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

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

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     o 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). o Yes     o 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. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o 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 2, 2010
Common Stock, no par value		71,741,380

 

 

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

January 31, 2010

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			24
Item 3.		Quantitative and Qualitative Disclosures about Market Risk			38
Item 4.		Controls and Procedures			40
Part II.		Other Information
Item 1.		Legal Proceedings			40
Item 1A.		Risk Factors			40
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 6.		Exhibits			41
		Signatures			43
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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,
		2010				2009
ASSETS
Utility Plant:
Utility plant in service		$	3,077,888			$	3,071,742
Less accumulated depreciation			879,659				862,079
Utility plant in service, net			2,198,229				2,209,663
Construction work in progress			112,515				87,978
Plant held for future use			6,751				6,751
Total utility plant, net			2,317,495				2,304,392
Other Physical Property, at cost (net of accumulated depreciation of $2,038 in 2010 and $2,497 in 2009)			685				719
Current Assets:
Cash and cash equivalents			16,198				7,558
Trade accounts receivable (less allowance for doubtful accounts of $3,516 in 2010 and $990 in 2009)			254,489				70,979
Income taxes receivable			14,111				44,413
Other receivables			1,298				4,712
Unbilled utility revenues			128,524				33,925
Inventories:
Gas in storage			104,077				103,584
Materials, supplies and merchandise			5,646				5,262
Gas purchase derivative assets, at fair value			1,616				2,559
Amounts due from customers			100,296				196,130
Prepayments			7,354				43,930
Other current assets			96				96
Total current assets			633,705				513,148
Noncurrent Assets:
Equity method investments in non-utility activities			109,344				104,430
Goodwill			48,852				48,852
Marketable securities, at fair value			889				441
Overfunded postretirement asset			10,773				—
Regulatory asset for postretirement benefits			76,672				76,905
Unamortized debt expense			9,014				9,177
Regulatory cost of removal asset			16,699				16,293
Other noncurrent assets			46,712				44,462
Total noncurrent assets			318,955				300,560
Total		$	3,270,840			$	3,118,819

See notes to consolidated financial statements.

		January 31,				October 31,
(In thousands)		2010				2009
CAPITALIZATION AND LIABILITIES
Capitalization:
Stockholders’ equity:
Cumulative preferred stock — no par value — 175 shares authorized		$	—			$	—
Common stock — no par value — shares authorized: 200,000; shares outstanding: 72,124 in 2010 and 73,266 in 2009			441,179				471,569
Retained earnings			552,636				458,826
Accumulated other comprehensive loss			(1,210	)			(2,447	)
Total stockholders’ equity			992,605				927,948
Long-term debt			732,313				732,512
Total capitalization			1,724,918				1,660,460
Current Liabilities:
Current maturities of long-term debt			60,000				60,000
Short-term debt			293,000				306,000
Trade accounts payable			156,003				67,010
Other accounts payable			31,278				48,431
Income taxes accrued			3,233				—
Accrued interest			12,016				21,294
Customers’ deposits			27,855				25,202
Deferred income taxes			33,986				14,138
General taxes accrued			8,068				19,993
Gas purchase derivative liabilities, at fair value			21,984				30,603
Other current liabilities			22,180				7,540
Total current liabilities			669,603				600,211
Noncurrent Liabilities:
Deferred income taxes			399,408				377,562
Unamortized federal investment tax credits			2,331				2,422
Accumulated provision for postretirement benefits			20,985				31,641
Cost of removal obligations			416,130				408,955
Other noncurrent liabilities			37,465				37,568
Total noncurrent liabilities			876,319				858,148
Commitments and Contingencies (Note 13)
Total		$	3,270,840			$	3,118,819

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Statements of Income (Unaudited)
(In thousands except per share amounts)

		Three Months Ended
		January 31
		2010				2009
Operating Revenues		$	673,736			$	779,644
Cost of Gas			450,794				558,961
Margin			222,942				220,683
Operating Expenses:
Operations and maintenance			52,039				50,725
Depreciation			24,355				24,142
General taxes			8,585				8,737
Income taxes			50,162				48,948
Total operating expenses			135,141				132,552
Operating Income			87,801				88,131
Other Income (Expense):
Income from equity method investments			11,833				9,790
Gain on sale of interest in equity method investment			49,674				—
Non-operating income			93				34
Non-operating expense			(363	)			(350	)
Income taxes			(23,985	)			(3,716	)
Total other income (expense)			37,252				5,758
Utility Interest Charges:
Interest on long-term debt			13,274				13,853
Allowance for borrowed funds used during construction			(519	)			(695	)
Other			(1,451	)			(145	)
Total utility interest charges			11,304				13,013
Net Income		$	113,749			$	80,876
Average Shares of Common Stock:
Basic			73,173				73,319
Diluted			73,545				73,646
Earnings Per Share of Common Stock:
Basic		$	1.55			$	1.10
Diluted		$	1.55			$	1.10
Cash Dividends Per Share of Common Stock		$	0.27			$	0.26

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
		2010				2009
Cash Flows from Operating Activities:
Net income		$	113,749			$	80,876
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			25,628				25,448
Amortization of investment tax credits			(91	)			(83	)
Allowance for doubtful accounts			2,526				1,828
Net gain on sale of interest in equity method investment, net of tax			(30,222	)			—
Gain on sale of property			(81	)			(77	)
Earnings from equity method investments			(11,833	)			(9,790	)
Distributions of earnings from equity method investments			1,004				1,251
Deferred income taxes			21,446				24,795
Stock-based compensation expense			—				84
Changes in assets and liabilities:
Gas purchase derivatives, at fair value			(7,676	)			68,071
Receivables			(277,415	)			(253,704	)
Inventories			(877	)			(2,558	)
Amounts due from customers			95,834				(24,383	)
Settlement of legal asset retirement obligations			(308	)			(381	)
Overfunded postretirement asset			(10,773	)			100
Regulatory asset for postretirement benefits			233				(383	)
Other assets			64,296				77,382
Accounts payable			74,912				21,461
Amounts due to customers			—				2,372
Regulatory liability for postretirement benefits			—				(5	)
Provision for postretirement benefits			(10,656	)			249
Other liabilities			1,233				8,209
Net cash provided by operating activities			50,929				20,762
Cash Flows from Investing Activities:
Utility construction expenditures			(33,880	)			(29,882	)
Allowance for funds used during construction			(519	)			(694	)
Distributions of capital from equity method investments			122				216
Proceeds from sale of interest in equity method investment			57,500				—
Proceeds from sale of property			351				—
Increase in restricted cash			—				(1	)
Investment in marketable securities			(455	)			(358	)
Other			55				281
Net cash provided by (used in) investing activities			23,174				(30,438	)

Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (Unaudited)
(In thousands)

		Three Months Ended
		January 31
		2010				2009
Cash Flows from Financing Activities:
Borrowings under short-term debt		$	(276,000	)		$	(383,000	)
Repayments under short-term debt			263,000				424,500
Retirement of long-term debt			(199	)			(394	)
Issuance of common stock through dividend reinvestment and employee stock plans			4,577				3,588
Repurchases of common stock			(36,878	)			—
Dividends paid			(19,813	)			(19,072	)
Other			(150	)			(50	)
Net cash provided by (used in) financing activities			(65,463	)			25,572
Net Increase in Cash and Cash Equivalents			8,640				15,896
Cash and Cash Equivalents at Beginning of Period			7,558				6,991
Cash and Cash Equivalents at End Period		$	16,198			$	22,887
Noncash Investing and Financing Activities:
Accrued construction expenditures		$	3,072			$	3,390

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Unaudited)
(In thousands)

		Three Months Ended
		January 31
		2010				2009
Net Income		$	113,749			$	80,876
Other Comprehensive Income:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $369 in 2010 and ($1,511) in 2009			573				(2,343	)
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $428 in 2010 and ($566) in 2009			664				(880	)
Total Comprehensive Income		$	114,986			$	77,653

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, 2009.

      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, 2010 and October 31, 2009, the results of operations for the three months ended January 31, 2010 and 2009, and cash flows for the three months ended January 31, 2010 and 2009. Our business is seasonal in nature. The results of operations for the three months ended January 31, 2010 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 at 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, 2009. There were no significant changes to those accounting policies during the three months ended January 31, 2010.

      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 rate riders or base rates 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 rate-based 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 future rate proceedings; therefore, we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a future rate recovery proceeding.

Regulatory assets and liabilities in the consolidated balance sheets as of January 31, 2010 and October 31, 2009 are as follows.

		January 31,				October 31,
In thousands		2010				2009
Regulatory assets		$	244,702			$	337,543
Regulatory liabilities			417,130				409,323

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 8 to the consolidated financial statements in this Form 10-Q.

      Accounting Pronouncements

In December 2008, the Financial Accounting Standards Board (FASB) issued new accounting guidance for employers’ disclosures about plan assets of defined benefit pension and other postretirement plans. This guidance requires that employers provide more transparency about the assets held by retirement plans or other postretirement employee benefit plans, the concentration of risk in those plans and information about the fair value measurements of plan assets similar to the disclosures required by current fair value guidance. The guidance is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since only additional disclosures about plan assets of defined benefit pension and other postretirement plans are required, it is not expected to have a material impact on our financial position, results of operations or cash flows. We will adopt the guidance on benefit plan assets during our fiscal year ending October 31, 2010.

In January 2010, the FASB issued accounting guidance to require new fair value measurement and classification disclosures, and to clarify existing disclosures. The guidance requires disclosures about transfers into and out of Levels 1 and 2 of the fair value hierarchy, and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. It also clarifies the existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value, and amends guidance on employers’ disclosures about postretirement benefit plan assets to require disclosures be provided by asset class instead of major categories of assets. The guidance is effective for interim and fiscal periods beginning after December 15, 2009, with the exception that the Level 3 activity disclosure requirement will be effective for interim periods for fiscal years beginning after December 15, 2010. Since the guidance addresses only disclosure related to fair value measurements, adoption of the guidance during our fiscal second quarter beginning February 1, 2010 did not have a material impact on our financial position, results of operations or cash flows. We will adopt the guidance for Level 3 disclosure for the first quarter of our fiscal year ending October 31, 2012.

2. Regulatory Matters

On August 3, 2009, 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, 2009. A hearing was held

on October 6, 2009 and testimony was submitted by us and the North Carolina Public Staff with agreed upon adjustments for the 2009 gas cost review period. A joint proposed order was filed on November 12, 2009. On February 17, 2010, the NCUC issued an order approving our gas cost purchasing and accounting practices for the period under review.

On October 1, 2009, we filed a petition with the Public Service Commission of South Carolina (PSCSC) requesting approval to offer three energy efficiency programs to residential and commercial customers. The proposed programs in South Carolina are designed to promote energy conservation and efficiency by residential and commercial customers with full ratepayer recovery of program costs and are similar to approved energy efficiency programs in North Carolina. A hearing was held on February 11, 2010. We are unable to predict the outcome of this proceeding at this time.

On July 1, 2009, we filed an annual report for the twelve months ended December 31, 2008 with the Tennessee Regulatory Authority (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 July 16, 2009, we filed a petition with the TRA requesting approval to decouple residential rates in Tennessee and to offer three energy efficiency programs to residential customers. We proposed a margin decoupling tracker mechanism that was designed to allow us to recover from our residential customers the approved per customer margin as approved in our last general rate proceeding. The proposed energy efficiency programs in Tennessee were designed to promote energy conservation and efficiency by residential customers and were similar to approved energy efficiency programs in North Carolina. On August 24, 2009, the TRA suspended the tariff and established a contested case to address the filing. A hearing on our requests was held in December 2009. In January 2010, the TRA denied our petition without prejudice to us refiling a margin decoupling tracker mechanism and energy efficiency programs for residential customers in a general rate proceeding.

3. Earnings per Share

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. A reconciliation of basic and diluted earnings per share for the three months ended January 31, 2010 and 2009 is presented below.

		Three Months
In thousands except per share amounts		2010				2009
Net Income		$	113,749			$	80,876
Average shares of common stock outstanding for basic earnings per share			73,173				73,319
Contingently issuable shares under incentive compensation plans			372				327
Average shares of dilutive stock			73,545				73,646
Earnings Per Share of Common Stock:
Basic		$	1.55			$	1.10
Diluted		$	1.55			$	1.10

4. 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 plans that became effective on January 1, 2009. For further information on the deferred compensation plans, see Note 6 to the consolidated financial statements.

The money market investments in the trust approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of January 31, 2010 and October 31, 2009 is as follows.

		As of January 31, 2010								As of October 31, 2009
						Fair								Fair
In thousands		Cost				Value				Cost				Value
Money markets		$	263			$	263			$	169			$	169
Mutual funds			566				626				205				272
Total trading securities		$	829			$	889			$	374			$	441

5. Capital Stock

On November 16, 2009, we discovered that we had inadvertently sold more shares under our dividend reinvestment and stock purchase plan (DRIP) than were registered with the SEC and authorized by our Board of Directors for issuance under the DRIP. We also discovered that the registration statement we believed had registered shares issued under the DRIP between December 1, 2008 and November 16, 2009 had expired for some of those shares. As a result, 568,000 shares sold to DRIP participants at prices ranging from $21.59 to $31.56 during that period may not have been properly registered under the Securities Act. We received $13.6 million in the aggregate from these sales, which was used for financing the construction of additions to our facilities and for general corporate purposes. Our Board of Directors ratified the authorization and issuance of the excess number of shares, and on November 20, 2009, we filed a registration statement covering the sale and issuance of an additional 2.75 million shares of our common stock under the DRIP. On February 8, 2010, we

filed a registration statement which offers to rescind the purchase of the 568,000 shares sold under the DRIP between December 1, 2008 and November 16, 2009 and registers all previously unregistered shares issued under the DRIP during that period. While we are unable to predict the full consequences of these events, we do not expect any rescissions or regulatory actions, if any, to have a material adverse effect on us.

In January 2010, we began to purchase and retire 1.8 million shares of our common stock under the Common Stock Open Market Purchase Program. We used a broker to repurchase the shares on the open market, and such shares were cancelled and became authorized but unissued shares available for issuance. As of January 31, 2010, we had repurchased 1.4 million shares at an average price of $26.38 per share. Total consideration paid of $36.9 million to purchase the shares was recorded in “Stockholders’ equity” as a reduction in “Common stock” in the consolidated balance sheets. In February 2010, we repurchased an additional .4 million shares for $10.4 million under the program.

6. 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, 2010 and 2009 are presented below.

		Qualified Pension								Nonqualified Pension								Other Benefits
In thousands		2010				2009				2010				2009				2010				2009
Service cost		$	2,100			$	1,487			$	10			$	6			$	334			$	360
Interest cost			2,850				2,750				61				83				476				579
Expected return on plan assets			(4,775	)			(4,138	)			—				—				(345	)			(426	)
Amortization of transition obligation			—				—				—				—				167				167
Amortization of prior service (credit) cost			(550	)			(549	)			5				5				—				—
Amortization of actuarial loss (gain)			550				—				2				(10	)			59				—
Total		$	175			$	(450	)		$	78			$	84			$	691			$	680

In January 2010, we contributed $22 million to the qualified pension plan and $.2 million to the money purchase pension plan. We anticipate that we will contribute the following amounts to our other plans in 2010.

		In thousands
Nonqualified pension plan		$	528
OPEB plan			3,400

We have a defined contribution restoration plan that we fund annually and that covers all officers at the vice president level and above. For the three months ended January 31, 2010, we contributed $.4 million to this plan. We have a voluntary deferral plan for the benefit of all director-level employees and officers; we make no contributions to this plan. Both deferred compensation plans are funded through a rabbi trust with a bank as the trustee. At January 31, 2010, we have a liability of $.9 million for these plans.

See Note 4 and Note 9 to the consolidated financial statements of this Form 10-Q for information on the investments in marketable securities that are held in the trust.

7. Business Segments

We have two reportable business segments, regulated utility and non-utility activities. These segments were identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. Operations of our regulated utility segment are conducted by the parent company. Operations of our non-utility activities segment are comprised of our equity method investments in joint ventures.

Operations of the regulated utility segment are reflected in operating income in the consolidated statements of income. Operations of the non-utility activities segment are included in the consolidated statements of 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, 2009.

Operations by segment for the three months ended January 31, 2010 and 2009 are presented below.

		Regulated								Non-utility
		Utility								Activities								Total
In thousands		2010				2009				2010				2009				2010				2009
Three Months
Revenues from external customers		$	673,736			$	779,644			$	—			$	—			$	673,736			$	779,644
Margin			222,942				220,683				—				—				222,942				220,683
Operations and maintenance expenses			52,039				50,725				123				39				52,162				50,764
Income from equity method investments			—				—				11,833				9,790				11,833				9,790
Gain from sale of interest in equity method investment			—				—				49,674				—				49,674				—
Operating income (loss) before income taxes			137,963				137,079				(212	)			(132	)			137,751				136,947
Income before income taxes			126,599				123,892				61,297				9,648				187,896				133,540

Reconciliations to the consolidated statements of income for the three months ended January 31, 2010 and 2009 are presented below.

		Three Months
In thousands		2010				2009
Operating Income:
Segment operating income before income taxes		$	137,751			$	136,947
Utility income taxes			(50,162	)			(48,948	)
Non-utility activities before income taxes			212				132
Operating income		$	87,801			$	88,131
Net Income:
Income before income taxes for reportable segments		$	187,896			$	133,540
Income taxes			(74,147	)			(52,664	)
Net income		$	113,749			$	80,876

8. 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 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.

On October 22, 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 is subject to NCUC approval, to expand our firm capacity requirement by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to spend as much as $39.2 million for the addition of 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. As an equity venture partner of Cardinal, we will invest as much as $8.7 million in Cardinal’s system expansion. When the project is placed into service on the scheduled in-service date of July 1, 2012, the members’ capital will be replaced with permanent financing with a target overall capital structure of 45-50% debt and 50-55% equity. The NCUC issued a formal certificate order to Progress Energy Carolinas for their Wayne County generation project on October 1, 2009.

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, 2010 and 2009, these transportation costs and the amounts we owed Cardinal as of January 31, 2010 and October 31, 2009 are as follows.

		Three Months
In thousands		2010				2009
Transportation costs		$	1,035			$	1,035

		January 31,				October 31,
		2010				2009
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 liquefied natural gas (LNG) storage facility in North Carolina and is regulated by the Federal Energy Regulatory Commission (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, 2010 and 2009, these gas storage costs and the amounts we owed Pine Needle as of January 31, 2010 and October 31, 2009 are as follows.

		Three Months
In thousands		2010				2009
Gas storage costs		$	3,209			$	3,024

		January 31,				October 31,
		2010				2009
Trade accounts payable		$	1,083			$	1,081

We own 15% of the membership interest 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 with most of its business being conducted in the unregulated retail gas market in Georgia. On January 1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC resulting in an after-tax gain of $30.2 million, or $0.41 per diluted share. GNGC has no further rights to our remaining 15% interest. We will continue to maintain 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 will continue to account for our 15% membership interest in SouthStar using the equity method, as all significant management decisions require the approval of both owners.

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, 2010 and 2009, our operating revenues from these sales and the amounts SouthStar owed to or by us as of January 31, 2010 and October 31, 2009 are as follows.

		Three Months
In thousands		2010				2009
Operating revenues (refund)		$	(63	)		$	2,998

		January 31,				October 31,
		2010				2009
Trade accounts (payable) receivable		$	(53	)		$	639

Summarized financial information provided to us by SouthStar for 100% of SouthStar for the three months ended December 31, 2009 and 2008 is presented below.

		Three Months
In thousands		2009				2008
Revenues		$	232,366			$	285,910
Gross profit			59,952				48,164
Income before income taxes			39,361				29,856

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. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a subsidiary of NiSource Inc. 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. Initial service to customers began April 1, 2007 when customers began injecting gas into storage for subsequent winter withdrawals. Final service levels were placed into service on April 1, 2009 as scheduled.

On June 29, 2006, Hardy Storage signed a note purchase agreement for interim notes and a revolving equity bridge facility for up to a total of $173.1 million for funding during the construction period. On November 1, 2007, Hardy Storage paid off the equity line of $10.2 million with member equity contributions, leaving an amount outstanding on the interim notes of $123.4 million.

The members of Hardy Storage each agreed to guarantee 50% of the construction financing. Our guaranty was executed by Piedmont Energy Partners, Inc. (PEP), a wholly owned subsidiary of Piedmont. Our share of the guaranty is capped at $111.5 million and expires upon closing of permanent financing. Depending upon the facility’s performance over the first three years after the in-service date, there could be additional construction expenditures of up to $10 million for contingency wells, of which PEP will guarantee 50%.

Securing PEP’s guaranty is a pledge of intercompany notes issued by Piedmont held by non-utility subsidiaries of PEP. Should Hardy Storage be unable to perform its payment obligation under the construction financing, PEP will call on Piedmont for the payment of the notes, plus accrued interest, for the amount of the guaranty. Also pledged is our membership interest in Hardy Storage.

We anticipate closing the permanent project financing in mid March 2010. The interim notes of $123.4 million will be replaced with a fifteen-year mortgage-style debt instrument without recourse to the members. We are structuring a capitalization of 70% debt and 30% equity.

We record a liability at fair value for this guaranty based on the present value of 50% of the construction financing outstanding at the end of each quarter, with a corresponding increase to our investment account in the venture. As our risk in the project changes, the fair value of the guaranty is adjusted accordingly through a quarterly evaluation. We continued to record the guaranty this quarter as the project was not closed out. The details of the guaranty at January 31, 2010 and October 31, 2009 are as follows.

		January 31,				October 31,
In thousands		2010				2009
Guaranty liability — PEP		$	1,234			$	1,234
Amount outstanding under the construction financing — Hardy Storage			123,410				123,410

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, 2010 and 2009, our gas storage costs and the amounts we owed Hardy Storage as of January 31, 2010 and October 31, 2009 are as follows.

		Three Months
In thousands		2010				2009
Gas storage costs		$	2,236			$	2,321

		January 31,				October 31,
		2010				2009
Trade accounts payable		$	746			$	781

9. 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. Based on the value of our positions in these brokerage accounts and the associated margin requirements, we may be required to deposit cash into these brokerage accounts. The accounting guidance related to derivatives and hedging requires that we use a gross presentation for the fair value amounts for our derivative instruments and the fair value of the right to reclaim cash collateral. We include amounts recognized for the right to reclaim cash collateral in our current assets and current liabilities. We had the right to reclaim cash collateral of $26.5 million and $35.4 million as of January 31, 2010 and October 31, 2009, respectively.

     Fair Value Measurements

We use financial instruments to mitigate commodity price risk for our customers. 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. These inputs can be readily observable, market corroborated or generally observable. We primarily apply the market approach for recurring 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. We are able to 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.

Effective November 1, 2009, we adopted the additional authoritative guidance related to nonrecurring fair value for certain nonfinancial assets and liabilities, such as the initial measurement of an asset retirement obligation and the use of fair value in goodwill, intangible assets and long-lived asset impairment tests. The adoption of this fair value guidance for reporting these nonrecurring fair value measurements had no impact on our financial position, results of operations or cash flows for the three months ended January 31, 2010.

Level 1 inputs which are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access as of the reporting date consist of financial instruments of exchange-traded derivatives and investments in marketable securities. Level 2 inputs which are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly corroborated or observable as of the reporting date and generally use valuation methodologies, consist of non-exchange-traded derivative

instruments such as over-the-counter (OTC) options. Level 3 inputs include significant pricing inputs that are generally less observable from objective sources which consist of cost estimates for removal (contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining life of long-lived assets and the credit adjusted risk free rate to discount for the time value of money over the appropriate time spans.

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, 2010 and October 31, 2009. 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.

Recurring Fair Value Measurements as of January 31, 2010

						Significant
		Quoted Prices				Other				Significant
		in Active				Observable				Unobservable				Total
		Markets				Inputs				Inputs				Carrying
In thousands		(Level 1)				(Level 2)				(Level 3)				Value
Assets:
Derivatives held for distribution operations		$	1,616			$	—			$	—			$	1,616
Debt and equity securities held as trading securities			889				—				—				889
Total fair value assets		$	2,505			$	—			$	—			$	2,505
Liabilities:
Derivatives held for distribution operations		$	21,984			$	—			$	—			$	21,984

Recurring Fair Value Measurements as of October 31, 2009

						Significant
		Quoted Prices				Other				Significant
		in Active				Observable				Unobservable				Total
		Markets				Inputs				Inputs				Carrying
In thousands		(Level 1)				(Level 2)				(Level 3)				Value
Assets:
Derivatives held for distribution operations		$	2,559			$	—			$	—			$	2,559
Debt and equity securities held as trading securities			441				—				—				441
Total fair value assets		$	3,000			$	—			$	—			$	3,000
Liabilities:
Derivatives held for distribution operations		$	30,290			$	313			$	—			$	30,603

The determination of the fair values incorporates various factors required under the fair value guidance. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, letters of credit and priority interests) and the impact of our nonperformance risk on our liabilities.

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

instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due to customers” or “Amounts due from customers” in our consolidated balance sheets. These derivative instruments include exchange-traded and OTC derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1. OTC derivative contracts are valued using broker or dealer quotation services or market transactions in either the listed or OTC markets and are classified within Level 2.

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.

The carrying value of cash and cash equivalents, receivables, short-term debt, accounts payable and accrued interest approximate fair value.

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.

		Carrying
In thousands		Amount				Fair Value
As of January 31, 2010		$	792,313			$	896,362
As of October 31, 2009			792,512				910,310

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. As of January 31, 2010, our financial options were comprised of both long and short commodity positions. A long position in an option contract is a right to purchase or sell the commodity at a specified price, while a short position in an option contract is the obligation, if the option is exercised, to purchase or sell the commodity at a specified price. As of January 31, 2010, we had long gas options providing total coverage of 34.2 million dekatherms, of which 22.2 million dekatherms are limited in upside protection. We have sold options for 14.9 million dekatherms that guarantee a minimum floor price for supply. The long and short options are for the period from March 2010 through February 2011.

The following table presents the fair value and balance sheet classification of our financial options for natural gas as of January 31, 2010 and October 31, 2009.

Fair Value of Derivative Instruments as of January 31, 2010

		Balance Sheet Classification		Fair Value
				in thousands
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments
Gas purchase options (March 2010-February 2011)		Current Assets — Gas purchase derivative assets		$	1,616
Liability Financial Instruments
Gas purchase options (March 2010-February 2011)		Current Liabilities — Gas purchase derivative liabilities			21,984
Total financial instruments, net				$	(20,368	)

Fair Value of Derivative Instruments as of October 31, 2009

		Balance Sheet Classification		Fair Value
				in thousands
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
Asset Financial Instruments
Gas purchase options (December 2009-November 2010)		Current Assets — Gas purchase derivative assets		$	2,559
Liability Financial Instruments
Gas purchase options (December 2009-November 2010)		Current Liabilities — Gas purchase derivative liabilities			30,603
Total financial instruments, net				$	(28,044	)

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 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 generally has no earnings impact.

The following table presents the impact that financial instruments would have had on our consolidated statements of income for the three months ended January 31, 2010, absent the regulatory treatment under our approved PGA procedures.

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards

Amount of Loss Recognized

Amount of Loss Deferred

Location of Loss

on

Under

Recognized through

in thousands

Derivatives

PGA Procedures

PGA Procedures

Gas purchase options

$

(16,650

)

$

(16,650

)

Cost of Gas

In Tennessee, the cost of these options and all other costs related to hedging activities up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our Tennessee Incentive Plan (TIP) approved by the TRA. In South Carolina, the costs of these options are pre-approved by the PSCSC for

recovery from customers subject to the terms and conditions of our gas hedging plan approved by the PSCSC. In North Carolina, costs associated with our hedging program are not pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding by the NCUC. In 2009, as a part of our North Carolina annual cost review proceeding for the twelve months ended May 31, 2009, we and the North Carolina Public Staff agreed to an adjustment of $1.1 million related to hedging activity as reflected in “Amounts due from customers,” which was approved by the NCUC in February 2010.

     Risk Management

Our OTC derivative financial instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments over and above payments made in the normal course of business when we are in a net liability position. At January 31, 2010, we have five International Swaps and Derivatives Association (ISDA) agreements for the purpose of securing put options as a part of our overall hedging program. The ISDA agreements specify a net liability of $55 million, $50 million, $30 million, $25 and $2 million before we are obligated to post collateral. The net liability extended under the agreements is a function of the credit rating assigned to us by Standard & Poor’s Ratings Services (S&P), which is currently A/stable. In the event of a downgrade in our S&P credit rating to A-, the net liability available to us would decline to $142 million before we would be obligated to post collateral. We have no outstanding positions under any ISDA agreement as of January 31, 2010.

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

10. Long-Term Debt Instruments

During the three months ended January 31, 2010, we paid $.2 million to noteholders of the 6.25% insured quarterly notes. These notes have a redemption right upon the death of the owner of the notes, within specified limitations.

11. Short-Term Debt Instruments

We have a syndicated five-year revolving credit facility that expires April 2011 with aggregate commitments totaling $450 million to meet working capital needs. This facility may be increased up to $600 million and includes annual renewal options and letters of credit. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. The facility provides a line of credit for letters of credit of $5 million, of which $2.7 million and $2.4 million were issued and outstanding at January 31, 2010 and October 31, 2009, 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 15 to 35 basis points, based on our credit ratings. Amounts borrowed remain outstanding until repaid, and such amounts do not mature daily. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.

As of January 31, 2010 and October 31, 2009, outstanding short-term borrowings under our syndicated five-year credit facility, as included in “Short-term debt” in the consolidated balance sheets, were $293 million and $306 million, respectively, in LIBOR cost-plus loans. During the three months ended January 31, 2010, short-term borrowings ranged from $236.5 million to $342.5 million, and interest rates ranged from .48% to .5% (weighted average of .49%). Our syndicated five-year revolving 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 52% at January 31, 2010.

We have corrected the presentation within the consolidated statements of cash flows for the three months ended January 31, 2009 to present borrowings and repayments under our syndicated five-year revolving credit facility on a gross basis. Such borrowings and repayments were formerly presented on a net basis. There was no effect on total cash flows from financing activities.

12. Employee Share-Based Plans

Under Board of Directors approved incentive compensation plans, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year 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, 2010 and 2009, we recorded compensation expense, and as of January 31, 2010 and October 31, 2009, we have accrued amounts 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.

Also under our approved incentive plan, 65,000 unvested shares of our common stock were granted to our President and Chief Executive Officer in September 2006. During the five-year vesting period, any dividends paid on these shares are accrued and converted into additional shares at the closing price on the date of the dividend payment. In accordance with the vesting schedule, 20% of the shares vested on September 1, 2009. The remaining 30% and 50% of the shares will vest on September 1, 2010 and 2011, respectively. For the three months ended January 31, 2010 and 2009, we recorded compensation expense, and as of January 31, 2010 and October 31, 2009, we have accrued amounts 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.

The compensation expense related to the incentive compensation plans for the three months ended January 31, 2010 and 2009, and the amounts recorded as liabilities as of January 31, 2010 and October 31, 2009 are presented below.

		Three Months
In thousands		2010				2009
Compensation expense		$	2,774			$	(70	)

		January 31,				October 31,
		2010				2009
Liability		$	7,210			$	8,173

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.

Currently, it is our policy to issue new shares for share-based awards. 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.

13. 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, telecommunication and information technology contracts and other purchase obligations. The time periods for pipeline and storage capacity contracts range from one to fourteen years. The time periods for gas supply contracts range from one to three years. The time periods for the telecommunications and technology outsourcing contracts, maintenance fees for hardware and software applications, usage fees, local and long-distance costs and wireless service 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 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 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.

     Legal

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

     Letters of Credit

We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $2.7 million in letters of credit that were issued and outstanding at January 31, 2010. Additional information concerning letters of credit is included in Note 11 to the consolidated financial statements in this Form 10-Q.

     Environmental Matters

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

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 and paid $5.3 million, charged to the estimated environmental liability, 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. On one of these nine properties, we performed additional clean-up activities, including the removal of an underground storage tank, in anticipation of an impending sale.

There are three other MGP sites located in Hickory, North Carolina, Nashville, Tennessee and Anderson, South

Carolina that we have owned, leased or operated. In addition to these sites, we acquired the liability for an MGP site located in Reidsville, North Carolina, in connection with the acquisition in 2002 of certain assets and liabilities of North Carolina Services, a division of NUI Utilities, Inc.

As part of a voluntary agreement with the North Carolina Department of Environment and Natural Resources (NCDENR), we started the initial steps for investigating the Hickory, North Carolina MGP site in 2007. Based on a limited site assessment report in 2007, we concluded that gas plant residuals remaining on the Hickory site were thought to be mostly contained within two former tar separators associated with the site’s operations. During 2008, more extensive testing was conducted and completed, including soil investigation and phase 1 of the groundwater investigation. The soil investigation revealed that most of the site surface soils and a significant area of deep soils exceed the site specific cleanup standards, and phase 1 of the groundwater investigation revealed contamination from an underground storage tank and the MGP. A remedial work plan to remove the soil has been submitted and approved by the NCDENR. The removal of approximately 10,000 tons of MGP impacted soil and phase 2 groundwater investigation has been delayed at the request of the property owners until our second fiscal quarter. Our estimate of the total cost to remediate the soil contamination is $1 million, and the phase 2 groundwater investigation may reveal the need for additional groundwater remediation.

In September 2009, the NCDENR requested a remediation plan for the Reidsville, North Carolina MGP site. In January 2010, we submitted our plan to the NCDENR. Our estimate of the total cost to remediate the Reidsville site is $.8 million.

In November 2008, we submitted our final report of the remediation of the Nashville MGP site to the Tennessee Department of Environment and Conservation (TDEC). Subsequently, the TDEC requested an additional soil removal report, groundwater monitoring and its reporting, and limited soil investigation of an adjacent property and its reporting. Minor groundwater contamination was detected and soil contaminant levels of the adjacent property were found to be within state standards. Work is progressing to finalize the consent order for the site with the TDEC, and we anticipate completion in our fourth quarter of 2010. We have incurred $1.5 million through January 31, 2010.

In connection with the 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.

We are continuing to investigate and remediate the property where our Huntersville LNG facility is located. During the three months ended January 31, 2010, our estimate of the total cost to remediate the property increased from $1.6 million to $2.3 million, for which we increased our reserve by the additional $.7 million. We have incurred $1.3 million through January 31, 2010. For further information, see Note 7 to our Form 10-K for the year ended October 31, 2009.

Further evaluation of the MGP sites and the underground storage tank sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.

During 2008, through the normal course of an on-going business review, one of our operating districts was found to have coatings containing asbestos on their pipelines. We have taken action to educate employees on the hazards of asbestos and to implement procedures for removing these coatings from our pipelines when we

must excavate and expose small portions of the pipeline. We continue to determine the impacts and related costs to us, if any, and the impact to employees and contractors, if any.

Additional information concerning commitments and contingencies is set forth in Note 7 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2009.

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 have been evaluated. For information on subsequent events disclosure items related to regulatory matters and common stock, see Note 2 and Note 5, respectively, to the consolidated financial statements of this Form 10-Q.

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

Forward-Looking Statements

This report, as well as other documents we file with the 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 and information currently available and are believed to be reasonable and are made in good faith. However, the forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those projected in the statements. Factors that may make the actual results differ from anticipated results include, but are not limited to:

	•		Regulatory issues affecting us and those from whom we purchase natural gas transportation and storage service, including those 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.
	•		Residential, commercial, industrial and power generation growth and energy consumption in our service areas. The ability to 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 fluctuations in the wholesale prices of natural gas and competitive energy sources.
	•		Deregulation, regulatory restructuring and competition in the energy industry. We face competition from electric companies and energy marketing and trading companies, and we expect this competitive environment to continue.
	•		The potential loss of large-volume industrial customers to alternate fuels or to bypass, or the shift by such customers to special competitive contracts or to tariff rates that are at lower per-unit margins than that customer’s existing rate.
	•		The capital-intensive nature of our business. In order to maintain growth, we must add to our natural gas distribution system each year. The cost of this construction may be affected by the cost of obtaining governmental approvals, compliance with federal and state pipeline safety and integrity regulations, development project delays 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 or our financial condition 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, can impact 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 environmental, safety, system integrity, tax and other laws and regulations, including those related to climate change, and the cost of compliance. We are subject to extensive federal, state and local laws and regulations. Compliance with such laws and regulations could increase capital or operating costs, affect our reported earnings, 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 repurchases under our Common Stock Open Market Purchase Program or new issuances.

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,” “will,” “assume,” “can,” “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 only 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. Please reference our website at www.piedmontng.com for current information. 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 as soon as reasonably practicable after the report is filed with or

furnished to the SEC.

Executive 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 61,000 customers served by municipalities who are our wholesale customers. We are invested in joint venture, energy-related businesses, including unregulated retail natural gas marketing, 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 Greenville, Monroe, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of Nashville, including wholesale natural gas service to 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 96% of our consolidated assets. Factors critical to the success of the regulated segment include 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, 2010, our earnings before taxes, including the gain from the sale of half of our ownership interest in SouthStar of $49.7 million, were $187.9 million. For the current period, 67% of our earnings before taxes, including the gain from the sale of half of our ownership interest in SouthStar, 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, interstate natural gas storage and intrastate natural gas transportation. For the three months ended January 31, 2010, the earnings before taxes from our non-utility segment, including the gain from the sale of half of our ownership interest in SouthStar, was 33%, which consisted of 1% from regulated non-utility activities and 32% from unregulated non-utility activities.

The GAAP presentation does not adequately reflect our segments because of the inclusion of the gain from the sale of half of our ownership interest in SouthStar, which is in our non-utility activities segment. Excluding this gain, for the three months ended January 31, 2010, 92% of our earnings before taxes came from our regulated utility segment, and earnings before taxes from our non-utility segment was 8%, which consisted of 1% from regulated non-utility activities and 7% from unregulated non-utility activities.

For further information on business segments, see Note 7 to the consolidated financial statements in this Form 10-Q. For information about our equity method investments, see Note 8 to the consolidated financial statements in this Form 10-Q.

Our utility operations are regulated by the NCUC, the PSCSC and the TRA as to rates, service area, adequacy of service, safety standards, extensions and abandonment of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance of 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 FERC that affect the purchase and sale of and the prices paid for the interstate transportation and storage of natural gas, regulations of the Department of Transportation that affect the 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 regulations, such as those relating to employment 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 cover our gas and non-gas costs and to earn a fair rate of return for our shareholders. In North Carolina, a margin decoupling mechanism provides for the recovery of our approved margin from residential and commercial customers 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. We have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that partially offset the impact of colder- or warmer-than-normal 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 gas cost portion of our costs is recoverable through PGA procedures and is not affected by the margin decoupling mechanism or the WNA.

Our strategic focus is on our core business of providing safe, reliable and quality natural gas distribution service to our customers in the growing Southeast market area. Part of our strategic plan is to responsibly manage our gas distribution business through control of our operating costs, implementation of new technologies and sound rate and regulatory initiatives. We are working to enhance the value and growth of our utility assets by good management of capital spending, including improvements for current customers, and the pursuit of profitable customer growth opportunities in our service areas. We strive for quality customer service by investing in technology, processes and people. We work with our state regulators to maintain fair rates of return and balance the interests of our customers and shareholders.

We seek to maintain a long-term debt-to-capitalization ratio within a range of 45% to 50%. We also seek to maintain a strong balance sheet and investment-grade credit ratings to support our operating and investment needs.

With the combination of the global recession and the movement to implement climate change policies that will impact how energy is used in this country, we are working toward a business model that positions us for long-term success in a carbon-constrained energy economy. This includes continual assessment of the nature of our business and examination of alternative cost recovery mechanisms and rate structures that are more appropriate in a changing energy economy. Additionally, we are seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation and efficiency and environmental stewardship.

One of our objectives has been to focus on future growth opportunities in a low-carbon energy economy. We are continually reviewing our business processes for quality and efficiency with a concentration on customer-oriented process improvements to be in a position to seize future business opportunities.

We must leverage our regulatory structure to realize future growth opportunities in a low-carbon energy economy. One example of this is our pursuit of alternatives to the traditional utility rate design that provide for the collection of margin revenue based on volumetric throughput with new rate designs and incentives that allow utilities to encourage energy efficiency and conservation. By breaking the link between energy consumption and margin revenues, or decoupling as we say, utilities’ interests are aligned with customers’ interests around conservation and energy efficiency. In North Carolina, we have decoupled rates. In South

Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin decoupling with a one-year lag. The TRA denied our filing to decouple residential rates without prejudice to us refiling for a decoupled rate structure in a general rate proceeding.

Even as we implement energy efficiency programs for our customers so that individual residential and business customers can save on their total natural gas bill by using natural gas as efficiently as possible, we also will continue our efforts to promote the direct use of natural gas in more homes, businesses, industries and vehicles. Our message is simple: the expanded use of domestic natural gas can help revitalize our economy, reduce overall greenhouse gas emissions and enhance our national energy security. With the success of drilling and completion technologies, recent production of domestic natural gas supplies from shale formations has resulted in an increase of domestic gas supply, which in turn has contributed to a moderation in the price of gas. This price moderation, if it continues as many in the industry anticipate, should lead to an increase in the competitiveness of natural gas as compared to other fuels.

In October 2009, we announced an agreement with Progress Energy Carolinas, Inc., a subsidiary of Progress, to provide natural gas delivery service to a new power generation facility to be built at their Wayne County, North Carolina power generation site. In addition to the environmental benefits associated with using natural gas at this new plant, the construction of the natural gas pipeline for this project will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for additional economic growth and development.

While we are seeing the impacts of the economic recession in our market area with a decline in customer growth in our new construction market and continued customer conservation practices, we have seen some rebound in the industrial markets as compared with the prior year period. As discussed above, we are positioning ourselves to capitalize on new opportunities as the economy improves.

To mitigate the decline in gross residential and commercial customer additions, we are actively seeking customer conversions to natural gas in order to gain new customers outside of the new construction market.

Under current economic conditions and a colder winter, it could become more difficult for some customers to pay their gas bills, potentially leading to slower collections and higher non-gas bad debt expense. With the potential of slower turnovers of accounts receivable, our level of borrowings could increase in order to meet our working capital 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 a projected rate of return greater than the returns allowed in our utility operations due to the higher 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. On January 1, 2010, we sold half of our 30% interest in SouthStar to GNGC for $57.5 million. For further information, see Note 8 to the consolidated financial statements in this Form 10-Q.

Results of Operations

We reported net income of $113.7 million for the three months ended January 31, 2010 as compared to $80.9 million for the same period in 2009. The following table sets forth a comparison of the components of our consolidated statements of income for the three months ended January 31, 2010 as compared with the three months ended January 31, 2009.

Income Statement Components

		Three Months Ended January 31
In thousands, except per share amounts		2010				2009				Variance				Percent Change
Operating Revenues		$	673,736			$	779,644			$	(105,908	)			(13.6	)%
Cost of Gas			450,794				558,961				(108,167	)			(19.4	)%
Margin			222,942				220,683				2,259				1.0	%
Operations and Maintenance			52,039				50,725				1,314				2.6	%
Depreciation			24,355				24,142				213				0.9	%
General Taxes			8,585				8,737				(152	)			(1.7	)%
Income Taxes			50,162				48,948				1,214				2.5	%
Total Operating Expenses			135,141				132,552				2,589				2.0	%
Operating Income			87,801				88,131				(330	)			(0.4	)%
Other Income (Expense), net of tax			37,252				5,758				31,494				547.0	%
Utility Interest Charges			11,304				13,013				(1,709	)			(13.1	)%
Net Income		$	113,749			$	80,876			$	32,873				40.6	%
Average Shares of Common Stock:
Basic			73,173				73,319				(146	)			(0.2	)%
Diluted			73,545				73,646				(101	)			(0.1	)%
Earnings Per Share of Common Stock:
Basic		$	1.55			$	1.10			$	0.45				40.9	%
Diluted		$	1.55			$	1.10			$	0.45				40.9	%

Key statistics are shown in the table below for the three months ended January 31, 2010 and 2009.

Gas Deliveries, Customers, Weather Statistics and Number of Employees

		Three Months Ended
		January 31												Percent
		2010				2009				Variance				Change
Deliveries in Dekatherms (in thousands):
Sales Volumes			55,367				52,376				2,991				5.7	%
Transportation Volumes			29,355				24,155				5,200				21.5	%
Throughput			84,722				76,531				8,191				10.7	%
Secondary Market Volumes			10,523				13,392				(2,869	)			(21.4	)%
Customers Billed (at period end)			970,973				965,402				5,571				0.6	%
Gross Customer Additions			3,066				3,913				(847	)			(21.6	)%
Degree Days
Actual			2,050				1,944				106				5.5	%
Normal			1,858				1,856				2				0.1	%
Percent colder than normal			10.3	%			4.7	%			n/a				n/a
Number of Employees (at period end)			1,809				1,823				(14	)			(0.8	)%

Operating Revenues

Operating revenues decreased $105.9 million for the three months ended January 31, 2010 compared with the same period in 2009 primarily due to the following decreases:

	•		$83.1 million primarily from lower prices for gas passed through to sales customers.
	•		$33 million from secondary market transactions due to decreased activity and gas costs. Secondary market transactions consist of off-system sales and capacity release arrangements and are a part of our regulatory gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.
	•		$8.6 million from the margin decoupling mechanism.

These decreases were partially offset by an increase of $20.9 million of commodity gas costs from increased volume deliveries to sales customers.

Cost of Gas

Cost of gas decreased $108.2 million for the three months ended January 31, 2010 compared with the same period in 2009 primarily due to the following decreases:

	•		$96.6 million primarily from lower prices for gas passed through to sales customers.
	•		$32.3 million from commodity gas costs in secondary market transactions due to decreased activity and gas costs.

These decreases were partially offset by an increase of $20.9 million of commodity gas costs from increased volume deliveries to sales customers.

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 increased $2.3 million for the three months ended January 31, 2010 compared with the same period in 2009, primarily due to gas cost adjustments, residential customer growth and improved volumes from industrial customers.

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 impact of the flow through of wholesale commodity costs, which accounts for 49% of revenues for the three months ended January 31, 2010, and transportation and storage costs, which account for 4%.

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 impacted also by certain regulatory mechanisms as defined elsewhere in this document and in our Form 10-K for the year ended October 31, 2009. These include the WNA in Tennessee and South

Carolina, the Natural Gas Rate Stabilization Act in South Carolina, secondary market activity in North Carolina and South Carolina, the TIP in Tennessee, the margin decoupling mechanism in North Carolina and negotiated loss treatment and the collection 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 $1.3 million for the three months ended January 31, 2010 compared with the same period in 2009 due to $3.5 million in payroll expense primarily from an increase in long-term incentive plan accruals priced at a higher current stock price and on a higher number of shares in the plans. This increase was partially offset by a decrease of $1.6 million in employee benefits primarily due to the regulatory deferral of the Tennessee portion of the pension plan funding which occurred in the current period compared to the third quarter in 2009, partially offset by an increase in group insurance expense from higher claims and an increase in pension expense from a lower discount rate used to determine periodic benefit cost.

Other Income (Expense)

Other Income (Expense) is comprised of income from equity method investments, gain on sale of interest in equity method investment, non-operating income, non-operating expense and income taxes related to these items. Non-operating income includes non-regulated merchandising and service work, 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, 2010 as compared with the same period in 2009 was in income from equity method investments and the gain on the sale of half of our ownership interest in SouthStar. All other changes were insignificant for the period.

On January 1, 2010, we sold 50% of our 30% membership interest in SouthStar to the other member of the joint venture and retained a 15% earnings and membership interest after the sale. The pre-tax gain on the sale was $49.7 million. The after-tax gain was $30.2 million, or $.41 per diluted earnings per share.

Income from equity method investments increased $2 million for the three months ended January 31, 2010 as compared with the same period in 2009 primarily due to a $2.4 million increase in earnings from SouthStar primarily due to favorable changes in the lower of cost or market storage inventory adjustment and the retail pricing plan mix chosen by SouthStar customers.

Utility Interest Charges

Utility interest charges decreased $1.7 million for the three months ended January 31, 2010 compared with the same period in 2009 primarily due to the following:

	•		$1 million decrease in interest on short-term debt primarily due to the average interest rate of the current period being approximately 100 basis points lower than the prior year period combined with lower levels of borrowing in the current period.
	•		$.6 million decrease in interest on long-term debt primarily due to lower amounts outstanding.

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. Even though we have been operating in tighter credit markets for over a year, we believe that these sources, including amounts available to us under our existing syndicated five-year revolving credit facility, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions and dividend payments.

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 resulting from such factors as 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 in storage and the collection of amounts billed to customers during the winter heating season (November through March). Cash requirements generally increase during the third and fourth quarters due to increases in natural gas purchases for storage, seasonal construction activity and decreases in receipts from customers.

During the winter heating season, our 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 volatility in the price of natural gas, which is a function of market fluctuations in the price 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 and in amounts due to/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 economic recession, we may incur additional bad debt expense during the winter heating season, 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, will significantly mitigate the impact these factors may have on our results of operations.

Net cash provided by operating activities was $50.9 million and $20.8 million for the three months ended January 31, 2010 and 2009, respectively. Net cash provided by operating activities reflects a $32.9 million increase in net income for 2010 compared with 2009, which includes an after-tax gain of $30.2 million on the sale of half of our interest in SouthStar as discussed in Results of Operations above.

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 $280.6 million in the current period

primarily due to the winter consumption of gas. Weather during the current period was 5.5% colder than the same prior year period. Volumes sold to residential and commercial customers increased 3 million dekatherms primarily due to the colder weather and customer growth, partially offset by lower gas costs in 2010 as compared with 2009. Total throughput increased 8.2 million dekatherms as compared with the same prior period.

	•		Net amounts due from customers decreased $95.8 million primarily due to decreases for gas cost amounts deferred and the impact of the decrease in amounts recorded under the margin decoupling mechanism, partially offset by realized and unrealized losses on hedging activities.
	•		Gas in storage increased $.5 million in the current period primarily due to prepaid inventories becoming available for use which increased the levels of gas in storage, partially offset by volumes of gas in storage at a lower average cost than the prior year.
	•		Prepaid gas costs decreased $40.2 million in the current period primarily due to gas becoming 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 winter heating season.
	•		Trade accounts payable increased $92.1 million in the current period primarily due to gas purchases to meet 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 credits to customers of $4.6 million and $1.7 million in the three months ended January 31, 2010 and 2009, 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 reduced margin by $15.5 million and $6.9 million in the three months ended January 31, 2010 and 2009, 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 provided by (used in) investing activities was $23.2 million and ($30.4) million for the three months ended January 31, 2010 and 2009, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the three months ended January 31, 2010 were $33.9 million as compared to $29.9 million in the same prior period primarily due to the construction of the Nashville operations center.

We have a substantial capital expansion program for construction of distribution facilities, purchase of equipment and other general improvements. This program primarily supports our system infrastructure and the growth in our customer base. Gross utility construction expenditures totaling $195.4 million are budgeted for 2010. The $195.4 million includes $46.3 million in capital expenditures, largely deferred from 2009, for pipeline infrastructure to serve two gas-fired power generation projects in North Carolina. We are not contractually obligated to expend capital until the work is completed. Even though we are seeing a slower pace of core residential and commercial customer growth in our service territory due to the downturn in the housing market and other economic factors, significant utility construction expenditures are expected to continue to meet long-term growth and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

We have deferred the development and construction of our previously announced LNG peak storage facility in Robeson County, North Carolina based on our current growth projections, which indicate that we may need to resume development of the project in 2011 to prepare for construction beginning in 2012 in order to provide service in 2015. This LNG peak storage facility, with an intended capacity to store approximately 1.25 billion cubic feet of natural gas for use during times of peak demand, is part of our plan to provide safe, reliable gas distribution service to our growing customer base and manage our seasonal demand. We intend to design, construct, own and operate this facility as a regulated utility project. Preliminary estimates place the cost of the facility in the $300 million to $350 million range. With the uncertain economic outlook, we will monitor customer growth trends in our markets and plan for the development of the Robeson project when needed to meet future customer requirements.

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, which is subject to NCUC approval, calls for us to construct 38 miles of 20-inch transmission pipeline along with additional compression facilities to provide natural gas delivery service to the plant by July 2012. Our investment in the pipeline and compression facilities is estimated at $85 million and is supported by a long-term service agreement. We anticipate making the capital expenditures related to the project during 2011 and 2012. To provide the additional delivery service, we have executed an agreement with Cardinal to expand our firm capacity requirement by 149,000 dekatherms per day to serve this facility. This will require Cardinal to spend as much as $39.2 million to expand its system. As a 22% equity venture partner of Cardinal, we will invest as much as $8.7 million in Cardinal’s system expansion.

On January 1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and retained a 15% earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million from GNGC. For further information regarding the sale, see Note 8 to the consolidated financial statements in this Form 10-Q.

Cash Flows from Financing Activities. Net cash provided by (used in) financing activities was ($65.5) million and $25.6 million for the three months ended January 31, 2010 and 2009, respectively. Funds are primarily provided from bank borrowings and the issuance of common stock through dividend reinvestment and stock purchase and employee stock purchase plans, net of purchases under the common stock repurchase program. We may sell common stock and long-term debt when market and other conditions favor such long-term financing. Funds are primarily used to pay down outstanding short-term bank borrowings, to repurchase common stock under the common stock repurchase program and to pay quarterly dividends on our common stock. As of January 31, 2010, our current assets were $633.7 million and our current liabilities were $669.6 million primarily due to seasonal requirements as discussed above.

As of January 31, 2010, we had committed lines of credit of $450 million with the ability to expand up to $600 million under our syndicated five-year revolving credit facility that expires April 2011 to meet working capital needs. We pay an annual fee of $35,000 plus six basis points for any unused amount up to $450 million. Outstanding short-term borrowings decreased from $306 million as of October 31, 2009 to $293 million as of January 31, 2010 primarily due to lower commodity gas costs and lower interest payments for short-term debt. During the three months ended January 31, 2010, short-term borrowings ranged from $236.5 million to $342.5 million, and interest rates ranged from .48% to .5% (weighted average of .49%).

As of January 31, 2010, we had available letters of credit of $5 million under our syndicated five-year revolving credit facility, of which $2.7 million was issued and outstanding. The letters of credit are used to guarantee claims from self-insurance under our general and automobile liability policies. As of January 31, 2010, unused lines of credit available under our syndicated five-year revolving credit facility, including the issuance of the letters of credit, totaled $154.3 million.

The level of short-term bank borrowings can vary significantly due to changes in the wholesale prices of natural gas, the level of purchases of natural gas supplies for storage and hedging transactions 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.

At this time, we do not anticipate issuing long-term debt in fiscal 2010, but intend to issue $150 — $175 million in long-term debt in fiscal 2011 for general operating purposes. The timing of this issuance has not yet been determined. We will continue to monitor customer growth trends in our markets along with the economic recovery of our service area for the timing of any infrastructure investments that would require the need for additional long-term debt.

During the three months ended January 31, 2010, we issued $4.6 million of common stock through dividend reinvestment and stock purchase plans. 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 of this Form 10-Q. Upon repurchase, such shares will be cancelled and become authorized shares available for issuance. During the quarter, we repurchased 1.4 million shares for $36.9 million under our Common Stock Open Market Purchase Program, leaving 4.9 million shares available for repurchase under the program. In February 2010, we

repurchased an additional .4 million shares for $10.4 million under the program.

We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of January 31, 2010, our retained earnings were not restricted. On February 26, 2010, the Board of Directors declared a quarterly dividend on common stock of $.28 per share, payable April 15, 2010 to shareholders of record at the close of business on March 25, 2010.

Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. As of January 31, 2010, our capitalization, including current maturities of long-term debt, consisted of 44% in long-term debt and 56% 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, 2010 and 2009, and October 31, 2009, are summarized in the table below.

		January 31								October 31								January 31
In thousands		2010				Percentage				2009				Percentage				2009				Percentage
Short-term debt		$	293,000				14	%		$	306,000				15	%		$	448,000				20	%
Current portion of long-term debt			60,000				3	%			60,000				3	%			30,000				1	%
Long-term debt			732,313				35	%			732,512				36	%			793,867				36	%
Total debt			1,085,313				52	%			1,098,512				54	%			1,271,867				57	%
Common stockholders’ equity			992,605				48	%			927,948				46	%			952,275				43	%
Total capitalization (including short-term debt)		$	2,077,918				100	%		$	2,026,460				100	%		$	2,224,142				100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flows relative to outstanding debt, capital expenditures, operating cash flow coverage of interest and pension liabilities and funding status. Rating agencies also consider qualitative factors, such as the consistency of our earnings over time, the quality of management, corporate governance and business strategy, the risks associated with our utility and non-utility businesses and the regulatory commissions that establish rates in the states where we operate.

As of January 31, 2010, all of our long-term debt was unsecured. Our long-term debt is rated “A” by S&P and “A3” by Moody’s Investors Service. Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook. 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 our debt agreements. As of January 31, 2010, 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, 2010, there were no material changes to our estimated future contractual obligations that were disclosed in our Form 10-K for the year ended October 31, 2009, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements other than operating leases, letters of credit and the credit extended by our counterparty in OTC derivative contracts. The letters of credit and operating leases were discussed in Note 4 and Note 7, respectively, to the consolidated financial statements in our Form 10-K for the year ended October 31, 2009. The credit extended by our counterparty in OTC derivative contracts is discussed in Note 9 to the consolidated financial statements in this Form 10-Q.

Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont, has entered into a guaranty in the normal course of business. The guaranty involves some levels of performance and credit risk that are not included on our consolidated balance sheets. We have recorded an estimated liability of $1.2 million as of January 31, 2010 and October 31, 2009. The possibility of having to perform on the guaranty is largely dependent upon the future operations of Hardy Storage, third parties or the occurrence of certain future events. For further information on this guaranty, see Note 8 to the consolidated financial statements in this Form 10-Q.

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, 2009, 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, 2009.

Recent Accounting Pronouncements

          Accounting Pronouncements

In December 2008, the Financial Accounting Standards Board (FASB) issued new accounting guidance for employers’ disclosures about plan assets of defined benefit pension and other postretirement plans. This guidance requires that employers provide more transparency about the assets held by retirement plans or other postretirement employee benefit plans, the concentration of risk in those plans and information about the fair value measurements of plan assets similar to the disclosures required by current fair value guidance. The guidance is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since only additional disclosures about plan assets of defined benefit pension and other postretirement plans are required, it is not expected to have a material impact on our financial position, results of operations or cash flows. We will adopt the guidance on benefit plan assets during our fiscal year ending October 31, 2010.

In January 2010, the FASB issued accounting guidance to require new fair value measurement and classification disclosures, and to clarify existing disclosures. The guidance requires disclosures about transfers into and out of Levels 1 and 2 of the fair value hierarchy, and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. It also clarifies the existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value, and amends guidance on employers’ disclosures about postretirement benefit plan assets to require disclosures be provided by asset class instead of major categories of assets. The guidance is effective for interim and fiscal periods beginning after December 15, 2009, with the exception that the Level 3 activity disclosure requirement will be effective for interim periods for fiscal years beginning after December 15, 2010. Since the guidance addresses only disclosure related to fair value measurements, adoption of the guidance during our fiscal second quarter beginning February 1, 2010 did not have a material impact on our financial position, results of operations or cash flows. We will adopt the guidance for Level 3 disclosure for the first quarter of our fiscal year ending October 31, 2012.

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 market risk and credit risk in accordance with defined policies and procedures under an Enterprise Risk Management Policy and with the direction of the EPRMC. 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.

We hold all financial instruments discussed below for purposes other than trading.

Credit Risk

We enter into contracts with third parties to buy and sell natural gas. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. In situations where our counterparties do not have investment grade credit ratings, our policy requires credit enhancements that include letters of credit or parental guarantees. In either circumstance, the policy specifies limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our requirements accordingly.

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

We have mitigated exposure to the risk of non-payment of utility bills by customers. In North Carolina and South Carolina, gas costs related to uncollectible accounts are recovered through PGA procedures. In Tennessee, the gas cost portion of net write-offs for a fiscal year that exceed the gas cost portion included in base rates is recovered through PGA procedures. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from those customers that do not satisfy our predetermined credit standards. Significant increases in the price of natural gas can also slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal accounts receivable.

Interest Rate Risk

We are exposed to interest rate risk as a result of changes in interest rates on short-term debt. As of January 31, 2010, all of our long-term debt was issued at fixed rates, and therefore not subject to interest rate risk.

We have short-term borrowing arrangements to provide working capital and general corporate liquidity. The level of borrowings under such arrangements varies from period to period depending upon many factors, including the cost of wholesale natural gas and our gas supply hedging programs, our investments in capital projects, the level and expense of our storage inventory and the collection of receivables. Future short-term interest expense and payments will be impacted by both short-term interest rates and borrowing levels.

As of January 31, 2010, we had $293 million of short-term debt outstanding under our syndicated revolving credit facility at an interest rate of .48%. 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 $.7 million during the three months ended January 31, 2010.

Commodity Price Risk

We have mitigated the cash flow risk resulting from commodity purchase contracts under our regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner. As such, we face regulatory recovery risk associated with these costs. With regulatory commission approval, we revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost of gas, including costs associated with our hedging programs under the recovery mechanism allowed by each of our state regulators. Under our PGA procedures, differences between gas costs incurred and gas costs billed to customers are deferred and any under-recoveries are included in “Amounts due from customers” or any over-recoveries are included in “Amounts due to customers” in our consolidated balance sheets for collection or refund over subsequent periods. When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge that we must refund to our customers.

We manage our gas supply costs through a portfolio of short- and long-term procurement and storage contracts with various suppliers. We actively manage our supply portfolio to balance sales and delivery obligations. We inject natural gas into storage during the summer months and withdraw the gas during the winter heating season. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX) exchange-traded instruments and have used over-the-counter instruments of various durations for the forward purchase of a portion of our natural gas requirements, subject to regulatory review and approval.

Our gas purchasing practices are subject to regulatory reviews in all three states in which we operate. Costs have never been disallowed on the basis of prudence in any jurisdiction.

Weather Risk

We are exposed to weather risk in our regulated utility segment in South Carolina and Tennessee where revenues are collected from volumetric rates without a margin decoupling mechanism. Our rates are designed based on an assumption of normal weather. In these states, this risk is mitigated by WNA mechanisms that are designed to offset the impact of colder-than-normal or warmer-than-normal weather in our residential and commercial markets. In North Carolina, we manage our weather risk through a margin decoupling mechanism that allows us to recover our approved margin from residential and commercial customers independent of volumes sold.

Additional information concerning market risk is set forth in “Financial Condition and Liquidity” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 2 of this Form 10-Q.

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 2010 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 litigation in the normal course of business.

Item 1A. Risk Factors

During the three months ended January 31, 2010, there were no material changes to our risk factors that were disclosed in our Form 10-K for the year ended October 31, 2009.

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

     a) Sale of Unregistered Equity Securities.

     On November 16, 2009, we discovered that we had inadvertently sold more shares under our dividend reinvestment and stock purchase plan (DRIP) than were registered with the Securities and Exchange Commission (SEC) and authorized by our Board of Directors for issuance under the DRIP. We also discovered that the registration statement we believed had registered shares issued under the DRIP between December 1, 2008 and November 16, 2009 had expired for some of those shares. As a result, from November 1, 2009 through November 16, 2009, we sold 15,029 shares under the DRIP that may not have been registered at the time of issuance for proceeds of $347,000. Our Board of Directors ratified the authorization and issuance of the excess number of shares, and on November 20, 2009, we filed a registration statement covering the sale and issuance of an additional 2.75 million shares of our common stock under the DRIP. On February 8, 2010, we filed a registration statement which offers to rescind the purchase of the shares sold under the DRIP between

December 1, 2008 and November 16, 2009 and registers all previously unregistered shares issued under the DRIP during that period. We have reported these events and are cooperating with the relevant regulatory authorities, including the SEC and the North Carolina Utilities Commission. The sale of unregistered securities could subject us to enforcement actions or penalties and fines by these regulatory authorities. While we are unable to predict the full consequences of these events, we do not expect any rescissions or regulatory actions, if any, to have a material adverse effect on us.

     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, 2010.

										Total Number of				Maximum Number
		Total Number								Shares Purchased				of Shares that May
		of Shares				Average Price				as Part of Publicly				Yet be Purchased
Period		Purchased				Paid Per Share				Announced Program				Under the Program *
Beginning of the period															6,310,074
11/01/09 - 11/30/09			—			$	—				—				6,310,074
12/01/09 - 12/31/09			—			$	—				—				6,310,074
01/01/10 - 01/31/10			1,397,900			$	26.38				1,397,900				4,912,174
Total			1,397,900			$	26.38				1,397,900

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, 2010, 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		Form of Performance Unit Award Agreement.
10.2		Instrument of Amendment for Piedmont Natural Gas Company, Inc. 401(k) Plan, dated as of December 17, 2009.
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.

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.
Form 10-Q
For the Quarter Ended January 31, 2010

Exhibits

Compensatory Contracts:

	10.1		Form of Performance Unit Award Agreement
	10.2		Instrument of Amendment for Piedmont Natural Gas Company, Inc. 401(k) Plan, dated as of December 17, 2009
	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