PIEDMONT NATURAL GAS CO INC (Form: 10-Q, Received: 03/09/2012 07:05:16)

March 9, 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 January 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 March 1, 2012
Common Stock, no par value		71,685,958

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

January 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	43
Item 4.	Controls and Procedures	43

Part II.	Other Information

Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 6.	Exhibits	45

	Signatures	47

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)


	January 31,		October 31,
	2012		2011
ASSETS
Utility Plant:
Utility plant in service	$	3,405,811	$	3,377,310
Less accumulated depreciation		992,867		974,631

Utility plant in service, net		2,412,944		2,402,679
Construction work in progress		277,710		217,832
Plant held for future use		6,751		6,751

Total utility plant, net		2,697,405		2,627,262


Other Physical Property, at cost (net of accumulated depreciation of $815 in 2012 and $806 in 2011)		443		452


Current Assets:
Cash and cash equivalents		10,106		6,777
Trade accounts receivable (less allowance for doubtful accounts of $2,755 in 2012 and $1,347 in 2011)		159,278		57,035
Income taxes receivable		29,216		15,966
Other receivables		1,336		2,547
Unbilled utility revenues		82,696		28,715
Inventories:
Gas in storage		105,308		91,124
Materials, supplies and merchandise		1,275		1,368
Gas purchase derivative assets, at fair value		1,776		2,772
Amounts due from customers		34,219		38,649
Prepayments		4,784		39,128
Deferred income taxes		—		1,793
Other current assets		257		147

Total current assets		430,251		286,021


Noncurrent Assets:
Equity method investments in non-utility activities		91,626		85,121
Goodwill		48,852		48,852
Marketable securities, at fair value		2,078		1,439
Overfunded postretirement asset		22,879		22,879
Regulatory asset for postretirement benefits		80,049		81,073
Unamortized debt expense		11,098		11,315
Regulatory cost of removal asset		19,776		19,336
Other noncurrent assets		59,714		58,791

Total noncurrent assets		336,072		328,806


Total	$	3,464,171	$	3,242,541

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Balance Sheets (Unaudited)

(In thousands)


	January 31,			October 31,
	2012			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: 71,674 in 2012 and 72,318 in 2011		424,689			446,791
Retained earnings		605,859			550,584
Accumulated other comprehensive loss		(462	)		(452	)

Total stockholders’ equity		1,030,086			996,923
Long-term debt		675,000			675,000

Total capitalization		1,705,086			1,671,923


Current Liabilities:
Bank debt		457,500			331,000
Trade accounts payable		104,425			85,721
Other accounts payable		30,886			43,959
Accrued interest		11,139			20,038
Customers’ deposits		26,101			25,462
Deferred income taxes		35,096			—
General taxes accrued		3,779			21,262
Amounts due to customers		8,615			2,617
Other current liabilities		14,431			4,073

Total current liabilities		691,972			534,132


Noncurrent Liabilities:
Deferred income taxes		537,041			512,961
Unamortized federal investment tax credits		1,915			2,004
Accumulated provision for postretirement benefits		14,685			14,671
Cost of removal obligations		473,086			466,000
Other noncurrent liabilities		40,386			40,850

Total noncurrent liabilities		1,067,113			1,036,486


Commitments and Contingencies (Note 8)


Total	$	3,464,171		$	3,242,541

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (Unaudited)

(In thousands except per share amounts)


	Three Months Ended
	January 31
	2012			2011

Operating Revenues	$	471,840		$	652,056
Cost of Gas		251,603			422,050


Margin		220,237			230,006


Operating Expenses:
Operations and maintenance		58,397			51,058
Depreciation		26,178			25,047
General taxes		8,622			11,097
Utility income taxes		47,221			51,935


Total operating expenses		140,418			139,137


Operating Income		79,819			90,869


Other Income (Expense):
Income from equity method investments		6,292			7,756
Non-operating income		61			168
Non-operating expense		(421	)		(384	)
Income taxes		(2,318	)		(2,952	)


Total other income (expense)		3,614			4,588


Utility Interest Charges:
Interest on long-term debt		10,023			12,099
Allowance for borrowed funds used during construction		(4,423	)		(2,334	)
Other		1,606			1,252

Total utility interest charges		7,206			11,017


Net Income		76,227			84,440


Other Comprehensive Income (Loss), net of tax:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of ($278) in 2012 and $121 in 2011		(436	)		185
Reclassification adjustment of realized gain from hedging activities of equity method investments included in net income, net of tax of $272 in 2012 and $252 in 2011		426			393

Total other comprehensive income (loss)		(10	)		578


Comprehensive Income	$	76,217		$	85,018


Average Shares of Common Stock:
Basic		72,126			72,194
Diluted		72,433			72,514

Earnings Per Share of Common Stock:
Basic	$	1.06		$	1.17
Diluted	$	1.05		$	1.16

Cash Dividends Per Share of Common Stock	$	0.29		$	0.28

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)


	Three Months Ended
	January 31
	2012			2011

Cash Flows from Operating Activities:
Net income	$	76,227		$	84,440
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		27,257			25,975
Amortization of investment tax credits		(89	)		(93	)
Allowance for doubtful accounts		1,408			2,447
Income from equity method investments		(6,292	)		(7,756	)
Distributions of earnings from equity method investments		1,600			793
Deferred income taxes, net		60,974			35,081
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		996			(533	)
Receivables		(156,455	)		(276,564	)
Inventories		(14,091	)		3,459
Amounts due from/to customers		10,428			63,361
Settlement of legal asset retirement obligations		(221	)		(329	)
Overfunded postretirement asset		—			(22,225	)
Regulatory asset for postretirement benefits		1,024			407
Other assets		20,414			45,621
Accounts payable		17,164			68,339
Provision for postretirement benefits		14			246
Other liabilities		(15,711	)		(1,428	)

Net cash provided by operating activities		24,647			21,241


Cash Flows from Investing Activities:
Utility construction expenditures		(98,140	)		(38,168	)
Allowance for funds used during construction		(4,423	)		(2,334	)
Contributions to equity method investments		(1,828	)		(1,591	)
Distributions of capital from equity method investments		—			748
Proceeds from sale of property		211			464
Investments in marketable securities		(677	)		(426	)
Other		251			907

Net cash used in investing activities		(104,606	)		(40,400	)

Piedmont Natural Gas Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)


	Three Months Ended
	January 31
	2012			2011

Cash Flows from Financing Activities:
Borrowings under bank debt	$	282,000		$	721,500
Repayments under bank debt		(155,500	)		(648,000	)
Retirement of long-term debt		—			(18	)
Expenses related to issuance of debt		(131	)		(2,152	)
Issuance of common stock through dividend reinvestment and employee stock plans		4,914			4,811
Repurchases of common stock		(27,016	)		(22,232	)
Dividends paid		(20,979	)		(20,278	)

Net cash provided by financing activities		83,288			33,631


Net Increase in Cash and Cash Equivalents		3,329			14,472
Cash and Cash Equivalents at Beginning of Period		6,777			5,619

Cash and Cash Equivalents at End of Period	$	10,106		$	20,091


Cash Paid During the Year for:
Interest	$	20,604		$	21,142

Income Taxes:
Income taxes paid	$	1,981		$	999
Income taxes refunded		—			—

Income taxes, net	$	1,981		$	999


Noncash Investing and Financing Activities:
Accrued construction expenditures	$	11,643		$	4,382

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)


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

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

Comprehensive Income:
Net income								84,440						84,440
Other comprehensive income											578			578

Total comprehensive income														85,018
Common Stock Issued		284			8,041									8,041
Common Stock Repurchased		(800	)		(22,232	)								(22,232	)
Tax Benefit from Dividends Paid on ESOP Shares								24						24
Dividends Declared ($.28 per share)								(20,278	)					(20,278	)

Balance, January 31, 2011		71,766		$	431,449		$	584,017		$	48		$	1,015,514


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

Comprehensive Income:
Net income								76,227						76,227
Other comprehensive loss											(10	)		(10	)

Total comprehensive income														76,217
Common Stock Issued		156			4,914									4,914
Common Stock Repurchased		(800	)		(27,016	)								(27,016	)
Tax Benefit from Dividends Paid on ESOP Shares								27						27
Dividends Declared ($.29 per share)								(20,979	)					(20,979	)

Balance, January 31, 2012		71,674		$	424,689		$	605,859		$	(462	)	$	1,030,086

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 (GAAP) in the United States of America are omitted in this interim report under these SEC rules and regulations. These financial statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Form 10-K for the year ended October 31, 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 January 31, 2012 and October 31, 2011, the results of operations for the three months ended January 31, 2012 and 2011, and cash flows for the three months ended January 31, 2012 and 2011. Our business is seasonal in nature. The results of operations for the three months ended January 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 three months ended January 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 commission 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 January 31, 2012 and October 31, 2011 are as follows.


	January 31,		October 31,
In thousands	2012		2011

Regulatory assets	$	195,315	$	200,135
Regulatory liabilities		479,548		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 11 to the consolidated financial statements in this Form 10-Q.

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, bank 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 a rabbi trust 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 7 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 January 31, 2012.

Recently Issued Accounting Guidance

In January 2010, the Financial Accounting Standards Board (FASB) issued accounting guidance to require separate disclosures about purchases, sales, issuances and settlements relating to Level 3 fair value measurements. The guidance was effective for interim periods for fiscal years beginning after December 15,

2010. We adopted the guidance for Level 3 disclosures for recurring and non-recurring items covered under the fair value guidance for the first quarter of our fiscal year ending October 31, 2012. Since the guidance addresses only disclosures related to fair value measurements under Level 3, the adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued accounting guidance to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The amendments are not intended to change the application of the current fair value requirements, but to clarify the application of existing requirements. The guidance does change particular principles or requirements for measuring fair value or disclosing information about fair value measurements. To improve consistency, language has been changed to ensure that U.S. GAAP and IFRS fair value measurement and disclosure requirements are described in the same way. The guidance will be effective for interim and annual periods beginning after December 15, 2011. We will adopt the amended fair value guidance for the second quarter of our fiscal year ending October 31, 2012. The adoption of this guidance will have no material impact on our financial position, results of operations or cash flows.

In June 2011, the FASB issued accounting guidance to increase the prominence of other comprehensive income (OCI) in financial statements. The guidance gives businesses two options for presenting OCI. An OCI statement can be included with the statement of income, and together the two will make a statement of comprehensive income. Alternatively, businesses can present a separate OCI statement, but that statement must appear consecutively with the statement of income within the financial report. This guidance, which we early adopted and presented in one continuous statement for the first quarter of our fiscal year ending October 31, 2012, is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.

In December 2011, the FASB issued accounting guidance to improve disclosures and make information more comparable to IFRS regarding the nature of an entity’s rights of setoff and related arrangements associated with its financial instruments and derivative instruments. The guidance requires the 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 August 1, 2011, 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, 2011. On January 25, 2012, the NCUC issued an order finding us prudent on our gas purchasing policies and practices during this review period and allowed 100% recovery of our gas costs.

On August 30, 2011, we filed an annual report with the Tennessee Regulatory Authority (TRA) reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary market transactions for the twelve months ended June 30, 2011 under the Tennessee Incentive Plan (TIP). We are unable to predict the outcome of this proceeding at this time.

On September 30, 2011, we filed an annual report for the twelve months ended June 30, 2011 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment mechanism. We are unable to predict the outcome of this proceeding at this time.

On September 2, 2011, we filed a general rate application with the TRA requesting authority for an increase to rates and charges for all customers to produce overall incremental revenues of $16.7 million annually, or 8.9% above the current annual revenues. In addition, the petition also requested modifications of the cost allocation and rate designs underlying our existing rates, including shifting more of our cost recovery to our fixed charges and away from the volumetric charges and expanding the period of the weather normalization adjustment to October through April. We also sought approval to implement a school-based energy education program with appropriate cost recovery mechanisms, amortization of certain regulatory assets and deferred accounts, revised depreciation rates for plant and changes to the existing service regulations and tariffs. The changes were proposed to be effective March 1, 2012. On December 22, 2011, we and the Consumer Advocate and Protection Division reached a stipulation and settlement agreement resolving all issues in this proceeding, including an increase in rates and charges to all customers effective March 1, 2012 designed to produce overall incremental revenues of $11.9 million annually, or 6.3% above the current annual revenue, based upon an approved rate of return on equity of 10.2%. The new cost allocations shift recovery of fixed charges from 29% to 37% with a resulting decrease of volumetric charges from 71% to 63%. The stipulation and settlement agreement did not include a cost recovery mechanism for a school-based energy education program. On January 23, 2012, a hearing on this matter was held by the TRA. The TRA approved the settlement agreement at the January 23, 2012 hearing.

On February 26, 2010, we filed a petition with the 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 recovery of $1.5 million for us. 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. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows.

In October 2010, the TRA approved a petition requesting deferred accounting treatment for the direct incremental expenses incurred as a result of our response to severe flooding in Nashville in May 2010. We had deferred $1 million as of January 31, 2012 and October 31, 2011 related to the flooding. As a part of the rate case stipulation and settlement agreement mentioned above, the TRA approved the recovery of these deferred expenses to be amortized over 96 months beginning March 1, 2012.

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 and are included in our calculation of fully diluted earnings per share.

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


	Three Months
In thousands except per share amounts	2012		2011

Net Income	$	76,227	$	84,440


Average shares of common stock outstanding for basic earnings per share		72,126		72,194
Contingently issuable shares under incentive compensation plans		307		320

Average shares of dilutive stock		72,433		72,514


Earnings Per Share of Common Stock:
Basic	$	1.06	$	1.17
Diluted	$	1.05	$	1.16

4. Short-Term Debt Instruments

We have a $650 million three-year revolving syndicated credit facility that expires in January 2014. The 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 was issued and outstanding at January 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 remain outstanding until repaid and do not mature daily. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

Our outstanding short-term bank borrowings, as included in “Bank debt” in the consolidated balance sheets, were $457.5 million and $331 million, as of January 31, 2012 and October 31, 2011, respectively, under our revolving syndicated credit facility in LIBOR cost-plus loans. During the three months ended January 31, 2012, short-term bank borrowings ranged from $328.5 million to $475.5 million, and interest rates ranged from 1.15% to 1.20% (weighted average of 1.18%). 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 January 31, 2012.

For information on the initiation of a commercial paper program (CP program) subsequent to the period, see Note 14 to the consolidated financial statements in this Form 10-Q.

5. Capital Stock and Accelerated Share Repurchase

On January 4, 2012, we entered into an accelerated share repurchase (ASR) agreement where we purchased 800,000 shares of our common stock from an investment bank at the closing price that day of $33.77 per share. The settlement and retirement of those shares occurred on January 5, 2012. Total consideration paid to purchase the shares of $27 million was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the consolidated balance sheets.

As part of the ASR, we simultaneously entered into a forward sale contract with the investment bank that is expected to mature in 52 trading days, or March 21, 2012. Under the terms of the forward sale contract, the

investment bank is required to purchase, in the open market, 800,000 shares of our common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold to us. At settlement, we, at our option, are required to either pay cash or issue shares of our common stock to the investment bank if the investment bank’s weighted average purchase price, less a $.09 per share discount, is higher than the January 4, 2012 closing price. The investment bank is required to pay us either cash or shares of our common stock, at our option, if the investment bank’s weighted average price, less a $.09 per share discount, for the shares purchased is lower than the initial purchase closing price. We have accounted for this forward sale contract as an equity instrument under accounting guidelines. As the fair value of the forward sale contract at inception was zero, no accounting for the forward sale contract is required until settlement, as long as the forward sale continues to meet the requirements for classification as an equity instrument.

For further information on the subsequent settlement of the ASR by the investment bank on February 28, 2012, see Note 14 to the consolidated financial statements in this Form 10-Q.

6. 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 a rabbi trust established for our deferred compensation. For further information on the deferred compensation plans, see Note 9 to the consolidated financial statements.

We have classified these marketable securities as trading securities since their inception as the assets are held in a rabbi trust. 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. Any participant’s account that exceeds $25,000 upon retirement will be paid over five years upon retirement. An amount less than $25,000 in a participant’s account upon retirement will be paid in a lump sum. We have matched the current portion of the deferred compensation liability with the current asset and 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 January 31, 2012 and October 31, 2011 is as follows.


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

Current trading securities:
Money markets	$	—	$	—	$	—	$	—
Mutual funds		149		162		47		52

Total current trading securities		149		162		47		52


Noncurrent trading securities:
Money markets		300		300		217		217
Mutual funds		1,611		1,778		1,107		1,222

Total noncurrent trading securities		1,911		2,078		1,324		1,439


Total trading securities	$	2,060	$	2,240	$	1,371	$	1,491

7. 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 January 31, 2012 and October 31, 2011, we had long gas purchase options providing total coverage of 44.1 million dekatherms and 38.1 million dekatherms, respectively. The long gas purchase options held at January 31, 2012 are for the period from March 2012 through February 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 a rabbi trust 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 January 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 January 31, 2012 and 2011.

Recurring Fair Value Measurements as of January 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

Assets:
Derivatives held for distribution operations	$	1,776	$	—	$	—	$	1,776
Debt and equity securities held as trading securities:
Money markets		300		—		—		300
Mutual funds		1,940		—		—		1,940

Total fair value assets	$	4,016	$	—	$	—	$	4,016

Recurring 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

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 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 Public Service Commission of South Carolina (PSCSC) and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net 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 include 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 a rabbi trust 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, are shown below.


In thousands	Carrying Amount		Fair Value

As of January 31, 2012	$	675,000	$	834,979
As of October 31, 2011		675,000		831,323

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 January 31, 2012 and October 31, 2011.

Fair Value of Derivative Instruments


In thousands	Fair Value January 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 (March 2012-February 2013)	$	1,776

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 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 comprehensive income for the three months ended January 31, 2012 and 2011, absent the regulatory treatment under our approved PGA procedures.


In thousands	Amount of Loss Recognized on Derivatives Instruments		Amount of Loss Deferred Under PGA Procedures		Location of Loss Recognized through PGA Procedures
	Three Months Ended January 31,		Three Months Ended January 31,
	2012	2011	2012	2011

Gas purchase options	$2,923	$4,221	$2,923	$4,221	Cost of Gas

In Tennessee, the cost of gas purchase options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our TIP approved by the TRA. In South Carolina, the costs of gas purchase options are subject to 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.

8. 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. The time periods for pipeline and storage capacity contracts range from one to twenty years. The time periods for gas supply contracts are one year. 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 range from one to three years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles and contractors.

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

Leases

We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting 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 January 31, 2012. Additional information concerning letters of credit is included in Note 4 to the consolidated financial statements.

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.

In October 1997, we entered into a settlement with a third party with respect to nine manufactured gas plant (MGP) sites that we have owned, leased or operated that released us from any investigation and remediation liability. Although no such claims are pending or, to our knowledge, threatened, the settlement did not cover any third-party claims for personal injury, death, property damage and diminution of property value or natural resources.

There are four other MGP sites located in Hickory and Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated. At our Reidsville site, we have performed soil remediation work and will be performing a groundwater remediation assessment under our North Carolina Department of Environment and Natural Resources (NCDENR) approved plan. Remediation at this site is scheduled to be completed in our fiscal year 2012, and we have incurred $.6 million of remediation costs through January 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 periodic 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 January 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 consent order imposing usage restrictions on the property was approved and signed by the TDEC in June 2010. The public comment period has ended, and we continue to conduct semi-annual groundwater monitoring at the site per the final consent order. We have incurred $1.5 million of remediation costs through January 31, 2012.

In connection with our 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress) prior to closing. Progress has complete responsibility for performing all of NCNG’s remediation obligations to conduct testing and clean-up at these sites, including both the costs of such testing and clean-up and the implementation of any affirmative remediation obligations that NCNG has related to the sites. Progress’ responsibility does not include any third-party claims for personal injury, death, property damage, and diminution of property value or natural resources. We know of no such pending or threatened claims.

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 for the Huntersville LNG molecular sieve 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 and imposing a fine in an amount that will be less than $100,000. We are currently negotiating the ACO. Plans to investigate the extent of the groundwater contamination related to the sieve burial will be developed upon the final negotiation of the ACO. 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. We have incurred $3.2 million to remediate the Huntersville LNG site through January 31, 2012. The LNG tank is scheduled for lead-based paint removal in our fiscal year 2012. Additional facilities at our Huntersville LNG plant site are being evaluated for lead-based paint removal with work scheduled for our fiscal year 2012.

Our Nashville LNG facility was also originally coated with lead-based paint. We have incurred $.4 million of remediation costs through January 31, 2012. This work is scheduled to be completed in our fiscal year 2012.

We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina district continues to operate USTs. During 2011, our Greenville, South Carolina and Greensboro and Salisbury, North Carolina districts 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 January 31, 2012, our estimated undiscounted environmental liability for USTs for which we retain remediation responsibility is $.3 million.

One of our operating districts has coatings containing asbestos on some of their pipelines. We have educated our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose small portions of the pipeline. Lead-based paint is being removed at multiple LNG facilities that we own. Employees have been trained on the hazards of lead exposure, and we have engaged independent environmental contractors to remove and dispose of the lead-based paint at these facilities.

As of January 31, 2012, our estimated undiscounted environmental liability totaled $2.4 million, and consisted of $1 million for the MGP sites for which we retain remediation responsibility, $1.1 million for the LNG facilities and $.3 million for the USTs not yet remediated.

Further evaluation of the MGP, LNG and UST sites and removal of lead-based paint 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.

9. Employee Benefit Plans

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended January 31, 2012 and 2011 are presented below.


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

Service cost	$	2,475		$	2,225		$	10	$	11	$	347		$	350
Interest cost		2,650			2,700			51		52		337			374
Expected return on plan assets		(5,125	)		(5,150	)		—		—		(388	)		(384	)
Amortization of transition obligation		—			—			—		—		167			167
Amortization of prior service (credit) cost		(550	)		(550	)		20		5		—			—
Amortization of actuarial loss		1,375			775			12		10		—			—

Total	$	825		$	—		$	93	$	78	$	463		$	507

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 three months ended January 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 a rabbi trust with a bank as the trustee. As of January 31, 2012, we have a liability of $2.3 million for these plans.

See Note 6 and Note 7 to the consolidated financial statements in this Form 10-Q for information on the investments in marketable securities that are held in the trust.

10. Employee Share-Based Plans

Under our shareholder approved Incentive Compensation Plan (ICP), eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the three months ended January 31, 2012 and 2011, we recorded compensation expense, and as of January 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 a participant’s units. For the three months ended January 31, 2012 and 2011, we recorded compensation expense, and as of January 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 incentive plan, 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 dividends equivalents will accrue on these stock units and be converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The stock units will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of the units vest on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the three months ended January 31, 2012, we recorded compensation expense, and as of January 31, 2012, 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.

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


	Three Months
In thousands	2012	2011

Compensation expense	$1,575	$922


	January 31, 2012	October 31, 2011

Liability	$6,590	$5,015

On a quarterly basis, we issue shares of common stock under the employee stock purchase plan 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.

11. 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 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. to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. To provide the additional delivery service, we have executed an agreement with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to spend an estimated $48 million for 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 will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of January 31, 2012, our current fiscal year contributions related to this expansion were $1.8 million, and our total contributions related to this expansion were $8 million.

The members’ capital will be replaced with permanent financing with a target overall capital structure of 45-50% debt and 50-55% equity after the project is placed into service, scheduled to be June 2012. Our service subscription to Cardinal’s capacity following the system expansion will increase from approximately 37% to approximately 53%.

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 ended January 31, 2012 and 2011, these transportation costs and the amounts we owed Cardinal as of January 31, 2012 and October 31, 2011 are as follows.


	Three Months
In thousands	2012	2011

Transportation costs	$1,035	$1,035

	January 31, 2012	October 31, 2011

Trade accounts payable	$349	$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 ended January 31, 2012 and 2011, these gas storage costs and the amounts we owed Pine Needle as of January 31, 2012 and October 31, 2011 are as follows.


	Three Months
In thousands	2012	2011

Gas storage costs	$2,519	$2,926

	January 31, 2012	October 31, 2011

Trade accounts payable	$849	$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 15% membership interest 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 ended January 31, 2012 and 2011, our operating revenues from these sales and the amounts SouthStar owed us as of January 31, 2012 and October 31, 2011 are as follows.


	Three Months
In thousands	2012	2011

Operating revenues	$(112)	$(31)

	January 31, 2012	October 31, 2011

Trade accounts receivable	$356	$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 ended January 31, 2012 and 2011, these gas storage costs and the amounts we owed Hardy Storage as of January 31, 2012 and October 31, 2011 are as follows.


	Three Months
In thousands	2012	2011

Gas storage costs	$2,425	$2,425

	January 31, 2012	October 31, 2011

Trade accounts payable	$808	$808

12. 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, and 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 January 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 11 to the consolidated financial statements. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments as discussed in Note 11 to the consolidated financial statements. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of January 31, 2012 and October 31, 2011, our investment balances are as follows.


In thousands	January 31, 2012		October 31, 2011

Cardinal	$	20,293	$	18,323
Pine Needle		18,757		18,690
SouthStar		21,494		17,536
Hardy Storage		31,082		30,572

Total equity method investments in non-utility activities	$	91,626	$	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.

13. 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” in the consolidated statements of comprehensive income. Operations of the non-utility activities segment are included in the consolidated statements of comprehensive income in “Income from equity method investments” and “Non-operating income.”

We evaluate the performance of the regulated utility segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. The basis of segmentation and the basis of the measurement of segment profit or loss are the same as reported in the consolidated financial statements in our Form 10-K for the year ended October 31, 2011.

Operations by segment for the three months ended January 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	$	471,840	$	652,056	$	—		$	—		$	471,840	$	652,056
Margin		220,237		230,006		—			—			220,237		230,006
Operations and maintenance expenses		58,397		51,058		23			30			58,420		51,088
Income from equity method investments		—		—		6,292			7,756			6,292		7,756
Operating income (loss) before income taxes		127,040		142,804		(107	)		(119	)		126,933		142,685
Income before income taxes		119,581		131,689		6,185			7,638			125,766		139,327

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


In thousands	Three Months
	2012			2011

Operating Income:
Segment operating income before income taxes	$	126,933		$	142,685
Utility income taxes		(47,221	)		(51,935	)
Non-utility activities before income taxes		107			119

Operating income	$	79,819		$	90,869


Net Income:
Income before income taxes for reportable segments	$	125,766		$	139,327
Income taxes		(49,539	)		(54,887	)

Net income	$	76,227		$	84,440

14. 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.

On February 28, 2012, the ASR settled. We received $.5 million from the investment bank and will record this amount in “Stockholder’s equity” as an addition to “Common Stock.” The $.5 million was the difference between the investment bank’s weighted average purchase price of $33.25 per share less a discount of $.09 per share for a settlement price of $33.16 per share and the initial purchase closing price of $33.77 per share multiplied by 800,000 shares.

In March 2012, we established a $650 million unsecured CP program. The notes issued under the CP program will have maturities not to exceed 397 days from the date of issuance and will be backstopped by our existing $650 million revolving syndicated credit facility expiring January 25, 2014. The amount outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, shall not exceed $650 million. Any borrowings under the CP program will rank equally with our other unsubordinated and unsecured debt. The short-term notes under the CP program will not be registered under the Securities Act of 1933 for public offering and may not be offered or sold by us absent registration or exemption from registration requirements. We will be issuing the notes pursuant to an exemption from registration.

In February 2012, we secured pricing confirmations from lenders that price $300 million of private placement long-term debt with the transaction expected to close on March 27, 2012. We will be issuing $100 million on or around July 16, 2012 with an interest rate of 3.47%. On or around October 15, 2012, we will be issuing the remaining $200 million with an interest rate of 3.57%. Both issuances will mature in fifteen years on or about July 16, 2027. The blended interest rate for these debt issuances is 3.54%. These proceeds will be used for general corporate purposes, including the repayment of short-term debt incurred in part for funding of capital expenditures for power generation gas delivery service projects.

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 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 rely 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 53,000 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.

In 1994, our predecessor, which was incorporated in 1950 under the same name, was merged into a newly formed North Carolina corporation for the purpose of changing our state of incorporation to North Carolina.

In the Carolinas, our service area is comprised of numerous cities, towns and communities. We provide service to Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte, Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine, Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro in North Carolina. In North Carolina, we also provide wholesale natural gas service to the cities of Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to the cities of Gallatin and Smyrna.

We have two reportable business segments, regulated utility and non-utility activities. The regulated utility segment is the largest segment of our business with approximately 97% of our consolidated assets. 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. For the three months ended January 31, 2012, 95% of our earnings before taxes came from our regulated utility segment. 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. For the three months ended January 31, 2012, 5% of our earnings before taxes came from our non-utility segment, which consisted of 2% from regulated non-utility activities and 3% from unregulated non-utility activities. For further information on equity method investments and business segments, see Note 11 and Note 13, respectively, to the consolidated financial statements.

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.

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 results in semi-annual rate adjustments to refund any over-collection of margin or recover any under-collection of margin. Currently, we have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset 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. 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.

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. These 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, we have decoupled residential and commercial rates. 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. In Tennessee, as a result of our 2012 rate case settlement, we will shift 37% of our cost recovery to fixed charges rather than 29% with a resulting decrease of volumetric charges to 63% rather than 71%. For the three months ended January 31, 2012, these and other rate designs stabilized our gas utility margin by providing fixed recovery of 69% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 22% 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 9% of our utility margins. For the three months ended January 31, 2012, the margin decoupling mechanism in North Carolina increased margin by $16.8 million, and the WNA in South Carolina and Tennessee increased margin by $7.1 million.

Our strategic directives have a customer-centered approach and reflect what we believe is the inherent benefit of natural gas compared to other types of energy. Our overall corporate focus is to expand our core natural gas and complementary energy-related businesses to enhance shareholder value. This focus includes traditional growth in the core residential, commercial and industrial markets, growth in the power generation market, supply diversity and complementary energy-related investments and natural gas end use technology. We want our customers to choose us because of the value of natural gas and the quality of our service to them. We strive to achieve excellence in service to our customers and in our business operations with every customer contact we make. We pursue business practices to 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.

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 transmission pipeline safety and integrity programs that include leak detection surveys, periodic valve maintenance, periodic corrosion and atmospheric corrosion inspections, cathodic protection, in-line inspection devices, hydrostatic and compressed air pressure testings of new facilities and other evaluation methods. 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. There is risk associated with the unauthorized access of digital data with the intent to misappropriate information, corrupt data or cause operational disruptions. 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. We also have a comprehensive identity theft protection program to protect customer information, as well as a cybersecurity insurance policy.

We continue to work toward a business model that positions us for long-term success in a lower carbon energy economy with a focus on future growth opportunities that support new clean energy technologies and energy efficiencies. We are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation, efficiency and environmental stewardship. We continue our efforts to promote the benefits of natural gas with promotion efforts aimed at educating consumers on the benefits of natural gas compared to other energy sources as well as advocating the benefits of natural gas to prospective customers in our communities. 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. We also promote and market the cost and environmental benefits of natural gas to power generation customers in our market area.

Our financial strength and flexibility is critical to our success as a company. We will continue our stewardship to maintain our financial strength, which translates to 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 to control our operating costs, implement new technologies and work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

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 supply production from shale basins, such as the Marcellus, Barnett and Haynesville as well as other shale gas producing areas, continues to provide supply stability and price moderation for natural gas as a commodity. 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. As a result, natural gas continues to have a price advantage, as well as an environmental advantage, over many other fuels.

We have taken advantage of the growth opportunities that exist in our markets and during the period continued to focus on residential, commercial and industrial customer conversions to natural gas and power generation gas delivery service opportunities. As we seek to expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for energy consumers because of the comfort, affordability, efficiency and environmental benefits of natural gas, as well as remind our customers of our reliability and safety as a company.

Customer additions in our residential and commercial markets increased for the quarter compared to the same period in 2011 by 22% and 10%, respectively. Residential gains were driven primarily by growth in our residential new construction and conversion markets where building permits increased modestly and lower wholesale natural gas costs continued to favorably position natural gas relative to other energy sources. Increased commercial growth reflected improvements in both commercial new construction activity and commercial conversion opportunities. We continue to forecast gross customer addition growth for fiscal 2012 of approximately 1%.

We completed a pipeline expansion project in December 2011 to provide long-term gas transportation service to a power generation customer in our market area. We have two pipeline expansion projects under construction to provide natural gas delivery service to power generation facilities currently under construction in North Carolina with targeted in service dates of June 2012 and June 2013. In addition to the environmental benefits of replacing coal-fired power plants with new efficient, combined-cycle natural gas-fired power plants, the construction of the natural gas pipelines for these projects will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for economic growth and development. See the following discussion of our forecasted capital investment related to the construction of the 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 see 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 customers. Currently, approximately 11% of our vehicle fleet uses CNG. We have five company CNG fueling stations in use, and we plan to construct up to five more in fiscal year 2012. 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 with sufficient usage.

We continue our regulatory strategy to align our rate structures between shareholder and customer interests. Notably, on January 23, 2012, the TRA approved a settlement agreement between us and the Consumer Advocate and Protection Division that resolved all issues in the general rate proceeding, including an increase in rates and charges to all customers of $11.9 million annually, effective March 1, 2012. As part of the settlement, we have shifted more of our cost recovery to the fixed portion of the customers’ bills to somewhat mitigate volumetric charges. 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. For further information, see Note 2 to the consolidated financial statements.

To support our strategic objectives focusing on excellence in customer service, as discussed above in the “Overview,” during the period we 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 new centralized service scheduling work processes and system enhancements to better serve our customers in a more timely and efficient fashion.

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 to us to provide for operations and capital investments. On February 15, 2012, we secured pricing confirmations from lenders that price $300 million of private placement long-term debt with the intention to issue $100 million in July 2012 and the remaining $200 million in October 2012. In March 2012, we initiated a commercial paper program (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 commercial paper compared to drawing on our syndicated revolving credit facility. The short-term notes under the CP program will not be registered under the Securities Act of 1933 for public offering and may not be offered or sold by us absent registration or exemption from registration requirements. We will be issuing the notes pursuant to an exemption from registration. We also have an open shelf registration filed in June 2011 with the SEC that is available for future issuances of debt or equity.

The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, enacted in December 2010, extended the 50% “bonus depreciation” that expired December 31, 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. The Internal Revenue Service has issued regulations that are intended to provide guidance in interpreting the law. Based on current capital projections and timelines, we are anticipating a benefit through 2014 of $130-170 million. We anticipate that the bonus depreciation allowance will have a material favorable impact on our cash flows in the near term by reducing cash needed to pay federal income taxes.

Our first quarter in 2012 reflected a warmer-than-normal start to the 2011-2012 winter heating season. The weather in our first quarter was 16% warmer than normal and 31% warmer than the first quarter of 2011. During the three months ended January 31, 2012, net income decreased $8.2 million as compared with the prior year period primarily due to the following:

•

Margin decreased $9.8 million from several factors, primarily influenced by weather. Margin from secondary wholesale market sales decreased $5.5 million due to less transactional opportunities because of lower natural gas demand and less volatility in wholesale natural gas pricing. Residential and commercial retail margin decreased $4.3 million primarily from decreased sales of 16.9 million dekatherms. The majority of the margin decrease is attributable to our residential and commercial customer classes in South Carolina and Tennessee where our rates are not fully decoupled and WNA does not perfectly adjust for variances in warmer- or colder-than-normal weather. Margin from the sales to and transport of gas for our industrial and resale customers decreased $1.1 million primarily because of warmer weather, partially offset by an increase in margin of $.8 million from power generation customers.

•

Operations and maintenance expenses increased $7.3 million due to higher pension expense, including the absence of a regulatory pension deferral in 2012, increased medical coverage expense, contract labor expenses related to process improvement efforts and payroll.

Additional information on operating results for the quarter follows.

Results of Operations

We reported net income of $76.2 million for the three months ended January 31, 2012 as compared to $84.4 million for the same period in 2011. The following table sets forth a comparison of the components of our consolidated statements of comprehensive income for the three months ended January 31, 2012 as compared with the three months ended January 31, 2011.

Comprehensive Income Statement Components


	Three Months Ended January 31
In thousands, except per share amounts	2012		2011		Variance			Percent Change
Operating Revenues	$	471,840	$	652,056	$	(180,216	)		(27.6	)%
Cost of Gas		251,603		422,050		(170,447	)		(40.4	)%

Margin		220,237		230,006		(9,769	)		(4.2	)%

Operations and Maintenance		58,397		51,058		7,339			14.4	%
Depreciation		26,178		25,047		1,131			4.5	%
General Taxes		8,622		11,097		(2,475	)		(22.3	)%
Utility Income Taxes		47,221		51,935		(4,714	)		(9.1	)%

Total Operating Expenses		140,418		139,137		1,281			0.9	%

Operating Income		79,819		90,869		(11,050	)		(12.2	)%
Other Income (Expense), net of tax		3,614		4,588		(974	)		(21.2	)%
Utility Interest Charges		7,206		11,017		(3,811	)		(34.6	)%

Net Income	$	76,227	$	84,440	$	(8,213	)		(9.7	)%


Average Shares of Common Stock:
Basic		72,126		72,194		(68	)		(0.1	)%
Diluted		72,433		72,514		(81	)		(0.1	)%


Earnings Per Share of Common Stock:
Basic	$	1.06	$	1.17	$	(0.11	)		(9.4	)%
Diluted	$	1.05	$	1.16	$	(0.11	)		(9.5	)%

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

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Three Months Ended January 31
	2012			2011		Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		38,596			56,177		(17,581	)	(31.3)%
Transportation Volumes		51,632			41,667		9,965		23.9%

Throughput		90,228			97,844		(7,616	)	(7.8)%

Secondary Market Volumes		11,447			14,286		(2,839	)	(19.9)%

Customers Billed (at period end)		983,481			979,728		3,753		0.4%
Gross Customer Additions		3,438			2,857		581		20.3%

Degree Days
Actual		1,568			2,278		(710	)	(31.2)%
Normal		1,869			1,865		4		0.2%
Percent (warmer) colder than normal		(16.1	)%		22.1%		n/a		n/a

Number of Employees (at period end)		1,782			1,774		8		0.5%

Operating Revenues

Operating revenues decreased $180.2 million for the three months ended January 31, 2012 compared with the same period in 2011 primarily due to the following decreases:

•

$186.7 million of lower gas costs passed through to sales customers.

•

$54.2 million from lower revenues in secondary market transactions due to decreased activity and margins.

These decreases were partially offset by the following increases:

•

$44.7 million from increased revenues under the margin decoupling mechanism.

•

$13.6 million from increased revenues under the WNA in South Carolina and Tennessee.

•

$1.9 million from increased volumes delivered to transportation customers, including new power generation customers.

Cost of Gas

Cost of gas decreased $170.4 million for the three months ended January 31, 2012 compared with the same period in 2011 primarily due to the following decreases:

•

$140.7 million of decreased commodity gas costs primarily from lower volumes sold and lower gas costs passed through to sales customers.

•

$48.7 million of decreased commodity gas costs in secondary marketing transactions due to decreased activity and lower average gas costs.

•

$4.1 million of decreased pipeline demand charges primarily due to changing asset manager payments.

These decreases were partially offset by $23.3 million of increased costs due to regulatory approved gas cost mechanisms.

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

Margin

Margin decreased $9.8 million for the three months ended January 31, 2012 compared with the same period in 2011 primarily due to the following decreases:

•

$5.5 million in decreased secondary market activity and margins due to decreased activity resulting from warmer weather and less wholesale natural gas price volatility.

•

$4.3 million primarily due to decreases in sales to residential and commercial classes because of 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 residential customer growth.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the passthrough of changes in wholesale commodity gas costs, which accounted for 37% of revenues for the three months ended January 31, 2012, and transportation and storage costs, which accounted for 7%.

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

Operations and maintenance expenses increased $7.3 million for the three months ended January 31, 2012 compared with the same period in 2011 primarily due to the following increases:

•

$4.2 million in higher pension expense, including the absence of a regulatory pension deferral in 2012, and increased medical coverage expense.

•

$1.1 million in contract labor expenses for process improvement efforts.

•

$.8 million in higher payroll.

•

$.7 million in materials primarily due to increased usage.

Depreciation

Depreciation expense increased $1.1 million for the three months ended January 31, 2012 compared with the same period in 2011 primarily due to increases in plant in service.

General Taxes

General taxes decreased $2.5 million for the three months ended January 31, 2012 compared with the same period in 2011 primarily due to the accrual of a liability in 2011 for sales tax on certain customer accounts that were not exempt from sales tax.

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 three months ended January 31, 2012 compared with the same period in 2011 was in income from equity method investments. All other changes were insignificant for the period.

Income from equity method investments decreased $1.5 million for the three months ended January 31, 2012 compared with the same period in 2011 due to a $1.6 million decrease in earnings from SouthStar Energy Services LLC primarily due to lower customer usage related to warmer weather 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.

Utility Interest Charges

Utility interest charges decreased $3.8 million for the three months ended January 31, 2012 compared with the same period in 2011 primarily due to the following changes:

•

$2.1 million decrease in interest expense due to an increase in capitalized interest in the borrowed allowance for funds used during construction primarily due to increased construction expenditures.

•

$2.1 million decrease in interest expense on long-term debt primarily due to lower amounts of debt outstanding at lower interest rates.

•

$.8 million increase in interest expense on short-term debt primarily due to higher balances outstanding during the current period at average interest rates that were approximately 60 basis points higher in the current period.

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 bank borrowings. 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.

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

Short-Term Borrowings . We have a $650 million three-year revolving syndicated credit facility. The facility expires in January 2014 and 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. During the three months ended January 31, 2012, short-term bank borrowings ranged from $328.5 million to $475.5 million, and interest rates ranged from 1.15% to 1.20%.

In March 2012, we established a $650 million unsecured CP program. The notes issued under the CP program will have maturities not to exceed 397 days from the date of issuance and will be backstopped by our existing $650 million revolving syndicated credit facility expiring January 25, 2014. The amount 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 will rank equally with our other unsubordinated and unsecured debt. Due to lower interest rates associated with commercial paper as opposed to drawing on our revolving syndicated credit facility, we anticipate annual saving of approximately $2.5 million. The short-term notes under the CP program will not be registered under the Securities Act of 1933 for public offering and may not be offered or sold by us absent registration or exemption from registration requirements. We will be issuing the notes pursuant to an exemption from registration.

Our short-term borrowings at quarter end consisting only of the revolving syndicated credit facility, as included in “Bank Debt” in the consolidated balance sheets, are 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 borrowings 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. We believe that our revolving syndicated credit facility, along with our access to capital markets, will allow us to meet the increased capital requirements anticipated to be spent over the next two years.

Highlights for our bank borrowings as of January 31, 2012 and for the quarter ended January 31, 2012 are presented below.

Bank Borrowings

As of January 31, 2012


In thousands

End of period (January 31, 2012):
Amount outstanding	$	457,500
Weighted average interest rate		1.17	%

During the period (November 1, 2011 - January 31, 2012):
Average amount outstanding	$	393,900
Weighted average interest rate		1.18	%

Maximum amount outstanding:
November	$	380,500
December		399,000
January		475,500

On January 1, 2012, we made interest payments of $14.7 million on long-term debt; these payments were made using cash from operations that reduced the maximum amount outstanding in January to a lower balance outstanding at month end.

The level of short-term bank borrowings 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.

As of January 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 January 31, 2012, unused lines of credit available under our revolving syndicated credit facility, including the issuance of the letters of credit, totaled $189.6 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 bank borrowings 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.

Net cash provided by operating activities was $24.6 million and $21.2 million for the three months ended January 31, 2012 and 2011, respectively. Net cash provided by operating activities reflects a decrease of $8.2 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 increased $157.6 million from October 31, 2011 primarily due to the winter consumption of gas and decreased $116.1 million compared with January 31, 2011 primarily due to 31.2% warmer weather during the current period than the same prior period. Volumes sold to weather-sensitive residential and commercial customers decreased 16.9 million dekatherms as compared with the same prior period. Total throughput decreased 7.6 million dekatherms as compared with the same prior period, largely from decreased sales to residential, commercial and industrial customers, partially offset by increased volumes of 11.6 million dekatherms, or 79%, sold to and transported for power generation customers.

•

Net amounts due from customers decreased $10.4 million from October 31, 2011 primarily due to the collection of deferred gas costs through rates.

•

Gas in storage increased $14.2 million in the current period primarily due to increased volumes of gas in storage from lower customer sales, partially offset by a decrease in the weighted average cost of gas purchased for injections in 2012 as compared with the prior year.

•

Prepaid gas costs decreased $35.8 million in the current period primarily due to 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.

•

Trade accounts payable increased $30.3 million in the current period primarily due to increased gas purchases to meet greater customer demand during the winter months.

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 in South Carolina and Tennessee generated charges to customers of $7.1 million and credits of $6.5 million in the three months ended January 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 $16.8 million and decreased margin by $27.9 million in the three months ended January 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 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 $104.6 million and $40.4 million for the three months ended January 31, 2012 and 2011, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the three months ended January 31, 2012 were $98.1 million as compared to $38.2 million in the same prior period primarily due to expending $51 million for the construction of power generation service delivery projects in 2012 as compared with $11.5 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 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 $260 - 280 million and $90 - 100 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. We intend to fund expenditures related to these projects in a manner that maintains our targeted capitalization ratio of 45-50% in long-term debt and 50-55% in common equity. Additional detail for the anticipated capital expenditures follows.


In millions	2012		2013		2014

Utility capital expenditures	$	280 - 320	$	290 - 320	$	200 - 250
Power generation related capital expenditures		260 - 280		90 - 100		—

Total forecasted capital expenditures	$	540 - 600	$	380 - 420	$	200 - 250

In October 2009, we reached an agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. The agreement, approved by the NCUC in May 2010, calls for us to construct approximately 38 miles of 20-inch transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2012. We began construction in February 2010. Our investment in the pipeline and compression facilities is supported by a long-term service agreement. To provide the additional delivery service, we have executed an agreement with Cardinal Pipeline Company, L.L.C. (Cardinal) to expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This will require Cardinal to spend an estimated $48 million to expand its system. As a 21.49% equity venture partner of Cardinal, we will invest an estimated $10.3 million in Cardinal’s system expansion. Capital contributions related to this system expansion began in January 2011 and will continue on a periodic basis through September 2012. As of January 31, 2012, our contributions to date related to this system expansion were $8 million. For further information regarding this agreement, see Note 11 to the consolidated financial statements.

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, also approved by the NCUC in May 2010, 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. We began construction in May 2010. Our service to Progress Energy Carolinas is supported by a long-term service agreement. 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.

The Sutton facilities will 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. 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. The timing and design scope of the expansion of our facilities in Robeson County will be determined as our system infrastructure and market supply growth requirements in North Carolina dictate.

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 financing activities was $83.3 million and $33.6 million for the three months ended January 31, 2012 and 2011, respectively. Funds are primarily provided from bank borrowings and the issuance of common stock through our dividend reinvestment and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to retire long-term debt, pay down outstanding short-term bank borrowings, repurchase common stock under the common stock repurchase program and pay quarterly dividends on our common stock.

Outstanding short-term bank borrowings increased from $331 million as of October 31, 2011 to $457.5 million as of January 31, 2012 primarily due to higher capital expenditures and to increased gas purchases to meet greater customer demand during the winter months. For further information on bank borrowings, see the previous discussion of “Short-Term Borrowings” 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.

On March 1, 2012, we established a $650 million unsecured CP program. For further information on our CP program, see the previous discussion of “Short-Term Borrowings” in “Financial Condition and Liquidity.”

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. In February 2012, we secured pricing confirmations from lenders that price $300 million of private placement long-term debt with the transaction expected to close in March 2012. We will be issuing $100 million on or around July 16, 2012 with an interest rate of 3.47%. On or around October 15, 2012, we will be issuing the remaining $200 million with an interest rate of 3.57%. The proceeds will be used for general corporate purposes, including the funding of capital expenditures for power generation gas delivery service projects.

During the three months ended January 31, 2012 and 2011, we issued $4.9 million and $4.8 million, respectively, of common stock through DRIP and ESPP. From time to time, we have repurchased shares of common stock under our Common Stock Open Market Purchase Program as described in Part II, Item 2 in this Form 10-Q. During the three months ended January 31, 2012, we repurchased and retired .8 million shares for $27 million, leaving a balance of 2,910,074 shares available for repurchase under the program. This transaction settled on February 28, 2012, and we received $.5 million from the investment bank. During the three months ended January 31, 2011, we repurchased and retired .8 million shares for $22.2 million under the program that settled in our second quarter in 2011.

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 January 31, 2012, our retained earnings were not restricted. On March 8, 2012, the Board of Directors declared a quarterly dividend on common stock of $.30 per share, payable April 13, 2012 to shareholders of record at the close of business on March 23, 2012.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. As of January 31, 2012, our capitalization, including current maturities of long-term debt, if any, consisted of 40% in long-term debt and 60% in common equity.

The components of our total debt outstanding (short-term debt and long-term debt) to our total capitalization as of January 31, 2012 and 2011, and October 31, 2011, are summarized in the table below.


	January 31					October 31					January 31
In thousands	2012		Percentage			2011		Percentage			2011		Percentage
Short-term debt	$	457,500		21	%	$	331,000		16	%	$	315,500		15	%
Current portion of long-term debt		—		—	%		—		—	%		60,000		3	%
Long-term debt		675,000		31	%		675,000		34	%		671,904		33	%

Total debt		1,132,500		52	%		1,006,000		50	%		1,047,404		51	%
Common stockholders’ equity		1,030,086		48	%		996,923		50	%		1,015,514		49	%

Total capitalization (including short-term debt)	$	2,162,586		100	%	$	2,002,923		100	%	$	2,062,918		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 January 31, 2012, all of our long-term debt was unsecured. Our long-term debt is rated “A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. Credit ratings and outlooks are opinions of the rating agency 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 January 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 January 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, an open accelerated share repurchase (ASR) agreement and operating leases. The letters of credit and the ASR are discussed in Note 4 and Note 5, respectively, 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 three months ended January 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 three months ended January 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 January 31, 2012, we had $457.5 million of short-term debt outstanding under our revolving syndicated credit facility at an interest rate of 1.17%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $1 million during the three months ended January 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 first 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 three months ended January 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

a) Sale of Unregistered Equity Securities.

None.

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 January 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				3,710,074
11/1/11 - 11/30/11	—	$—	—	3,710,074
12/1/11 - 12/31/11	—	$—	—	3,710,074
1/1/12 - 1/31/12	800,000	$33.77	800,000	2,910,074

Total	800,000	$33.77	800,000

(1)

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

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”), except out of net earnings available for restricted payments. As of January 31, 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		Instrument of Amendment for Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan dated as of January 23, 2012, by Piedmont Natural Gas Company, Inc.

10.2		2011 Retention Award Agreement dated December 15, 2011 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains

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 (1)

101.SCH		XBRL Taxonomy Extension Schema (1)

101.CAL		XBRL Taxonomy Calculation Linkbase (1)

101.DEF		XBRL Taxonomy Definition Linkbase (1)

101.LAB		XBRL Taxonomy Extension Label Linkbase (1)

101.PRE		XBRL Taxonomy Extension Presentation Linkbase (1)

(1)	Furnished, not filed.

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 January 31, 2012 and October 31, 2011; (3) Consolidated Statements of Comprehensive Income for the three months

ended January 31, 2012 and 2011; (4) Consolidated Statements of Cash Flows for the three months ended January 31, 2012 and 2011; (5) Consolidated Statements of Stockholders’ Equity for the three months ended January 31, 2012 and 2011; and (6) Notes to Consolidated Financial Statements.

Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed furnished, not filed as part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

SIGNATURES

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


				Piedmont Natural Gas Company, Inc.
				(Registrant)

Date March 9, 2012				/s/ Karl W. Newlin
				Karl W. Newlin
				Senior Vice President and Chief Financial Officer
				(Principal Financial Officer)

Date March 9, 2012				/s/ Jose M. Simon
				Jose M. Simon
				Vice President and Controller
				(Principal Accounting Officer)

Piedmont Natural Gas Company, Inc.

Form 10-Q

For the Quarter Ended January 31, 2012

Exhibits

Compensatory Contract:


10.1		Instrument of Amendment for Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan dated as of January 23, 2012, by Piedmont Natural Gas Company, Inc.

10.2		2011 Retention Award Agreement dated December 15, 2011 between Piedmont Natural Gas Company, Inc. and Thomas E. Skains

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

INSTRUMENT OF AMENDMENT FOR

PIEDMONT NATURAL GAS COMPANY, INC.

DEFINED CONTRIBUTION RESTORATION PLAN

THIS INSTRUMENT OF AMENDMENT (this “ Instrument ”) is made and entered into as of the 23rd day of January, 2012, by PIEDMONT NATURAL GAS COMPANY, INC., a North Carolina corporation (the “ Company ”).

Statement of Purpose

The Company maintains the Piedmont Natural Gas Company, Inc. Defined Contribution Restoration Plan (the “ Plan ”). The Company desires to amend the Plan to change the definition of retirement. In Section 6.1 of the Plan the Company has reserved the right to amend the Plan in whole or in part at any time and has further directed that the Benefit Plan Committee (the “ Committee ”) shall have the authority to adopt any non-substantive amendment.

NOW, THEREFORE, the Company, acting through the Committee, does hereby declare that the Plan is amended to read as follows:

1. Effective as January 1, 2010, Section 2.1(b)(19) is amended in its entirety to read as follows:

““ Retirement ” shall mean a Participant’s Separation from Service on or after such Participant is eligible for early or normal retirement under the defined benefit pension plan sponsored by the Company or would have been so eligible if the Participant were eligible to participate in such plan.”

2. Except as expressly or by necessary implication amended hereby, the Plan shall continue in full force and effect.

IN WITNESS WHEREOF, the Company has caused this Instrument to be executed as of the day and year first above written.


PIEDMONT NATURAL GAS COMPANY, INC.

By:		/s/ Kevin M. O’Hara
		Kevin M. O’Hara
		Senior Vice President, Chief Administrative Officer

“Company”

Exhibit 10.2

Piedmont Natural Gas Company, Inc.

2011 Retention Award Agreement

This 2011 RETENTION AWARD AGREEMENT (this “ Agreement ”) is made and entered into this the 15 ^th day of December, 2011, by and between PIEDMONT NATURAL GAS COMPANY, INC. , a North Carolina corporation (the “ Company ”), and THOMAS E. SKAINS (the “ Participant ”) pursuant to the Piedmont Natural Gas Company, Inc. Incentive Compensation Plan, as amended and restated effective December 15, 2010 (the “ Plan ”). Capitalized terms used herein without definition have the meaning given in the Plan.

1. Award of Retention Stock Units . The Company hereby evidences and confirms its award to the Participant, effective as of the date hereof (the “ Award Date ”), of 64,700 Common Stock units. All Common Stock units awarded to the Participant under this Agreement are subject to the restrictions contained herein and are referred to as the “ Retention Stock Units .” This Agreement is subordinate to, and the terms and conditions of the Retention Stock Units awarded hereunder are subject to, the terms and conditions of the Plan, which are incorporated by reference into this Agreement. If there is any inconsistency between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall govern.

2. RSU Account; Dividend Equivalent Units . The Retention Stock Units shall be credited to a bookkeeping account in the name of the Participant on the books and records of the Company (the “ RSU Account ”). Within thirty (30) days after the payment date of any cash dividend with respect to Shares of Common Stock of the Company, the Participant’s RSU Account shall be credited with the number of additional Retention Stock Units determined by dividing (a) the product of the total number of Retention Stock Units credited to the Participant’s RSU Account as of the record date for such dividend multiplied by the per share amount of the dividend by (b) the Fair Market Value of a Share of Common Stock on such record date.

3. Vesting of Retention Stock Units .

(a) Vesting Period . Subject to the Participant’s continuous employment with the Company or a Subsidiary, and except as provided in Section 3(c) of this Agreement or Article X of the Plan, the “ Vesting Period ” shall commence on the Award Date and expire, and the Retention Stock Units credited to the RSU Account shall become vested, in accordance with the following schedule:


Vesting Date	Percentage of RSU Account Vested

December 15, 2014		20	%
December 15, 2015		30	%
December 15, 2016		50	%

Except for transfers by will or by the laws of descent and distribution, the Retention Stock Units may not be sold, assigned, transferred, pledged, hypothecated or otherwise directly or indirectly encumbered or disposed of until the expiration of the Vesting Period with respect to such Retention Stock Units.

(b) Termination of Employment . Except as otherwise provided in the Plan, if the Participant’s employment terminates for any reason during the Vesting Period, the unvested Retention Stock Units shall be forfeited and canceled as of the date of such termination.

(c) Committee Discretion . Notwithstanding anything contained in this Agreement to the contrary, the Committee, in its sole discretion, may accelerate the expiration date of the Vesting Period at such time and upon such terms and conditions as the Committee shall determine.

4. Receipt of Common Stock .

(a) Upon Vesting . The Company shall issue to the Participant one Share of Common Stock for each vested Retention Stock Unit awarded to the Participant within five (5) business days after the expiration of the Vesting Period and the vesting of such Retention Stock Unit.

(b) Cancellation of Retention Stock Units . The Retention Stock Units in respect of which Shares of Common Stock are issued pursuant to Section 4(a) of this Agreement shall be removed from the RSU Account and canceled upon the issuance of such Common Stock. In no event shall Shares of Common Stock be issued to the Participant, or to any person or entity claiming by or through the Participant, in respect of unvested Retention Stock Units.

5. Limitation of Rights . The Retention Stock Units do not confer upon the Participant, or the Participant’s estate or Designated Beneficiary in the event of the Participant’s death, any rights as a shareholder of the Company unless and until Shares of Common Stock are in fact issued to such person in respect of the Retention Stock Units. Nothing in this Award Agreement shall interfere with or limit in any way the right of the Company to terminate the Participant’s service at any time, nor confer upon the Participant any right to continue in the service of the Company.

6. Payment and Withholding of Taxes . The Company shall deduct from any Shares otherwise distributable to the Participant that number of Shares having a value equal to the amount of any taxes required by law to be withheld from awards made under the Plan. In the event the total amount of taxes required to be withheld by law is less than 50% of the value of the Shares distributable to the Participant, the Participant may elect to have the Company withhold a greater number of Shares (up to a maximum of fifty percent (50%) of the Shares distributable to the Participant) for tax withholding.

7. Binding Agreement . Subject to the limitation on the transferability of this award contained herein, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

8. Consent to Electronic Delivery . By executing this Agreement, the Participant hereby consents to the delivery of information (including, without limitation, information required to be delivered to the Participant pursuant to applicable securities laws) regarding the Company and the Subsidiaries, the Plan, and the Retention Stock Units via the Company’s website or other electronic delivery.

9. Section and Other Headings, etc . The section and other headings contained in this Agreement are for reference purposes only and shall not affect the meaning or

interpretation of this Agreement.

10. Counterparts . This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original and all of which together shall constitute one and the same instrument.

11. Agreement Severable . In the event that any provision in this Agreement will be held invalid or unenforceable, such provision will be severable from, and such invalidity or unenforceability will not be construed to have any effect on, the remaining provisions of this Agreement.

12. Modifications to the Agreement . This Agreement constitutes the entire understanding of the parties on the subjects covered. Modifications to this Agreement can be made only in an express written contract executed by a duly authorized officer of the Company.

13. Governing Law . Except to the extent superseded by the laws of the United States, this Agreement will be governed by, and construed in accordance with, the laws of the State of North Carolina without regard to principles of conflict of laws.

14. Additional Actions . The parties will execute such further instruments and take such further action as may reasonably be necessary to carry out the intent of this Agreement.

IN WITNESS WHEREOF , the Company and the Participant have executed this Agreement as of the Award Date.


PIEDMONT NATURAL GAS COMPANY, INC.

By:		/s/ Kevin M. O’Hara
		Kevin M. O’Hara
		Senior Vice President,
		Chief Administrative Officer

		/s/ Thomas E. Skains
		Thomas E. Skains

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 January 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.

March 9, 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 January 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.

March 9, 2012

/s/ Karl W. Newlin

Karl W. Newlin

Senior Vice President and Chief Financial Officer