in “Income from equity method investments” and “Non-operating income.”

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from 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, 2011.

Operations by segment for the three months and nine months ended July 31, 2012 and 2011 are presented below.


In thousands	Regulated Utility						Non-utility Activities						Total
	2012			2011			2012			2011			2012			2011

Three Months

Revenues from external customers	$	161,123		$	197,274		$	—		$	—		$	161,123		$	197,274
Margin		86,460			81,963			—			—			86,460			81,963
Operations and maintenance expenses		59,248			53,351			14			33			59,262			53,384
Income from equity method investments		—			—			3,290			2,360			3,290			2,360
Operating income (loss) before income taxes		(6,595	)		(6,722	)		(86	)		59			(6,681	)		(6,663	)
Income (loss) before income taxes		(10,662	)		(17,750	)		3,205			2,418			(7,457	)		(15,332	)

Nine Months

Revenues from external customers	$	941,395		$	1,241,897		$	—		$	—		$	941,395		$	1,241,897
Margin		478,647			484,900			—			—			478,647			484,900
Operations and maintenance expenses		178,155			163,344			59			80			178,214			163,424
Income from equity method investments		—			—			21,234			22,500			21,234			22,500
Operating income (loss) before income taxes		197,316			215,188			(217	)		(85	)		197,099			215,103
Income before income taxes		180,108			179,871			21,016			22,426			201,124			202,297

Reconciliations to the consolidated statements of operations and comprehensive income for the three months and nine months ended July 31, 2012 and 2011 are presented below.


In thousands	Three Months						Nine Months
	2012			2011			2012			2011

Operating Income:
Segment operating income (loss) before income taxes	$	(6,681	)	$	(6,663	)	$	197,099		$	215,103
Utility income taxes		4,082			7,111			(71,228	)		(71,003	)
Non-utility activities before income taxes		86			(59	)		217			85

Operating income (loss)	$	(2,513	)	$	389		$	126,088		$	144,185


Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(7,457	)	$	(15,332	)	$	201,124		$	202,297
Income taxes		2,844			6,629			(79,318	)		(79,152	)

Net income (loss)	$	(4,613	)	$	(8,703	)	$	121,806		$	123,145

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 related to regulatory matters, see Note 2 to the consolidated financial statements.

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

Forward-Looking Statements

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

•

Regulatory issues. Deregulation, regulatory restructuring and other regulatory issues may affect us and those from whom we purchase natural gas transportation and storage service, including issues that affect allowed rates of return, terms and conditions of service, rate structures and financings. We monitor our ability to earn appropriate rates of return and initiate general rate proceedings as needed.

•

Customer growth and consumption. Residential, commercial, industrial and power generation growth and energy consumption in our service areas may change. The ability to retain and grow our customer base, the pace of that growth and the levels of energy consumption are impacted by general business and economic conditions, such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and by fluctuations in the wholesale prices of natural gas and competitive energy sources. Large-volume industrial customers may switch to alternate fuels or bypass our systems or shift to special competitive contracts or to tariff rates that are at lower-per unit margins than that customer’s existing rate.

•

Competition in the energy industry. We face competition in the energy industry, such as from electric companies, energy marketing and trading companies, fuel oil and propane dealers, renewable energy companies and coal companies, and we expect this competitive environment to continue.

•

The capital-intensive nature of our business. In order to maintain growth, we must invest in our natural gas transmission and distribution systems each year. The cost of and the ability to complete these capital projects may be affected by the ability to obtain and the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, cost and timing of project development-related contracts and approvals, project development delays, federal and state tax policies, and the cost and availability of labor and materials. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost and timing of a project.

•

Access to capital markets. Our internally generated cash flows are not adequate to finance the full cost of capital expenditures. As a result, we rely on access to both short-term and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. Changes in the capital markets, our financial condition or the financial condition of our lenders or investors could affect access to and cost of capital.

•

Changes in the availability and cost of natural gas. To meet firm customer requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure delivery to our distribution system

while also ensuring that our supply and capacity contracts allow us to remain competitive. Natural gas is an unregulated commodity market subject to supply and demand and price volatility. Producers, marketers and pipelines are subject to operating, regulatory and financial risks associated with exploring, drilling, producing, gathering, marketing and transporting natural gas and have risks that increase our exposure to supply and price fluctuations. Since such risks may affect the availability and cost of natural gas, they also may affect the competitive position of natural gas relative to other energy sources.

•

Changes in weather conditions. Weather conditions and other natural phenomena can have a material impact on our earnings. Severe weather conditions, including destructive weather patterns such as hurricanes, tornadoes and floods, can impact our customers, our suppliers and the pipelines that deliver gas to our distribution system and our distribution and transmission assets. Weather conditions directly influence the supply, demand, distribution and cost of natural gas.

•

Changes in and cost of compliance with laws and regulations. We are subject to extensive federal, state and local laws and regulations. Environmental, safety, system integrity, tax and other laws and regulations, including those related to carbon regulation, may change. Compliance with such laws and regulations could increase capital or operating costs, affect our reported earnings or cash flows, increase our liabilities or change the way our business is conducted.

•

Ability to retain and attract professional and technical employees. To provide quality service to our customers and meet regulatory requirements, we are dependent on our ability to recruit, train, motivate and retain qualified employees.

•

Changes in accounting regulations and practices. We are subject to accounting regulations and practices issued periodically by accounting standard-setting bodies. New accounting standards may be issued that could change the way we record revenues, expenses, assets and liabilities, and could affect our reported earnings or increase our liabilities.

•

Earnings from our equity method investments. We invest in companies that have risks that are inherent in their businesses, and these risks may negatively affect our earnings from those companies.

•

Changes in outstanding shares. The number of outstanding shares may fluctuate due to new issuances or repurchases under our Common Stock Open Market Purchase Program.

Other factors may be described elsewhere in this report. All of these factors are difficult to predict, and many of them are beyond our control. For these reasons, you should not place undue reliance on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “should,” “could,” “assume,” “estimate,” “forecast,” “future,” “indicate,” “outlook,” “plan,” “predict,” “seek,” “target,” “would” and variations of such words and similar expressions are intended to identify forward-looking statements.

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

Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy services company whose principal business is the distribution of natural gas to over one million residential, commercial, industrial and power generation customers in portions of North Carolina, South Carolina and Tennessee, including 52,300 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation.

We have two reportable business segments, regulated utility and non-utility activities, with the regulated utility segment being the largest. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system and the ability to recover the costs and expenses of the business in the rates charged to customers. The non-utility activities segment consists of our equity method investments in joint venture, energy-related businesses that are involved in unregulated retail natural gas marketing, and regulated interstate natural gas storage and intrastate natural gas transportation. The percentages of assets as of July 31, 2012 and earnings before taxes by segment for the nine months ended July 31, 2012 are presented below.


	Assets			Earnings Before Taxes

Regulated Utility		97	%		90	%

Non-utility Activities:
Regulated non-utility activities					3	%
Unregulated non-utility activities					7	%

Total non-utility activities		3	%		10	%

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

Our utility operations are regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina and the Tennessee Regulatory Authority (TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. The NCUC also regulates us as to the issuance of long-term debt and equity securities. We are also subject to or affected by various federal regulations. These federal regulations include regulations that are particular to the natural gas industry, such as regulations of the Federal Energy Regulatory Commission that affect the purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the U.S. Department of Transportation (DOT) that affect the design, construction, operation, maintenance, integrity, safety and security of natural gas distribution and transmission systems, and regulations of the Environmental Protection Agency relating to the environment. In addition, we are subject to numerous 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 generate revenues to recover the cost of natural gas delivered to our customers and our operating expenses and to earn a fair rate of return on invested capital for our shareholders. Our ability to earn our authorized rates of return is based in part on our ability to reduce or eliminate regulatory lag and also by improved rate designs that decouple the recovery of our approved margins from customer usage patterns impacted by seasonal weather patterns and customer conservation.

We continually assess alternative rate structures and cost recovery mechanisms that are more appropriate to the changing energy economy. The traditional utility rate design provides for the collection of margin revenue based on volumetric throughput which can be affected by customer consumption patterns, weather, conservation, price levels for natural gas or general economic conditions. Alternative rate structures and cost recovery mechanisms are rate designs and mechanisms that allow utilities to encourage energy efficiency and conservation by separating or decoupling the link between energy consumption and margin revenues, thereby aligning the interests of shareholders and customers.

In North Carolina, a margin decoupling mechanism 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 recover any under-collection of margin. In South Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin decoupling for residential and commercial customers with a one year lag. We have a weather normalization adjustment (WNA) mechanism in South Carolina that partially offsets the impact of colder- or warmer-than-normal winter weather on bills rendered during the months of November through March for residential and commercial customers. We also have a WNA mechanism in Tennessee that, effective March 1, 2012 with our rate case settlement, expanded the period to include the months of October through April for bills rendered to residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The WNA formula does not ensure full recovery of approved margin during periods when customer consumption patterns significantly vary from consumption patterns used to establish the WNA factors. 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. Also, as a result of our 2012 rate case settlement in Tennessee, our margin recovery will shift from 29% to 37% through fixed charges with a resulting decrease from 71% to 63% through volumetric charges. For the nine months ended July 31, 2012, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 71% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 18% of our utility margins, including the rate stabilization mechanism in South Carolina and WNA in South Carolina and Tennessee; and volumetric or periodic renegotiation of 11% of our utility margins, including our secondary marketing programs. For the nine months ended July 31, 2012, the margin decoupling mechanism in North Carolina increased margin by $43.6 million, and the WNA in South Carolina and Tennessee increased margin by $13.7 million, which included the additional month of April 2012 in Tennessee.

Our strategic directives are customer-centered and reflect what we believe is the inherent benefit of natural gas compared to other types of energy. They are as follows:

•

Promote the benefits of natural gas

•

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

•

Be the energy and service provider of choice

•

Achieve excellence in customer service every time

•

Preserve financial strength and flexibility

•

Execute sustainable business practices

•

Enhance our healthy, high performance culture

We believe natural gas is a safe and reliable energy source that is clean, efficient and abundant. We incorporate this belief into our pursuit of growth in our core residential, commercial, industrial and power generation markets as well as complementary energy-related investments. We want our customers to choose us because of the value of natural gas and the quality of our service to them. With the environmental and cost benefits of

using natural gas compared to coal in the generation of electricity, we have encouraged the development of gas-fired power generation facilities in our market area. In providing services to our customers, we want every customer to feel that the service provided was excellent and that we value their business. In our business practices, we promote a sustainable enterprise by reducing our impact on the environment, developing strong communities in which we operate and fostering increased awareness and use of natural gas. We support our employees with improved processes and technology to better serve our customers and to add value for our shareholders while continuing to build on our healthy, high performance culture in order to recruit, retain and motivate our workforce.

Our business model supports new clean energy technologies and energy efficiencies in the end use of natural gas. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We are promoting the direct use of natural gas in more homes, businesses, industries and vehicles as we strongly believe that the expanded use of clean, efficient, abundant and domestic natural gas with its relatively low emissions can help revitalize our economy, reduce both overall energy consumption and greenhouse gas emissions and enhance our national energy security.

The safety of our system, the public and our employees is a critical component to our ongoing success as a company. We are subject to DOT and state regulation of our pipeline and related facilities and have ongoing programs to inspect our system for corrosion and leaks. We anticipate federal legislative and regulatory enactments that will increase in scope and add further requirements to our pipeline safety and integrity programs. We will continue our efforts to educate the public about our pipeline system in an effort to decrease third party excavation damage, which is the greatest cause of any pipeline damage on our system. We encourage focused efforts to improve the safety of our industry as a whole.

The safeguarding of our information technology infrastructure is important to our business as an operational investment to integrate, standardize, centralize and streamline our operations. We rely on these technological tools for enterprise resource planning, customer service solutions for integration of planning, scheduling and dispatching of field resources, automated meter reading and customer information for billing, to name a few. We are subject to cybersecurity risks related to breaches in technologies that are used in our natural gas distribution operations and other business processes when there is unauthorized access of digital data with the intent to misappropriate information, corrupt data or cause operational disruptions. A breakdown or breach in our systems could occur and could result in the unauthorized release of individually identifiable customer or other sensitive data and have an adverse effect on our reputation, financial position, results of operations and/or cash flows. To protect confidential customer, vendor, financial and employee information, we believe we have appropriate levels of security measures in place to secure our information systems from cybersecurity attacks or breaches, in addition to having a comprehensive identity theft protection program to protect customer information together with a cybersecurity insurance policy.

Our financial strength and flexibility is critical to our success as a company. We will continue our stewardship to maintain our financial strength which includes a strong balance sheet, investment-grade credit ratings and continued access to capital markets. We continue to evaluate the strength of financial institutions with which we have working relationships to ensure access to funds for operations and capital investments. Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range of 45% to 50%. We will continue our efforts to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return for the benefit of our customers and shareholders.

We invest in joint ventures to complement or supplement income from our regulated utility operations if an opportunity aligns with our overall business strategies and allows us to leverage our core competencies. We analyze and evaluate potential projects with a major factor being projected rates of return commensurate with the risk of such projects. We participate in the governance of our ventures by having management

representatives on the governing boards. We monitor actual performance against expectations, and any decision to exit an existing joint venture would be based on many factors, including performance results and continued alignment with our business strategies.

Executive Summary

Natural gas development and production in North America continues to provide supply stability and price moderation for natural gas as an energy commodity. In the past two years, the lower price of natural gas has allowed us to significantly lower the cost of gas to our customers in North Carolina, South Carolina and Tennessee. Currently, natural gas has a price advantage over many other fuels, and it is anticipated that the cost of natural gas will remain competitive, in part due to abundant sources of shale gas reserves.

With our continued focus on residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities, we continue to educate energy consumers about the benefits of natural gas as the fuel of choice because of its comfort, affordability, efficiency and environmental benefits, as well as the reliability and safety of our service and system. Customer gains in our residential market increased 21% for the nine months ended July 31, 2012 compared to the same period in 2011 primarily from growth in our residential new construction and conversion markets. Building permits have increased modestly and lower wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. Commercial customer additions have increased 19% for the nine months ended July 31, 2012 compared to 2011, reflecting improvements in both commercial new construction activity and commercial conversion opportunities. We continue to expect gross customer addition growth for fiscal 2012 of approximately 1%.

We continue to make progress with capital projects that we expect will have current and future benefits to us and our customers, providing an appropriate return on invested capital while ensuring the safety, reliability and integrity of our utility infrastructure. We completed pipeline expansion projects in December 2011 and June 2012 to provide long-term gas delivery service to two power generation customers in our market area. We have one pipeline expansion project under construction to provide natural gas delivery service to a power generation facility currently under construction in North Carolina with a targeted in service date of June 2013. See the discussion of our forecasted capital investment related to the construction of natural gas pipelines and compressor stations to serve these new power generation facilities in “Cash Flows from Investing Activities” in Item 2 of this Form 10-Q in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We also see an opportunity in the clean energy technology of compressed natural gas (CNG) vehicles. We are executing a plan to build more CNG fueling stations in our service area for use by our own vehicle fleet as well as by third party customers. Currently, approximately 13% of our vehicle fleet uses CNG. We have six company CNG fueling stations in use, and we plan to construct up to four more in fiscal year 2012 to serve our operational facilities. Within two years, we anticipate that up to 33% of our fleet may be capable of using CNG. We are also actively pursuing other commercial fleets to utilize company CNG stations and have had discussions with commercial customers for fueling stations at customer sites where there is sufficient demand. Currently, we have over 300 customer vehicles using company CNG stations.

We continue our regulatory strategy to align our rate structures between shareholder and customer interests. On January 23, 2012, the TRA approved in a general rate proceeding an annual increase of $11.9 million in rates and charges to all customers, based on an approved rate of return of equity of 10.2%, effective March 1, 2012. This represents an increase of 6.3% above the prior annual revenue. As part of the settlement, we have shifted more of our cost recovery to the fixed portion of our customers’ bills to somewhat mitigate margin recovery fluctuations from volumetric usage. Also approved was an expansion of the WNA period to October through April with updated WNA factors and the recovery of various deferred regulatory assets.

Even though we have WNA in South Carolina and Tennessee, we are not fully insulated from the effects of weather that is significantly outside the normalization factors used in the design of these mechanisms. Significantly warmer-than-normal weather during the 2011-2012 winter heating season had a negative impact on demand for natural gas across our service territories and the collection of our normalized residential and commercial margin in South Carolina and Tennessee. Weather for the nine months ended July 31, 2012 was 21% warmer than normal and 28% warmer than the same prior year period.

To support our strategic objectives of excellence in customer service, as discussed above in the “Overview,” we have reorganized our field customer services, sales and marketing, field operations and maintenance and construction departments into functional organizations to provide a more focused and better managed approach to customer service with an end goal of increasing customer loyalty and satisfaction while improving operational efficiencies. We have also implemented centralized service scheduling work processes and system enhancements to better serve our customers in a more timely and efficient fashion.

We are in the process of a multi-year program designed to bring additional technology and automation to our field operations by providing systems and information to enable operations employees to effectively and efficiently manage our pipeline assets, ensure operating efficiencies and facilitate compliance with pipeline safety and integrity regulations. This enhanced and new systems and process program, which includes multiple projects, will be integrated with our current and future financial and other business systems.

We are actively working to control costs where possible in payroll, corporate charges and various discretionary spending items. We have benefited from cost containment measures taken during the current fiscal year, and we will continue to review areas where we could benefit further.

In order to fund our capital expansion projects as well as our ongoing capital needs, we have continued to focus on securing funds at the lowest cost for operations and capital investments. In March 2012, we initiated a commercial paper (CP) program that is backstopped by our syndicated revolving credit facility for a combined borrowing capacity of $650 million. We anticipate interest expense savings of $2.5 million annually due to the lower interest rates associated with the sale of CP compared to drawing on our syndicated revolving credit facility. Also in March 2012, we entered into an agreement to issue $300 million of senior unsecured long-term debt in a private placement with a blended interest rate of 3.54%. We issued $100 million on July 16, 2012 and will issue the remaining $200 million in October 2012 with the proceeds being used to repay short-term debt incurred in part for funding of capital expenditures. We also have an open shelf registration filed in June 2011 with the SEC that is available for future issuances of debt or equity.

Additional information on operating results for the three-month and nine-month periods follows.

Results of Operations

We reported a net loss of $4.6 million for the three months ended July 31, 2012 as compared to a net loss of $8.7 million for the same period in 2011. The following table provides a comparison of the components of our consolidated statements of operations and comprehensive income for the three months ended July 31, 2012 as compared with the three months ended July 31, 2011.

Comprehensive Statement of Operations Components


	Three Months Ended July 31
In thousands, except per share amounts	2012			2011			Variance			Percent Change

Operating Revenues	$	161,123		$	197,274		$	(36,151	)		(18.3	)%
Cost of Gas		74,663			115,311			(40,648	)		(35.3	)%

Margin		86,460			81,963			4,497			5.5	%

Operations and Maintenance		59,248			53,351			5,897			11.1	%
Depreciation		25,532			26,128			(596	)		(2.3	)%
General Taxes		8,275			9,206			(931	)		(10.1	)%
Utility Income Taxes		(4,082	)		(7,111	)		3,029			42.6	%

Total Operating Expenses		88,973			81,574			7,399			9.1	%

Operating Income (Loss)		(2,513	)		389			(2,902	)		(746.0	)%
Other Income (Expense), net of tax		1,977			2,286			(309	)		(13.5	)%
Utility Interest Charges		4,077			11,378			(7,301	)		(64.2	)%

Net Loss	$	(4,613	)	$	(8,703	)	$	4,090			47.0	%


Average Shares of Common Stock:
Basic		71,936			72,007			(71	)		(0.1	)%
Diluted		71,936			72,007			(71	)		(0.1	)%


Loss Per Share of Common Stock:
Basic	$	(0.06	)	$	(0.12	)	$	0.06			50.0	%
Diluted	$	(0.06	)	$	(0.12	)	$	0.06			50.0	%

We reported net income of $121.8 million for the nine months ended July 31, 2012 as compared to $123.1 million for the same period in 2011. The following table provides a comparison of the components of our consolidated statements of operations and comprehensive income for the nine months ended July 31, 2012 as compared with the nine months ended July 31, 2011.

Comprehensive Statement of Operations Components


	Nine Months Ended July 31
In thousands, except per share amounts	2012		2011		Variance			Percent Change

Operating Revenues	$	941,395	$	1,241,897	$	(300,502	)		(24.2	)%
Cost of Gas		462,748		756,997		(294,249	)		(38.9	)%

Margin		478,647		484,900		(6,253	)		(1.3	)%

Operations and Maintenance		178,155		163,344		14,811			9.1	%
Depreciation		76,980		76,601		379			0.5	%
General Taxes		26,196		29,767		(3,571	)		(12.0	)%
Utility Income Taxes		71,228		71,003		225			0.3	%

Total Operating Expenses		352,559		340,715		11,844			3.5	%

Operating Income		126,088		144,185		(18,097	)		(12.6	)%
Other Income (Expense), net of tax		12,664		14,219		(1,555	)		(10.9	)%
Utility Interest Charges		16,946		35,259		(18,313	)		(51.9	)%

Net Income	$	121,806	$	123,145	$	(1,339	)		(1.1	)%


Average Shares of Common Stock:
Basic		71,933		72,010		(77	)		(0.1	)%
Diluted		72,233		72,235		(2	)		—	%


Earnings Per Share of Common Stock:
Basic	$	1.69	$	1.71	$	(0.02	)		(1.2	)%
Diluted	$	1.69	$	1.70	$	(0.01	)		(0.6	)%

Key statistics are shown in the table below for the three months ended July 31, 2012 and 2011.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Three Months Ended July 31
	2012			2011			Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		7,905			8,602			(697	)	(8.1)%
Transportation Volumes		63,638			51,641			11,997		23.2%

Throughput		71,543			60,243			11,300		18.8%

Secondary Market Volumes		14,045			14,248			(203	)	(1.4)%

Customers Billed (at period end)		969,492			959,815			9,677		1.0%
Gross Customer Additions		2,670			2,245			425		18.9%

Degree Days
Actual		13			58			(45	)	(77.6)%
Normal		49			50			(1	)	(2.0)%
Percent (warmer) colder than normal		(73.5	)%		16.0	%		n/a		n/a

Number of Employees (at period end)		1,773			1,801			(28	)	(1.6)%

Key statistics are shown in the table below for the nine months ended July 31, 2012 and 2011.

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Nine Months Ended July 31
	2012			2011		Variance		Percent Change
Deliveries in Dekatherms (in thousands):
Sales Volumes		70,526			93,541		(23,015)		(24.6)%
Transportation Volumes		171,446			130,122		41,324		31.8 %

Throughput		241,972			223,663		18,309		8.2 %

Secondary Market Volumes		38,531			39,509		(978)		(2.5)%

Customers Billed (at period end)		969,492			959,815		9,677		1.0%
Gross Customer Additions		8,728			7,243		1,485		20.5 %

Degree Days
Actual		2,446			3,410		(964)		(28.3)%
Normal		3,111			3,115		(4)		(0.1)%
Percent (warmer) colder than normal		(21.4)	%		9.5%		n/a		n/a

Number of Employees (at period end)		1,773			1,801		(28)		(1.6)%

Operating Revenues

Changes in operating revenues for the three months and nine months ended July 31, 2012 compared with the same periods in 2011 are presented below.

Changes in Revenues - Increase (Decrease)


In millions	Three Months			Nine Months
Gas costs passed through to sales customers	$	(16.4	)	$	(285.8	)
Secondary market revenues		(26.2	)		(96.7	)
Margin decoupling mechanism		(.3	)		54.7
WNA		—			18.4
Power generation and industrial transportation revenues		5.5			8.8
Other		1.2			.1

Total	$	(36.2	)	$	(300.5	)

Gas costs passed through to sales customers – the decreases for the three months and nine months are primarily due to lower volumes delivered and lower gas costs passed through to sales customers.

Secondary market revenues – the decreases for the three months and nine months are due to decreased activity and margins.

Margin decoupling mechanism – the increase for the nine months is due to weather that was warmer than the prior year in North Carolina.

WNA – the increase for the nine months is due to weather that was warmer than the prior year in South Carolina and Tennessee.

Power generation and industrial transportation revenues – the increases for the three months and nine months are primarily due to increased services delivered to power generation customers.

Cost of Gas

Changes in cost of gas for the three months and nine months ended July 31, 2012 compared with the same periods in 2011 are presented below.

Changes in Cost of Gas - Increase (Decrease)


In millions	Three Months			Nine Months
Commodity gas costs passed through to sales customers	$	(17.7	)	$	(184.4	)
Gas costs—secondary market transactions		(26.8	)		(91.6	)
Pipeline demand charges		(.9	)		(6.5	)
Regulatory approved gas cost mechanisms		4.8			(11.7	)

Total	$	(40.6	)	$	(294.2	)

Commodity gas costs passed through to sales customers – the decreases for the three months and nine months are due to lower volumes sold and lower gas costs passed through to sales customers.

Gas costs—secondary market transactions—the decreases for the three months and nine months are due to lower average gas costs.

Pipeline demand charges – the decreases for the three months and nine months are primarily due to changing asset manager payments.

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

Margin

Margin, rather than revenues, is used by management to evaluate utility operations due to the 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. The commodity gas costs accounted for 36% of revenues for the nine months ended July 31, 2012 and pipeline transportation and storage costs accounted for 10%.

Changes in margin for the three months and nine months ended July 31, 2012 compared with the same periods in 2011 are presented below.

Changes in Margin - Increase (Decrease)


In millions	Three Months		Nine Months

Secondary market activity	$	.6	$	(5.1	)
Residential and commercial customers		2.0		(1.9	)
Power generation and industrial customers		1.6		.7
Net gas cost adjustments		.3		—

Total	$	4.5	$	(6.3	)

Secondary market activity – the decrease for the nine months is due to decreased activity resulting from warmer weather and less wholesale natural gas price volatility.

Residential and commercial customers – the increase for the three months is primarily due to the impact of increased rates approved in the Tennessee general rate case effective March 1, 2012 and customer growth. The decrease for the nine months is primarily due to warmer weather in jurisdictions where our rates are not fully decoupled and WNA does not perfectly adjust for variances from normal weather, slightly offset by the impact of increased rates approved in the Tennessee general rate case effective March 1, 2012 and customer growth.

Power generation and industrial customers – the increases for the three months and nine months are due to increased services in the power generation market.

In general rate proceedings, state regulatory commissions authorize us to recover a margin, which is the applicable billing rate less cost of gas, on each unit of gas delivered. The commissions also authorize us to recover margin losses resulting from negotiating lower rates to industrial customers when necessary to remain competitive. The ability to recover such negotiated margin reductions is subject to continuing regulatory approvals.

Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in this document and in our Form 10-K for the year ended October 31, 2011. These include WNA in Tennessee and South Carolina, the Natural Gas Rate Stabilization Act in South Carolina, secondary market activity in North Carolina and South Carolina, Tennessee Incentive Plan in Tennessee, the margin decoupling mechanism in North Carolina and negotiated loss treatment and the recovery of uncollectible gas costs in all three jurisdictions. We retain 25% of secondary market margins generated through off-system sales and capacity release activity in all jurisdictions, with 75% credited to customers through the incentive plans.

Operations and Maintenance Expenses

Changes in operations and maintenance expenses for the three months and nine months ended July 31, 2012 compared with the same periods in 2011 are presented below.

Changes in Operations and Maintenance Expenses - Increase/(Decrease)


In millions	Three Months		Nine Months

Employee benefits expense	$	.4	$	6.0
Payroll expense		3.5		3.6
Contract labor expense		1.7		2.4
Other		.3		2.8

Total	$	5.9	$	14.8

Employee benefits expense – the increases for the three months and nine months are due primarily to increases in medical coverage premiums and defined benefit pension costs, and for the nine months, the absence of a regulatory pension deferral in 2012.

Payroll expense – the increases for the three months and nine months are primarily due to increases in long-term incentive plan accruals.

Contract labor expense – the increases for the three months and nine months are due primarily to increased process improvements and pipeline integrity and safety efforts.

General Taxes

General taxes decreased $3.6 million for the nine months ended July 31, 2012 compared with the same period in 2011 primarily due to the accrual of a liability of $2.7 million in 2011 for sales tax on certain customer accounts and $.8 million of lower accruals in the current period for Tennessee gross receipts tax as a result of lower revenues. The quarter change was insignificant.

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 other miscellaneous expenses.

The primary change to Other Income (Expense) for the nine months ended July 31, 2012 compared with the same period in 2011 was income from equity method investments. All other changes for the three months ended July 31, 2012 compared with the same period in 2011 were insignificant.

Income from equity method investments decreased $1.3 million for the nine months ended July 31, 2012 compared with the same period in 2011 due to a $2.1 million decrease in earnings from SouthStar Energy Services LLC primarily due to lower customer usage related to warmer-than-normal weather, net of weather derivatives, and the recording of a lower of cost or market storage inventory adjustment in the current year period as compared with the prior year period, partially offset by higher retail price spreads and lower transportation and gas costs. This decrease was partially offset by a $.6 million increase in earnings from Cardinal Pipeline Company, L.L.C. (Cardinal) primarily due to higher capitalized interest from the borrowed allowance for funds used during construction and increased revenues as a result of the expansion project to serve Progress Energy Carolinas’ Wayne County generation project and lower operating and interest expenses.

Utility Interest Charges

Changes in utility interest charges for the three months and nine months ended July 31, 2012 compared with the same periods in 2011 are presented below.

Changes in Utility Interest Charges - Increase (Decrease)


In millions	Three Months			Nine Months

Borrowed allowance for funds used during construction	$	(4.7	)	$	(11.5	)
Interest expense on long-term debt		(1.1	)		(5.2	)
Regulatory interest expense, net		(1.5	)		(2.8	)
Interest expense on short-term debt		—			1.1
Other		—			.1

Total	$	(7.3	)	$	(18.3	)

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

Interest expense on long-term debt – the decreases for the three months and nine months are primarily due to the retirement of $60 million of 6.55% medium-term notes on September 26, 2011.

Regulatory interest expense, net – the decreases for the three months and nine months are primarily due to an increase in interest charged on amounts due from customers, which is recorded as interest income.

Interest expense on short-term debt – the increase for the nine months is primarily due to higher balances outstanding during the current period used for utility capital expenditures and other corporate purposes.

Financial Condition and Liquidity

To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, access to capital markets, cash generated from our investments in joint ventures and short-term debt. Our capital market strategy has continued to focus on maintaining a strong balance sheet, ensuring sufficient cash resources and daily liquidity, accessing capital markets at favorable times when needed, managing critical business risks, and maintaining a balanced capital structure through the issuance of equity or long-term debt securities or the repurchase of our equity securities.

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

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 the capacity of short-term credit available to us under our revolving syndicated credit facility and our CP program and the issuance of debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments, employee benefit plan contributions, common share repurchases and other cash needs. Liquidity has been enhanced by the extension of bonus depreciation legislation. For further information on bonus depreciation, see the following discussion of “Cash Flows from Operating Activities.”

Short-Term Debt . We have a $650 million three-year revolving syndicated credit facility that expires on January 25, 2014. The credit facility has an option to expand up to $850 million. We pay an annual fee of $30,000 plus fifteen basis points for any unused amount up to $650 million.

On March 1, 2012, we established a $650 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt.

We are in discussions with the lenders under our existing $650 million three-year revolving syndicated credit facility to amend and extend the facility, including its option to increase to $850 million, for five years from the effective date of the amendment at more favorable pricing. We have proposed that the amendment be effective in October 2012. The CP program will continue to be backstopped by the new credit facility. We anticipate annual savings of approximately $800,000 from lower unused fees and extended amortization of debt issuance costs.

During the three months ended July 31, 2012, short-term debt ranged from $375 million to $480 million, and interest rates ranged from .35% to 1.15%. During the nine months ended July 31, 2012, short-term debt ranged from $328.5 million to $480 million, and interest rates ranged from .22% to 1.20%. For further information on short-term debt activity, see Note 5 to the consolidated financial statements in this Form 10-Q.

Our short-term debt as of July 31, 2012 consists of $400 million of notes outstanding under our CP program. The notes under the CP program are expected to be refinanced in part with long-term debt that we will issue in October 2012. We have reclassified these notes, limited to the $200 million to be issued as private placement long-term debt, to “Long-term debt” in the consolidating balance sheets. For further information, see Note 4 to the consolidated financial statements in this Form 10-Q. The remaining balance of $200 million of CP notes outstanding is included in “Short-term debt” in the consolidated balance sheets.

Highlights for our short-term debt as of July 31, 2012 and for the quarter ended July 31, 2012 are presented below.

Short-Term Debt

As of July 31, 2012


In thousands	Commercial Paper			Credit Facility			Total Borrowings

End of period (July 31, 2012):
Amount outstanding	$	400,000		$	—		$	400,000
Weighted average interest rate		0.39	%		—	%		0.39	%

During the period (May 1, 2012 - July 31, 2012):
Average amount outstanding	$	413,300		$	100		$	413,300
Weighted average interest rate		0.39	%		1.15	%		0.39	%

Maximum amount outstanding:
May	$	405,000		$	—		$	405,000
June		430,000			5,000			430,000
July		480,000			—			480,000

As of July 31, 2012, we had $10 million available for letters of credit under our revolving syndicated credit facility, of which $2.9 million were issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of July 31, 2012, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $247.1 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. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas withdrawal from storage and the collection of amounts billed to customers during the November through March winter heating season. Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases injected into storage, construction activity and decreases in receipts from customers.

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

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

Because of the weak economy, including continued high unemployment, we may incur additional bad debt expense as well as experience increased customer conservation. We may incur more short-term debt to pay for gas supplies and other operating costs since collections from customers could be slower and some customers may not be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms, such as those that allow us to recover the gas cost portion of bad debt expense, are expected to mitigate the impact these factors may have on our results of operations. With the unusually warmer-than-normal winter of 2011-2012 together with lower natural gas prices this fiscal year, we have experienced lower levels of bad debt expense.

Net cash provided by operating activities was $266.1 million and $280 million for the nine months ended July 31, 2012 and 2011, respectively. Net cash provided by operating activities reflects a decrease of $1.3 million in net income for 2012 compared with 2011 primarily due to lower margin earned in 2012 as well as higher operating costs. 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 $13.6 million from October 31, 2011 primarily due to the decrease in unbilled volumes and amounts billed to customers reflecting lower gas costs and decreased $21.3 million compared with July 31, 2011 primarily due to 28% warmer weather during the current period than the same prior period. Volumes sold to weather-sensitive residential and commercial customers decreased 21.4 million dekatherms as compared with the same prior period. Total throughput increased 18.3 million dekatherms as compared with the same prior period, largely from increased volumes of 43.2 million dekatherms, or 72%, sold to and transported for power generation customers, partially offset by decreased sales to residential, commercial and industrial customers.

•

Net amounts due from customers increased $27 million from October 31, 2011 primarily due to the timing of the collection of deferred gas costs, including margin decoupling, through rates.

•

Gas in storage decreased $18.8 million in the current period primarily due to a decrease in the weighted average cost of gas and decreased volumes in storage.

•

Prepaid gas costs decreased $16.4 million in the current period primarily due to a decrease in the weighted average cost of gas and gas being made available for sale during the period. Under some gas supply contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November through March for residential and commercial customers. The WNA mechanism in Tennessee, effective March 1, 2012 as a result of our rate case settlement, applies to the months of October through April for residential and commercial billings. The WNA in South Carolina and Tennessee, which includes the additional month of April 2012 in Tennessee, generated charges to customers of $13.7 million and credits of $4.7 million in the nine months ended July 31, 2012 and 2011, 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” or “Amounts due to customers” in the consolidated balance sheets for subsequent collection from or refund to all customers in the class. The margin decoupling mechanism in North Carolina provides for the collection of our approved margin from residential and commercial customers independent of consumption patterns. The margin decoupling mechanism increased margin by $43.6 million and decreased margin by $11.1 million in the nine months ended July 31, 2012 and 2011, respectively. Our gas costs are recoverable through PGA procedures and are not affected by the WNA or the margin decoupling mechanism.

The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (the Act), enacted in December 2010, extended the 50% bonus depreciation that expired December 2009 and temporarily increased bonus depreciation for federal income tax purposes to 100% for certain qualified investments. These provisions are effective for our fiscal year tax returns for 2010-2014. Based on current capital projections and timelines, we are anticipating that bonus depreciation will reduce cash needed to pay federal income taxes during fiscal years 2010-2014 by $130-170 million as compared with cash tax needs prior to the Act. While reducing cash tax payments, bonus depreciation will increase deferred tax liabilities by a similar amount. Rate base generally consists of net utility plant in service less utility deferred income tax liabilities. Rate base upon which authorized revenue requirements are determined is expected to increase for the remainder of 2012, but less than if bonus depreciation had not been in effect.

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, reliability and energy efficiency. Increases in the price of natural gas can negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This can impact our cash needs if customer growth slows, resulting in reduced capital expenditures, or if customers conserve, resulting in reduced gas purchases and customer billings.

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

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

Cash Flows from Investing Activities . Net cash used in investing activities was $359.5 million and $138 million for the nine months ended July 31, 2012 and 2011, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the nine months ended July 31, 2012 were $351 million as compared to $137.6 million in the same prior period primarily due to expending $197.5 million for the construction of power generation service delivery projects in 2012 as compared with $32.1 million expended for these projects in the same prior period.

We have a substantial capital expansion program for the construction of transmission and distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system

infrastructure and the growth in our customer base. Significant utility construction expenditures are expected to meet long-term growth, including growth in the power generation market, and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years. We are contractually obligated to expend capital as the work is completed.

We anticipate making capital expenditures, including allowance for funds used during construction, of $270 - 290 million and $75 - 85 million in our fiscal years 2012 and 2013, respectively, to provide natural gas service for two new power generation facilities in North Carolina. These expenditures are significantly higher than we have traditionally expended for service expansions. Our estimates of utility capital expenditures shown below for 2013 and 2014 have increased from last quarter primarily due to additional transmission pipeline integrity projects. We intend to fund capital expenditures in a manner that maintains our targeted capitalization ratio of 45-50% in long-term debt and 50-55% in common equity. A portion of the funding for capital expenditures is derived from operations, including lower federal income tax payments due to bonus depreciation benefits. Additional detail for the anticipated capital expenditures follows.


In millions	2012		2013		2014

Utility capital expenditures	$	270 - 310	$	450 - 490	$	300 - 350
Power generation related capital expenditures		270 - 290		75 - 85		—

Total forecasted capital expenditures	$	540 - 600	$	525 - 575	$	300 - 350

In October 2009, we reached an agreement with Progress Energy Carolinas, now a subsidiary of Duke Energy Corporation, to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. This required us to construct 38 miles of transmission pipeline along with additional compression facilities, which was placed into service in June 2012. To provide the additional delivery service, we executed an agreement with Cardinal to expand our firm capacity requirement on Cardinal by 149,000 dekatherms per day to serve Progress Energy Carolinas. This required Cardinal to invest in a new compressor station and expanded meter stations in order to increase the capacity of its system. As an equity venture partner of Cardinal, we made capital contributions of $9.8 million related to this system expansion beginning in January 2011 through June 2012; our current fiscal year contributions related to this expansion were $3.6 million. We do not anticipate making any additional contributions related to this expansion. Cardinal’s expansion service for the project was placed into service on June 1, 2012. In June 2012, due to Cardinal obtaining permanent financing on the expansion, we received $5.4 million as a return of our capital investment. For further information regarding this agreement, see Note 12 to the consolidated financial statements in this Form 10-Q.

In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement calls for us to construct approximately 130 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2013, and our investment in the pipeline and compression facilities is supported by a long-term service agreement.

The Sutton facilities will also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. We anticipate that a portion of the cost of this project will be included in our North Carolina utility rate base because the facilities will enhance our ability to serve our other North Carolina customers. At the present time with the timing and design scope of the Sutton facilities, there is no current need to proceed with our previously announced Robeson liquefied natural gas storage project, which is dependent upon the effect of market growth in North Carolina on our need for additional system infrastructure.

In December 2011 under an agreement with Duke Energy Carolinas, we placed into service the natural gas pipeline facilities that we constructed to provide natural gas delivery service to their Rockingham County, North Carolina power generation facility.

Cash Flows from Financing Activities . Net cash provided by (used in) financing activities was $92.3 million and ($42.9) million for the nine months ended July 31, 2012 and 2011, respectively. Funds are primarily provided from short-term borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP), our employee stock purchase plan (ESPP) and bonus depreciation. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to retire long-term debt, pay down outstanding short-term debt, repurchase common stock under the common stock repurchase program and pay quarterly dividends on our common stock.

Outstanding debt under our syndicated revolving credit facility and CP program increased to $400 million as of July 31, 2012 from $331 million as of October 31, 2011 primarily due to higher capital expenditures. For further information on short-term debt, see Note 5 to the consolidated financial statements in this Form 10-Q and the previous discussion of “Short-Term Debt” in “Financial Condition and Liquidity.”

We have an open combined debt and equity shelf registration filed in July 2011 that is available for future use. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for our investments in our subsidiaries, and for repurchases of shares of our common stock. Pending such use, we may temporarily invest any net proceeds that are not applied to the purposes mentioned above in investment grade securities.

We continually monitor customer growth trends, opportunities in our markets, the economic recovery of our service area and the timing of any infrastructure investments that would require the need for additional long-term debt. On March 27, 2012, we entered into an agreement to issue $300 million of notes in a private placement with a blended interest rate of 3.54%. On July 16, 2012, we issued notes in the amount of $100 million with an interest rate of 3.47%. On or around October 15, 2012, we will issue the remaining $200 million with an interest rate of 3.57%. Both issuances will mature on July 16, 2027. These proceeds will be used for general corporate purposes, including the repayment of short-term debt incurred in part for funding of capital expenditures.

During the nine months ended July 31, 2012 and 2011, we issued $16.5 million and $15.4 million, respectively, of common stock through DRIP and ESPP. From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2 in this Form 10-Q. During the nine months ended July 31, 2012, we repurchased and retired .8 million shares for $26.5 million, leaving a balance of 2,910,074 shares available for repurchase under the program. During the nine months ended July 31, 2011, we repurchased and retired .8 million shares for $23 million under the program.

We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of July 31, 2012, our retained earnings were not restricted. The Board of Directors is scheduled to consider our next quarterly dividend on common stock at its meeting on September 14, 2012.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. As of July 31, 2012, our capitalization as presented in our financial statements in this Form 10-Q, including current maturities of long-term debt, if any, consisted of 48% in long-term debt and 52% in common equity. Our contractual long-term debt excludes the $200 million reclassification of CP that is expected to be refinanced in October 2012 with long-term debt. Without this $200 million reclassification, as of July 31, 2012, our capitalization, including current maturities of contractual long-term debt, if any, consisted of 43% in contractual long-term debt and 57% 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, 2012 and 2011, and October 31, 2011, are summarized in the table below.


	July 31					October 31					July 31
In thousands	2012		Percentage			2011		Percentage			2011		Percentage

Short-term debt	$	200,000		9	%	$	331,000		16	%	$	269,500		13	%
Current portion of long-term debt		—		—	%		—		—	%		60,000		3	%
Long-term debt		975,000		44	%		675,000		34	%		675,000		34	%

Total debt		1,175,000		53	%		1,006,000		50	%		1,004,500		50	%
Common stockholders’ equity		1,044,771		47	%		996,923		50	%		1,022,238		50	%

Total capitalization (including short-term debt)	$	2,219,771		100	%	$	2,002,923		100	%	$	2,026,738		100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. 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. In determining our credit ratings, the rating agencies consider a number of quantitative and qualitative factors. For a listing of the more significant quantitative and qualitative factors considered by the rating agencies, see “Cash Flows from Financing Activities” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K for the year ended October 31, 2011.

As of July 31, 2012, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services (S&P) and “A3” by Moody’s Investors Service (Moody’s). Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. S&P and Moody’s have issued credit ratings on the CP program at “A1” and “P2”, respectively. Credit ratings and outlooks are opinions of the rating agencies and are subject to their ongoing review. A significant decline in our operating performance, capital structure or a significant reduction in our liquidity could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by our rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in its judgment, circumstances warrant a change.

We are subject to default provisions related to our long-term debt and short-term borrowings. Failure to satisfy any of the default provisions may result in total outstanding issues of debt becoming due. There are cross-default provisions in all of our debt agreements. As of July 31, 2012, there has been no event of default giving rise to acceleration of our debt.

Estimated Future Contractual Obligations

During the three months ended July 31, 2012, there were no material changes to our estimated future contractual obligations in Management’s Discussion and Analysis in this Form 10-Q compared to what we disclosed in our Form 10-K for the year ended October 31, 2011.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than letters of credit and operating leases. The letters of credit are discussed in Note 5 to the consolidated financial statements in this Form 10-Q. The operating leases were discussed in Note 8 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2011.

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, 2011 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, 2011.

Accounting Guidance

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

During the nine months ended July 31, 2012, there were no material changes in the way that we monitor and manage market risk and credit risk in accordance with our policies and procedures. Our exposure to and management of interest rate risk, commodity price risk and weather risk has remained the same during the nine months ended July 31, 2012. Our annual discussion of market risk was included in Item 7A of our Form 10-K as of October 31, 2011.

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, 2012, we had $400 million of debt outstanding under our CP program at an interest rate of .39%, which at July 31, 2012 was the rate for the CP program as we were not borrowing under the revolving syndicated credit facility. The carrying amount of this debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $3 million during the nine months ended July 31, 2012.

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 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

During the nine months ended July 31, 2012, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2011.

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, 2012.


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
5/1/12 - 5/31/12		—	$	—		—		2,910,074
6/1/12 - 6/30/12		—	$	—		—		2,910,074
7/1/12 - 7/31/12		—	$	—		—		2,910,074

Total		—	$	—		—

(1)

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

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of July 31, 2012, net earnings available for restricted payments were greater than retained earnings; therefore, our retained earnings were not restricted.

Item 6. Exhibits


Compensatory Contracts:

10.1		Amended and Restated Employment Agreement dated May 25, 2012 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (substantially identical agreements have been entered into with Victor M. Gaglio, Jane R. Lewis-Raymond, Karl W. Newlin, Kevin M. O’Hara and Franklin H. Yoho)

10.2		Schedule of Amended and Restated Employment Agreements with Executives

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) Consolidated Balance Sheets at July 31, 2012 and October 31, 2011; (3) Consolidated Statements of Operations and Comprehensive Income for the three months and nine months ended July 31, 2012 and 2011; (4) Consolidated Statements of Cash Flows for the nine months ended July 31, 2012 and 2011; (5) Consolidated Statements of Stockholders’ Equity for the nine months ended July 31, 2012 and 2011; and (6) Notes to Consolidated Financial Statements.

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 7, 2012				/s/ Karl W. Newlin
				Karl W. Newlin
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)

Date September 7, 2012				/s/ Jose M. Simon
				Jose M. Simon
				Vice President and Controller
				(Principal Accounting Officer)

Exhibit INDEX

Piedmont Natural Gas Company, Inc.

Form 10-Q

For the Quarter Ended July 31, 2012

Exhibits

Compensatory Contracts:



10.1		Amended and Restated Employment Agreement dated May 25, 2012 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains (substantially identical agreements have been entered into with Victor M. Gaglio, Jane R. Lewis-Raymond, Karl W. Newlin, Kevin M. O’Hara and Franklin H. Yoho)

10.2		Schedule of Amended and Restated Employment Agreements with Executives

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

Exhibit 10.1

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

THIS AMENDED AND RESTATED EMPLOYMENT AGREEMENT (the “Agreement”) dated as of May 25, 2012 by and between PIEDMONT NATURAL GAS COMPANY, INC., a North Carolina corporation (the “Corporation”), and Thomas E. Skains , (the “Officer”).

WITNESSETH :

WHEREAS, the Officer is an executive employed by the Corporation pursuant to an Employment Agreement dated December 1, 1999 (the “Existing Employment Agreement”); and

WHEREAS, the Board of Directors of the Corporation has determined that the continued retention of the services of the Officer on a long-term basis as described herein is in the best interest of the Corporation in that (a) it promotes the stability of senior management of the Corporation; (b) it enables the Corporation to obtain and retain the services of a well-qualified executive officer with extensive contacts in the natural gas industry; and (c) it secures the continued services of the Officer notwithstanding any change in control of the Corporation; and

WHEREAS, the services of the Officer, his experience and knowledge of the Corporation’s industry, and his reputation and contacts in the Corporation’s industry are valuable to the Corporation; and

WHEREAS, the Corporation considers the establishment and maintenance of a sound and vital management to be part of its overall corporate strategy and to be essential to protecting and enhancing the best interests of the Corporation and its stockholders; and

WHEREAS, the Corporation and the Officer desire to amend and restate the terms and conditions of the Existing Employment Agreement to meet current needs; and

WHEREAS, in addition to this Agreement, the parties have entered into a Severance Agreement (the “Severance Agreement”), which sets forth certain rights and obligations of the Officer and certain rights and obligations of the Corporation in the event of a “Potential Change of Control” (as defined in the Severance Agreement) or following a “Change in Control” (as defined in the Severance Agreement). Use of the phrases “Potential Change of Control” and “Change in Control” herein shall have the meanings ascribed to those phrases in the Severance Agreement.

NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, the parties hereby agree as follows:

1. Employment . The Corporation will continue to employ the Officer and the Officer hereby accepts such continued employment, upon the terms and conditions stated herein, as President & Chief Executive Officer of the Corporation. The Officer shall continue to render such administrative and management services to the Corporation as are customarily performed by persons

situated in a similar executive capacity. The Officer shall promote the business of the Corporation and perform such other duties as shall from time to time be reasonably prescribed by the Directors or the Chief Executive Officer of the Corporation. It is understood that the Officer’s continued election as an officer of the Corporation is dependent upon action by the Board of Directors of the Corporation from time to time and that, subject to the provisions of Section 7 of this Agreement, the Officer’s title and/or duties may change from time to time; provided that following a Change in Control and during the term of the Severance Agreement any action affecting a change in title and/or duties shall be subject to the Severance Agreement.

2. Base Salary . The Corporation shall pay the Officer during the term of this Agreement as compensation for all services rendered by him to the Corporation a base salary in such amounts and at such intervals as shall be commensurate with his duties and responsibilities hereunder. Initially such base salary shall be the current base salary in effect for the Officer. The Officer’s base salary may be increased from time to time to reflect the duties required of the Officer. In reviewing the Officer’s base salary, the Board of Directors of the Corporation shall consider the overall performance of the Corporation, the overall performance of the Officer and the service of the Officer rendered to the Corporation and its subsidiaries and changes in the cost of living. The Board of Directors may also provide for performance or merit increases. Participation by the Officer in any incentive, deferred compensation, stock option, stock purchase, bonus, pension, life insurance or other employee benefit plans which may be offered by the Corporation from time to time and participation in any fringe benefits provided by the Corporation shall not cause a reduction of the base salary payable to the Officer. The Officer will be entitled to such customary fringe benefits, vacation and sick leave as are consistent with the normal practices and established policies of the Corporation.

3. Participation in Incentive, Retirement and Employee Benefit Plans; Fringe Benefits . The Officer shall be entitled to participate in any plan relating to incentive compensation, stock options, stock purchase, pension, thrift, profit sharing, group life insurance, medical coverage, disability coverage, education, or other retirement or employee benefits that the Corporation has adopted, or may from time to time adopt, for the benefit of its executive employees and for employees generally, subject to the eligibility rules of such plans.

The Officer shall also be entitled to participate in any other fringe benefits which are now or may be or become applicable to the Corporation’s executive employees, including the payment of reasonable expenses for attending annual and periodic meetings of trade associations, and any other benefits which are commensurate with the duties and responsibilities to be performed by the Officer under this Agreement. Additionally, the Officer shall be entitled to such vacation and sick leave as shall be established under uniform employee policies promulgated by the Board of Directors. The Corporation shall reimburse the Officer for all out-of-pocket reasonable and necessary business expenses which the Officer may incur in connection with his service on behalf of the Corporation.

4. Term . The initial term of employment under this Agreement shall be for a one-year period commencing on the date hereof; provided that this Agreement shall automatically be extended to a full one-year period on each successive day during the term of this Agreement. The effect hereof shall be that the Agreement shall at all times remain subject to a term of one year,

unless (i) written notice has been given that the Agreement shall not be extended as provided in this Section 4, or (ii) the Agreement is terminated pursuant to Section 7. If written notice from the Corporation or the Officer is delivered to the other party advising the other party that this Agreement is not to be further extended, then upon such notice, the Agreement shall terminate on the second anniversary of the date of notice. Notwithstanding the foregoing, no extension shall cause this Agreement to extend beyond the date of the annual shareholder meeting following the date the Officer attains age sixty-five (65), or such later retirement date as may be approved pursuant to the Corporation’s Senior Officer Mandatory Retirement Policy as in effect from time to time. Upon any extension, the base salary of the extended agreement shall be the base salary in effect on the effective date of such extension.

5. Loyalty; Noncompetition

(a) The Officer shall devote his best efforts to the performance of his duties and responsibilities under this Agreement.

(b) During the term of this Agreement, or any renewals hereof, the Officer agrees he will not own, manage, operate, join, control or participate in the management, operation or control of, or be employed by or connected in any manner with any business which competes with the Corporation or any of its subsidiary corporations without the prior written consent of the Corporation. Notwithstanding the foregoing, the Officer shall be free, without such consent, to purchase or hold as an investment or otherwise, up to five percent (5%) of the outstanding stock or other securities of any corporation which has its securities publicly traded on any recognized securities exchange or in any established over-the-counter market.

The Officer shall hold in confidence all knowledge or information of a confidential nature with respect to the business of the Corporation or any subsidiary of the Corporation received by him during the term of this Agreement and will not disclose or make use of such information without the prior written consent of the Corporation.

The Officer acknowledges that it would not be possible to ascertain the amount of monetary damages in the event of a breach by the Officer under the provisions of this Section 5 and agrees that, in the event of a breach of this Section, injunctive relief enforcing the terms of this Section is an appropriate remedy.

6. Standards . The Officer shall perform his duties and responsibilities under this Agreement in accordance with such reasonable standards expected of employees with comparable positions in comparable organizations and as may be established from time to time by the Board of Directors. The Corporation will provide the Officer with the working facilities and staff customary for similar executives and necessary for him to perform his duties.

7. Termination and Termination Pay .

(a) Change of Control . Following a Change in Control and during the term of the Severance Agreement, this Agreement shall become null and void except with respect to any rights

or obligations accruing prior to the Change in Control and the rights and obligations of the Officer and the Company, including any termination of the Officer, shall be subject to the provisions of the Severance Agreement.

(b) By Death . The Officer’s employment under this Agreement shall be terminated upon the death of the Officer during the term of this Agreement, in which event the Officer’s estate shall be entitled to receive all compensation due the Officer through the last day of the calendar month in which his death shall have occurred.

(c) By Total Disability . Except for that period of time following a Change in Control and during the term of the Severance Agreement, the Officer’s employment under this Agreement shall be terminated upon the total permanent disability of the Officer during the term of this Agreement, in which event the Officer shall receive all compensation, including bonuses, through the date of determination of such disability and for a period of 90 days thereafter. For purposes of this Section, the Officer shall be deemed to have suffered permanent disability upon the determination of such status by the United States Social Security Administration or a certification to such effect by the Officer’s regular physician.

(d) By Officer . Except as provided in Section 4 of the Severance Agreement, the Officer’s employment under this Agreement may be terminated at any time by the Officer upon 60 days’ written notice to the Board of Directors. Upon such termination, the Officer shall be entitled to receive all compensation, including bonuses, through the effective date of such termination.

(e) By Corporation . Except for that period of time following a Change of Control and during the term of the Severance Agreement, the Board of Directors may terminate the Officer’s employment at any time, but any such termination by the Board of Directors, other than termination for cause, shall not prejudice the Officer’s right to continue to receive payment of all compensation and the continuance of benefits for a period of 12 months from the effective date of termination or until such time as the Officer reaches 65 years of age (whichever is less). The Officer shall have no right to receive compensation or other benefits (other than vested benefits) for any period after “termination for cause.” Termination for cause shall mean termination because of the Officer’s personal dishonesty, incompetence, willful material misconduct, breach of fiduciary duty involving personal profit, intentional failure to perform stated duties, willful material violation of a law, rule or regulation (other than traffic or traffic-related violations or similar offenses) or final cease-and-desist order, or material breach of any provisions of this Agreement.

(f) Costs and Expenses . In the event any dispute shall arise between the Officer and the Corporation as to the terms or interpretation of this Agreement, including this Section 7, whether instituted by formal legal proceedings or otherwise, including any action taken by Officer to enforce the terms of this Section 7 or in defending against any action taken by the Corporation, the Corporation shall reimburse the Officer for all costs and expenses, proceedings or actions in the event the Officer prevails in any such action.

8. Successors and Assigns .

(a) This Agreement shall inure to the benefit of and be binding upon any corporate or other successor of the Corporation that shall acquire, directly or indirectly, by conversion, merger, consolidation, purchase or otherwise, all or substantially all of the assets of the Corporation.

(b) Since the Corporation is contracting for the unique and personal skills of the Officer, the Officer shall be precluded from assigning or delegating his rights or duties hereunder without first obtaining the written consent of the Corporation.

9. Code Section 409A .

(a) Delay of Certain Payments . Notwithstanding anything in this Agreement to the contrary, if any amount or benefit that the Corporation determines would constitute non-exempt “deferred compensation” for purposes of Section 409A of the Internal Revenue Code of 1986 (the “Code”) would otherwise be payable or distributable under this Agreement by reason of the Officer’s termination of employment, then to the extent necessary to comply with Code Section 409A:

(i) if the payment or distribution is payable in a lump sum, the Officer’s right to receive payment or distribution of such non-exempt deferred compensation will be delayed until the earlier of the Officer’s death or the seventh month following the Officer’s termination of employment; and

(ii) if the payment or distribution is payable over time, the amount of such non-exempt deferred compensation that would otherwise be payable during the six (6) month period immediately following the Officer’s termination of employment will be accumulated and the Officer’s right to receive payment or distribution of such accumulated amount will be delayed until the earlier of the Officer’s death or the seventh month following the Officer’s termination of employment and paid on the earlier of such dates, without interest, and the normal payment or distribution schedule for any remaining payments or distributions will commence.

(b) Expense Reimbursements . To the extent any expense reimbursement or in-kind benefit to which the Officer is or may be entitled to receive under this Agreement constitutes non-exempt “deferred compensation” for purposes of Section 409A of the Code, then (i) such reimbursement shall be paid to the Officer as soon as administratively practicable after the Officer submits a valid claim for reimbursement, but in no event later than the last day of the Officer’s taxable year following the taxable year in which the expense was incurred, (ii) the amount of expenses eligible for reimbursement, or in-kind benefits provided, during any taxable year of the Officer shall not affect the expenses eligible for reimbursement, or in-kind benefits to be provided, in any other taxable year of the Officer, and (iii) the Officer’s right to reimbursement or in-kind benefits shall not be subject to liquidation or exchange for another benefit.

10. Modification; Waiver; Amendments . No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing, signed by the Officer and on behalf of the Corporation by such officer as may be specifically designated by the Board of Directors. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No amendments or additions to this Agreement shall be binding unless in writing and signed by both parties, except as herein otherwise provided. Any modification, waiver or amendment shall be made consistent with the terms and conditions of the Severance Agreement.

11. Applicable Law . This Agreement shall be governed in all respects whether as to validity, construction, capacity, performance or otherwise, by the laws of North Carolina.

12. Severability . The provisions of this Agreement shall be deemed severable and the invalidity or unenforceability of any provision shall not affect the validity or enforceability of the other provisions hereof.

13. Effect on Existing Employment Agreement . This Agreement contains the entire understanding between the parties hereto with respect to the Officer’s continued employment by the Corporation and supersedes in all respects the Existing Employment Agreement.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first hereinabove written.


	CORPORATION:

ATTEST:	Piedmont Natural Gas Company, Inc.

/s/ Judy Z. Mayo
Asst Secretary
	By:	/s/ Kevin M. O’Hara
		Kevin M. O’Hara
		Senior Vice President & Chief Administrative Officer

	OFFICER:

	By:	/s/ Thomas E. Skains

Exhibit 10.2

Schedule of Amended and Restated Employment Agreements with Executives

In accordance with the instructions of Item 601 of Regulation S-K, the registrant has omitted filing Amended and Restated Employment Agreements dated as of May 15, 2012 by and between Piedmont Natural Gas Company, Inc, and the following employees as exhibits to this Form 10-Q as they are identical, except as noted below, to the Amended and Restated Employment Agreement filed as Exhibit 10.1 with this Form 10-Q. These agreements were signed on behalf of the Company by Thomas E. Skains, Chairman of the Board, President and Chief Executive Officer.


Executive Officer Name	Title	Paragraph 4, 3 ^rd sentence

Victor M. Gaglio	Senior Vice President – Chief Utility Operations Officer	If written notice from the Corporation or the Officer is delivered to the other party advising the other party that this Agreement is not to be further extended, then upon such notice, the Agreement shall terminate on the anniversary of the date of notice.

Jane R. Lewis- Raymond	Senior Vice President – General Counsel, Corporate Secretary and Chief Compliance and Community Affairs Officer	If written notice from the Corporation or the Officer is delivered to the other party advising the other party that this Agreement is not to be further extended, then upon such notice, the Agreement shall terminate on the anniversary of the date of notice.

Karl W. Newlin	Senior Vice President – Chief Financial Officer	If written notice from the Corporation or the Officer is delivered to the other party advising the other party that this Agreement is not to be further extended, then upon such notice, the Agreement shall terminate on the anniversary of the date of notice.

Kevin M. O’Hara	Senior Vice President – Chief Administrative Officer	If written notice from the Corporation or the Officer is delivered to the other party advising the other party that this Agreement is not to be further extended, then upon such notice, the Agreement shall terminate on the anniversary of the date of notice.

Franklin H. Yoho	Senior Vice President – Chief Commercial Operations Officer	If written notice from the Corporation or the Officer is delivered to the other party advising the other party that this Agreement is not to be further extended, then upon such notice, the Agreement shall terminate on the anniversary of the date of notice.

Exhibit 31.1

CERTIFICATION

I, Thomas E. Skains, certify that:

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

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

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

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

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

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

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

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

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

(a)

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

(b)

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

Exhibit 31.2

CERTIFICATION

I, Karl W. Newlin, certify that:

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

(a)

(b)

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

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Quarterly Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-Q for the period ended July 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Skains, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)

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

(2)

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

September 7, 2012

/s/ Thomas E. Skains

Thomas E. Skains

Chairman of the Board, President and Chief Executive Officer

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

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY

ACT OF 2002

In connection with the Quarterly Report of Piedmont Natural Gas Company, Inc. (the “Company”), on Form 10-Q for the period ended July 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Karl W. Newlin, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)

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

(2)

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

September 7, 2012

/s/ Karl W. Newlin

Karl W. Newlin

Senior Vice President and Chief Financial Officer