Edgar Filing: PIEDMONT NATURAL GAS CO INC

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended July 31, 2010


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

For the transition period from to

Commission File Number 1-6196

Piedmont Natural Gas Company, Inc.

(Exact name of registrant as specified in its charter)


North Carolina		56-0556998

(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

4720 Piedmont Row Drive, Charlotte, North Carolina		28210

(Address of principal executive offices)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes 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). þ 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):


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 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 August 31, 2010

Common Stock, no par value		72,113,862

Piedmont Natural Gas Company, Inc.

Form 10-Q

for

July 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		41
Item 4.	Controls and Procedures		43

Part II.	Other Information

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

	Signatures		47
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

Part I. Financial Information

Item 1. Financial Statements

Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Balance Sheets (Unaudited)
(In thousands)


	July 31,		October 31,
	2010		2009
ASSETS
Utility Plant:
Utility plant in service	$	3,161,733	$	3,071,742
Less accumulated depreciation		914,944		862,079

Utility plant in service, net		2,246,789		2,209,663
Construction work in progress		146,175		87,978
Plant held for future use		6,751		6,751

Total utility plant, net		2,399,715		2,304,392


Other Physical Property, at cost (net of accumulated depreciation of $2,098 in 2010 and $2,497 in 2009)		627		719


Current Assets:
Cash and cash equivalents		5,192		7,558
Trade accounts receivable (less allowance for doubtful accounts of $2,873 in 2010 and $990 in 2009)		80,973		70,979
Income taxes receivable		—		44,413
Other receivables		4,140		4,712
Unbilled utility revenues		11,360		33,925
Inventories:
Gas in storage		99,848		103,584
Materials, supplies and merchandise		5,090		5,262
Gas purchase derivative assets, at fair value		2,891		2,559
Amounts due from customers		36,105		196,130
Prepayments		29,857		43,930
Other current assets		96		96

Total current assets		275,552		513,148


Noncurrent Assets:
Equity method investments in non-utility activities		89,460		104,430
Goodwill		48,852		48,852
Marketable securities, at fair value		938		441
Overfunded postretirement asset		10,803		—
Regulatory asset for postretirement benefits		76,355		76,905
Unamortized debt expense		8,688		9,177
Regulatory cost of removal asset		17,431		16,293
Other noncurrent assets		47,027		44,462

Total noncurrent assets		299,554		300,560


Total	$	2,975,448	$	3,118,819

See notes to consolidated financial statements.

Piedmont Natural Gas Company, Inc. and Subsidiaries
Consolidated Balance Sheets (Unaudited)
(In thousands)


	July 31,			October 31,
	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: 72,098 in 2010 and 73,266 in 2009		440,468			471,569
Retained earnings		549,132			458,826
Accumulated other comprehensive loss		(785	)		(2,447	)

Total stockholders’ equity		988,815			927,948
Long-term debt		732,010			732,512

Total capitalization		1,720,825			1,660,460


Current Liabilities:
Current maturities of long-term debt		60,000			60,000
Short-term debt		122,000			306,000
Trade accounts payable		72,690			67,010
Other accounts payable		25,531			48,431
Income taxes accrued		5,029			—
Accrued interest		12,099			21,294
Customers’ deposits		25,574			25,202
Deferred income taxes		5,296			14,138
General taxes accrued		14,724			19,993
Gas purchase derivative liabilities, at fair value		4,694			30,603
Other current liabilities		8,362			7,540

Total current liabilities		355,999			600,211


Noncurrent Liabilities:
Deferred income taxes		409,115			377,562
Unamortized federal investment tax credits		2,151			2,422
Accumulated provision for postretirement benefits		21,366			31,641
Cost of removal obligations		430,839			408,955
Other noncurrent liabilities		35,153			37,568

Total noncurrent liabilities		898,624			858,148


Commitments and Contingencies (Note 12)


Total	$	2,975,448		$	3,118,819

See notes to consolidated financial statements.

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


	Three Months Ended						Nine Months Ended
	July 31						July 31
	2010			2009			2010			2009

Operating Revenues	$	211,603		$	180,201		$	1,358,185		$	1,415,276
Cost of Gas		133,706			99,362			888,667			943,802


Margin		77,897			80,839			469,518			471,474


Operating Expenses:
Operations and maintenance		55,295			50,124			164,838			154,200
Depreciation		24,691			24,488			73,529			72,937
General taxes		8,753			8,841			26,096			26,235
Utility income taxes		(7,371	)		(4,199	)		68,499			73,035


Total operating expenses		81,368			79,254			332,962			326,407


Operating Income (Loss)		(3,471	)		1,585			136,556			145,067


Other Income (Expense):
Income from equity method investments		2,607			3,828			27,748			31,449
Gain on sale of interest in equity method investment		—			—			49,674			—
Non-operating income		(31	)		(51	)		283			(149	)
Non-operating expense		(227	)		(749	)		(1,603	)		(1,955	)
Income taxes		(558	)		(866	)		(29,449	)		(11,339	)


Total other income (expense)		1,791			2,162			46,653			18,006


Utility Interest Charges:
Interest on long-term debt		13,280			13,829			39,805			41,500
Allowance for borrowed funds used during construction		(6,360	)		(483	)		(7,662	)		(1,710	)
Other		918			(2,299	)		9			(3,818	)

Total utility interest charges		7,838			11,047			32,152			35,972


Net Income (Loss)	$	(9,518	)	$	(7,300	)	$	151,057		$	127,101


Average Shares of Common Stock:
Basic		71,968			72,983			72,315			73,180
Diluted		71,968			72,983			72,668			73,476

Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.13	)	$	(0.10	)	$	2.09		$	1.74
Diluted	$	(0.13	)	$	(0.10	)	$	2.08		$	1.73

Cash Dividends Per Share of Common Stock	$	0.28		$	0.27		$	0.83		$	0.80

See notes to consolidated financial statements.

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


	Nine Months Ended
	July 31
	2010			2009

Cash Flows from Operating Activities:
Net income	$	151,057		$	127,101
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		76,867			76,827
Amortization of investment tax credits		(271	)		(248	)
Allowance for doubtful accounts		1,883			883
Net gain on sale of interest in equity method investment, net of tax		(30,222	)		—
Gain on sale of property		(158	)		(418	)
Earnings from equity method investments		(27,748	)		(31,449	)
Distributions of earnings from equity method investments		29,000			22,750
Deferred income taxes		2,189			67,083
Stock-based compensation expense		—			252
Changes in assets and liabilities:
Gas purchase derivatives, at fair value		(26,241	)		38,102
Receivables		10,953			42,376
Inventories		3,908			83,774
Amounts due from customers		160,025			(27,225	)
Settlement of legal asset retirement obligations		(634	)		(1,127	)
Overfunded postretirement asset		(10,803	)		(21,837	)
Regulatory asset for postretirement benefits		550			(1,147	)
Other assets		55,147			12,146
Accounts payable		(18,294	)		(56,141	)
Provision for postretirement benefits		(10,275	)		872
Other liabilities		(7,309	)		(26,480	)

Net cash provided by operating activities		359,624			306,094


Cash Flows from Investing Activities:
Utility construction expenditures		(141,677	)		(83,208	)
Allowance for funds used during construction		(7,662	)		(1,710	)
Contributions to equity method investments		—			(862	)
Distributions of capital from equity method investments		7,389			315
Proceeds from sale of interest in equity method investment		57,500			—
Proceeds from sale of property		1,320			644
Investments in marketable securities		(484	)		(373	)
Other		(38	)		1,258

Net cash used in investing activities		(83,652	)		(83,936	)

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


	Nine Months Ended
	July 31
	2010			2009
Cash Flows from Financing Activities:
Borrowings under short-term debt	$	816,500		$	877,500
Repayments under short-term debt		(1,000,500	)		(1,026,500	)
Retirement of long-term debt		(502	)		(1,446	)
Issuance of common stock through dividend reinvestment and employee stock plans		14,283			11,048
Repurchases of common stock		(47,295	)		(17,857	)
Dividends paid		(60,056	)		(58,624	)
Other		(768	)		(51	)

Net cash used in financing activities		(278,338	)		(215,930	)


Net Increase (Decrease) in Cash and Cash Equivalents		(2,366	)		6,228
Cash and Cash Equivalents at Beginning of Period		7,558			6,991

Cash and Cash Equivalents at End of Period	$	5,192		$	13,219


Noncash Investing and Financing Activities:
Accrued construction expenditures	$	1,074		$	2,449
Guaranty		1,234			—

See notes to consolidated financial statements.

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


	Three Months Ended						Nine Months Ended
	July 31						July 31
	2010			2009			2010			2009

Net Income (Loss)	$	(9,518	)	$	(7,300	)	$	151,057		$	127,101

Other Comprehensive Income:
Unrealized gain (loss) from hedging activities of equity method investments, net of tax of $94 and ($257) for the three months ended July 31, 2010 and 2009, respectively, and ($77) and ($3,626) for the nine months ended July 31, 2010 and 2009, respectively		148			(400	)		(117	)		(5,629	)
Reclassification adjustment from hedging activities of equity method investments included in net income, net of tax of $263 and $1,253 for the three months ended July 31, 2010 and 2009, respectively, and $1,147 and $997 for the nine months ended July 31, 2010 and 2009, respectively		407			1,946			1,779			1,546


Total Comprehensive Income (Loss)	$	(8,963	)	$	(5,754	)	$	152,719		$	123,018

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 July 31, 2010 and October 31, 2009, the results of operations for the three months and nine months ended July 31, 2010 and 2009, and cash flows for the nine months ended July 31, 2010 and 2009. Our business is seasonal in nature. The results of operations for the three months and nine months ended July 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 nine months ended July 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 July 31, 2010 and October 31, 2009 are as follows.


	July 31,		October 31,
In thousands	2010		2009

Regulatory assets	$	181,048	$	337,543
Regulatory liabilities		429,920		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 7 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, these disclosures will not have a material impact on our financial position, results of operations or cash flows. These disclosures will be in our Form 10-K for our fiscal year ending October 31, 2010.

In June 2009, the FASB amended accounting guidance to eliminate the quantitative approach that entities use to determine whether an entity has a controlling financial interest in a variable interest entity (VIE) and to require that the entity with a variable interest in a VIE qualitatively assess whether it has a controlling financial interest, and if so, determine whether it is the primary beneficiary. The guidance requires companies to continually evaluate the VIE for consolidation, rather than performing the assessment only when specific events occur. It also requires enhanced disclosures to provide more information about the entity’s involvement with the VIE. The guidance is effective for fiscal periods beginning after November 15, 2009. We do not expect this guidance on consolidation of variable interest entities to have a material impact on our financial position, results of operations or cash flows. We will adopt the guidance during the first quarter of our fiscal year ending October 31, 2011.

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.

In July 2010, the FASB issued accounting guidance to improve disclosures related to an entity’s allowance for credit losses and the credit quality of its financing receivables, excluding short-term trade accounts receivable or receivables measured at fair value or cost if lower than fair value. The guidance requires additional disclosures about financing receivables such as the credit quality indicators, the aging of past due financing receivables, the nature and extent of troubled debt restructurings, any modifications of financing receivables as troubled debt restructurings and the related effect on the allowance for credit losses and any significant purchases or sales of financing receivables during the reporting period. The guidance is effective for end of reporting period disclosures for the reporting period ending on or after December 15, 2010. The disclosures about activity that occurred during a reporting period are effective for interim and annual periods beginning on or after December 15, 2010. Comparative disclosure for earlier reporting periods is encouraged, but not required. We will adopt the guidance for the end of period disclosures as of January 31, 2011, and for the disclosures related to activity in the reporting period during our fiscal second quarter beginning February 1, 2011. Since the guidance addresses only disclosures related to credit quality of financing receivables and the allowance for credit losses, we do not expect the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows.

2. Regulatory Matters

On July 29, 2010, 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, 2010. A hearing has been scheduled for October 5, 2010. We are unable to predict the outcome of this proceeding at this time.

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. On May 20, 2010, the PSCSC approved the energy efficiency programs on a three-year experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipment and weatherization assistance for low-income residential customers.

On August 25, 2010, the PSCSC approved our purchased gas adjustments and found our gas purchasing policies to be prudent for the period covering the twelve months ended March 31, 2010.

On June 15, 2010, we filed with the PSCSC a cost and revenue study as permitted by the Natural Gas Rate Stabilization Act requesting a change in rates from those approved by the PSCSC in an order dated October 13, 2009. On September 1, 2010, we and the Office of Regulatory Staff filed a settlement agreement with the PSCSC addressing our proposed rate changes. The settlement, if approved, will result in a slight increase in margin based on a return on equity of 11.3%, effective November 1, 2010. The settlement is pending approval by the PSCSC. 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. On July 20, 2010, in coordination with the TRA Audit Staff, we withdrew the annual

report filed on July 1, 2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008. On August 23, 2010, the TRA approved the findings of the TRA Audit Staff report on this matter, which were in agreement with our report.

On February 26, 2010, we filed a petition with the TRA to adjust the applicable rate for the collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as of May 31, 2009. On April 12, 2010, the TRA passed a motion approving a new Nashville franchise fee rate designed to recover only the net under-collections that have accrued since June 1, 2005, which would deny recovery of $1.5 million for us. Once the TRA issues its order on this matter, we intend to seek their reconsideration. We are unable to predict the outcome of this proceeding at this time. However, we do not believe this matter will have a material effect on our financial position, results of operations or cash flows.

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 and nine months ended July 31, 2010 and 2009 is presented below.


	Three Months						Nine Months
In thousands except per share amounts	2010			2009			2010		2009

Net Income (Loss)	$	(9,518	)	$	(7,300	)	$	151,057	$	127,101


Average shares of common stock outstanding for basic earnings per share		71,968			72,983			72,315		73,180
Contingently issuable shares under incentive compensation plans *		—			—			353		296

Average shares of dilutive stock		71,968			72,983			72,668		73,476


Earnings (Loss) Per Share of Common Stock:
Basic	$	(0.13	)	$	(0.10	)	$	2.09	$	1.74
Diluted	$	(0.13	)	$	(0.10	)	$	2.08	$	1.73


*		For the three months ended July 31, 2010 and 2009, the inclusion of 339 and 276 contingently issuable shares, respectively, would have been antidilutive.

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

The money market investments in the trust approximate fair value due to the short period of time to maturity. The fair values of the mutual fund investments are based on the quoted market value of the fund, or the net asset

value of the shares, as traded on the exchanges. The composition of these securities as of July 31, 2010 and October 31, 2009 is as follows.


	July 31, 2010				October 31, 2009
			Fair				Fair
In thousands	Cost		Value		Cost		Value

Money markets	$	259	$	259	$	169	$	169
Mutual funds		599		679		205		272

Total trading securities	$	858	$	938	$	374	$	441

5. Employee Benefit Plans

Components of the net periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended July 31, 2010 and 2009 are presented below.


	Qualified Pension						Nonqualified Pension				Other Benefits
In thousands	2010			2009			2010		2009		2010			2009
Service cost	$	1,852		$	1,325		$	10	$	6	$	334		$	(56	)
Interest cost		2,473			2,929			61		81		476			541
Expected return on plan assets		(4,530	)		(4,290	)		—		—		(345	)		25
Amortization of transition obligation		—			—			—		—		167			167
Amortization of prior service (credit) cost		(548	)		(549	)		5		5		—			—
Amortization of actuarial loss		399			—			2		—		59			—

Total	$	(354	)	$	(585	)	$	78	$	92	$	691		$	677

Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the nine months ended July 31, 2010 and 2009 are presented below.


	Qualified Pension						Nonqualified Pension					Other Benefits
In thousands	2010			2009			2010		2009			2010			2009
Service cost	$	6,052		$	4,300		$	29	$	19		$	1,003		$	664
Interest cost		8,173			8,430			182		244			1,429			1,700
Expected return on plan assets		(14,080	)		(12,567	)		—		—			(1,036	)		(827	)
Amortization of transition obligation		—			—			—		—			500			500
Amortization of prior service (credit) cost		(1,648	)		(1,648	)		15		15			—			—
Amortization of actuarial loss (gain)		1,499			—			7		(15	)		178			—

Total	$	(4	)	$	(1,485	)	$	233	$	263		$	2,074		$	2,037

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	$	484
OPEB plan		3,700

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 nine months ended July 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 July 31, 2010, we have a liability of $1.1 million for these plans.

See Note 4 and Note 8 to the consolidated financial statements of this Form 10-Q for information on the investments in marketable securities that are held in the trust.

6. 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 (Loss)” in the consolidated statements of operations. Operations of the non-utility activities segment are included in the consolidated statements of operations 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 and nine months ended July 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	$	211,603		$	180,201		$	—		$	—		$	211,603		$	180,201
Margin		77,897			80,839			—			—			77,897			80,839
Operations and maintenance expenses		55,295			50,124			24			198			55,319			50,322
Gain from sale of interest in equity method investment		—			—			—			—			—			—
Income from equity method investments		—			—			2,607			3,828			2,607			3,828
Operating loss before income taxes		(10,842	)		(2,614	)		(303	)		(267	)		(11,145	)		(2,881	)
Income (loss) before income taxes		(18,719	)		(14,206	)		2,388			3,573			(16,331	)		(10,633	)

Nine Months
Revenues from external customers	$	1,358,185		$	1,415,276		$	—		$	—		$	1,358,185		$	1,415,276
Margin		469,518			471,474			—			—			469,518			471,474
Operations and maintenance expenses		164,838			154,200			258			275			165,096			154,475
Gain from sale of interest in equity method investment		—			—			49,674			—			49,674			—
Income from equity method investments		—			—			27,748			31,449			27,748			31,449
Operating income (loss) before income taxes		205,055			218,102			(633	)		(444	)		204,422			217,658
Income before income taxes		172,130			180,474			76,875			31,001			249,005			211,475

Reconciliations to the consolidated statements of operations for the three months and nine months ended July 31, 2010 and 2009 are presented below.


	Three Months						Nine Months
In thousands	2010			2009			2010			2009
Operating Income:
Segment operating income (loss) before income taxes	$	(11,145	)	$	(2,881	)	$	204,422		$	217,658
Utility income taxes		7,371			4,199			(68,499	)		(73,035	)
Non-utility activities before income taxes		303			267			633			444

Operating income (loss)	$	(3,471	)	$	1,585		$	136,556		$	145,067


Net Income (Loss):
Income (loss) before income taxes for reportable segments	$	(16,331	)	$	(10,633	)	$	249,005		$	211,475
Income taxes		6,813			3,333			(97,948	)		(84,374	)

Net income (loss)	$	(9,518	)	$	(7,300	)	$	151,057		$	127,101

7. Equity Method Investments

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

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 was approved by the NCUC in May 2010, to expand our firm capacity requirement by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to spend as much as $53.1 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 $11.4 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 and nine months ended July 31, 2010 and 2009, these transportation costs and the amounts we owed Cardinal as of July 31, 2010 and October 31, 2009 are as follows.


	Three Months				Nine Months
In thousands	2010		2009		2010		2009

Transportation costs	$	1,035	$	1,035	$	3,070	$	3,070


	July 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 and nine months ended July 31, 2010 and 2009, these gas storage costs and the amounts we owed Pine Needle as of July 31, 2010 and October 31, 2009 are as follows.


	Three Months				Nine Months
In thousands	2010		2009		2010		2009

Gas storage costs	$	2,922	$	3,207	$	9,236	$	9,157


	July 31,		October 31,
	2010		2009

Trade accounts payable	$	985	$	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 $.42 per diluted share for the nine months ended July 31, 2010. GNGC has no further rights to acquire our remaining 15% interest. We will continue to account for our 15% membership interest in SouthStar using the equity method, as we retain board representation with voting rights equal to GNGC on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.

We have related party transactions as we sell wholesale gas supplies to SouthStar, and we record in operating revenues the amounts billed to SouthStar. For each period of the three months and nine months ended July 31, 2010 and 2009, our operating revenues from these sales and the amounts SouthStar owed us as of July 31, 2010 and October 31, 2009 are as follows.


	Three Months				Nine Months
In thousands	2010		2009		2010		2009

Operating revenues	$	1,905	$	1,459	$	2,965	$	6,638


	July 31,		October 31,
	2010		2009

Trade accounts receivable	$	552	$	639

Summarized financial information provided to us by SouthStar for 100% of SouthStar for the three months and nine months ended June 30, 2010 and 2009 is presented below.


	Three Months				Nine Months
In thousands	2010		2009		2010		2009

Revenues	$	116,618	$	124,278	$	741,754	$	753,707
Gross profit		17,730		23,136		173,625		155,444
Income before income taxes		1,153		6,377		115,321		99,422

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.

We have related party transactions as a customer of Hardy Storage and record in cost of gas the storage costs charged by Hardy Storage. For each period of the three months and nine months ended July 31, 2010 and 2009, these gas storage costs and the amounts we owed Hardy Storage as of July 31, 2010 and October 31, 2009 are

as follows.


	Three Months				Nine Months
In thousands	2010		2009		2010		2009

Gas storage costs	$	2,425	$	2,344	$	6,961	$	6,996


	July 31,		October 31,
	2010		2009

Trade accounts payable	$	808	$	781

8. Financial Instruments and Related Fair Value

Derivative Assets and Liabilities under Master Netting Arrangements

We maintain brokerage accounts to facilitate transactions that support our gas cost hedging plans. 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 $5.1 million and $35.4 million as of July 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 and nine months ended July 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 July 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 July 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	$	2,891	$	—	$	—	$	2,891
Debt and equity securities held as trading securities:
Money markets		259		—		—		259
Mutual funds		679		—		—		679

Total fair value assets	$	3,829	$	—	$	—	$	3,829

Liabilities:
Derivatives held for distribution operations	$	4,694	$	—	$	—	$	4,694

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:
Money markets		169		—		—		169
Mutual funds		272		—		—		272

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 would 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 with the assistance of broker or dealer quotation services or market transactions in either the listed or OTC markets and are classified within Level 2. We have had no transfers between Level 1 and Level 2 during this fiscal year.

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 July 31, 2010	$	792,010	$	927,291
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 July 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 July 31, 2010, we had long gas options providing total coverage of 29.3 million dekatherms, of which 6.1 million dekatherms are limited in upside protection. We have sold options for 3.5 million dekatherms that guarantee a minimum floor price for supply. The long and short options are for the period from September 2010 through August 2011.

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

Fair Value of Derivative Instruments


	Fair Value			Fair Value
In thousands	July 31, 2010			October 31, 2009

Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:

Asset Financial Instruments
Current Assets — Gas purchase derivative assets (September 2010-August 2011)	$	2,891		$
Current Assets — Gas purchase derivative assets (December 2009-November 2010)					2,559

Liability Financial Instruments
Current Liabilities — Gas purchase derivative liabilities (September 2010-August 2011)		4,694
Current Liabilities — Gas purchase derivative liabilities (December 2009-November 2010)					30,603


Total financial instruments, net	$	(1,803	)	$	(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 not designated as hedging instruments under derivative accounting standards would have had on our consolidated statements of operations for the three months and nine months ended July 31, 2010 and 2009, absent the regulatory treatment under our approved PGA procedures.


	Amount of Loss Recognized on Derivatives and Deferred Under PGA Procedures
	Three Months Ended				Nine Months Ended				Location of Loss
	July 31				July 31				Recognized through
In thousands	2010		2009		2010		2009		PGA Procedures

Gas purchase options	$	16,910	$	36,632	$	50,686	$	119,248	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 July 31, 2010, we have five International Swaps and Derivatives Association (ISDA) agreements for the purpose of selling 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 million 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 July 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.

9. Long-Term Debt Instruments

During the nine months ended July 31, 2010, we paid $.5 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.

10. 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, capital expenditures and approved acquisitions. 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 July 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 July 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 $122 million and $306 million, respectively, in LIBOR cost-plus loans. During the three months ended July 31, 2010, short-term borrowings ranged from zero to $135.5 million, and interest rates ranged from .53% to .61% (weighted average of .59%). During the nine months ended July 31, 2010, short-term borrowings ranged from zero to $342.5 million, and interest rates ranged from .48% to .61% (weighted average of .52%). 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 48% at July 31, 2010.

We have corrected the presentation within the consolidated statements of cash flows for the nine months ended July 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.

11. 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 and nine months ended July 31, 2010 and 2009, we recorded compensation expense, and as of July 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% and 30% of the shares vested on September 1, 2009 and 2010, respectively. The remaining 50% of the shares will vest on September 1, 2011. For the three months and nine months ended July 31, 2010 and 2009, we recorded compensation expense, and as of July 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 and nine months ended July 31, 2010 and 2009, and the amounts recorded as liabilities as of July 31, 2010 and October 31, 2009 are presented below.


	Three Months				Nine Months
In thousands	2010		2009		2010		2009

Compensation expense	$	1,342	$	673	$	6,071	$	1,817


	July 31,		October 31,
	2010		2009

Liability	$	10,507	$	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.

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.

12. 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 twenty-two 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 operations 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 July 31, 2010. Additional information concerning letters of credit is included in Note 10 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.

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 (UST) 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 was initiated in April 2010. 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. In June 2010, we conducted our initial investigation which consisted of digging test pits and completing soil and groundwater contamination testing. Our estimate of the total cost to remediate the Reidsville site is $.8 million for which we have recorded a liability.

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). Remediation has been completed, and a consent order imposing usage restrictions on the property was approved and signed by the TDEC in June 2010. The consent order is subject to public comment, which we anticipate being completed in our fourth quarter of 2010. We have incurred $1.5 million through July 31, 2010 for this remediation.

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 have completed soil remediation at the property where our Huntersville LNG facility is located. During the nine months ended July 31, 2010, our estimate of the total cost to remediate the property increased from $1.6 million to $3.1 million, for which we increased our reserve by the additional $1.5 million. We have incurred $2 million through July 31, 2010. In June 2010 we received a determination from NCDENR that no further soil remediation would be required for the Huntersville LNG molecular sieve issue. We are continuing to address the remaining remediation issues, including completion of a groundwater monitoring plan and lead-based paint removal, both scheduled to be implemented in fiscal 2011. For further information, see Note 7 to our Form 10-K for the year ended October 31, 2009.

Since October 31, 2009, we have identified additional USTs that may require remediation. As of July 31, 2010, our undiscounted environmental liability for USTs for which we retain remediation responsibility is $.5 million.

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

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

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.

13. 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 event disclosures related to regulatory matters and share-based payments, see Note 2 and Note 11 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 retain and grow our customer base, the pace of that growth and the levels of energy consumption are impacted by general business and economic conditions, such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in our service areas and the country, and 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, tornadoes and floods, can impact our customers, our suppliers and the pipelines that deliver gas to our distribution system and our distribution and transmission assets. Weather conditions directly influence the supply, demand, distribution and cost of natural gas.

	•		Changes in 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 new issuances or repurchases under our Common Stock Open Market Purchase Program.

Other factors may be described elsewhere in this report. All of these factors are difficult to predict and many of them are beyond our control. For these reasons, you should not rely on these forward-looking statements when making investment decisions. When used in our documents or oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “should,” “could,” “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 52,000

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, Rocky Mount and Wilson, and until April 30, 2010, to Monroe. 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 97% 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 nine months ended July 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 $249 million. For the current nine-month period, 69% 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 nine months ended July 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 31%, which consisted of 3% from regulated non-utility activities and 28% 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 nine months ended July 31, 2010, 86% of our earnings before taxes came from our regulated utility segment, and earnings before taxes from our non-utility segment was 14%, which consisted of 3% from regulated non-utility activities and 11% from unregulated non-utility activities.

For further information on business segments, see Note 6 to the consolidated financial statements in this Form 10-Q. For information about our equity method investments, see Note 7 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 winter weather on bills rendered during the months of November through March for residential and commercial customers. The WNA formula calculates the actual weather variance from normal, using 30 years of history, which increases revenues when weather is warmer than normal and decreases revenues when weather is colder than normal. The 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 current national discussions on climate change policies that will impact how energy is produced and 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. We are also seeking opportunities for regulatory innovation and strategic alliances to advance our customers’ interests in energy conservation and efficiency and environmental stewardship. We are focused 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 future general rate proceeding. For the fiscal year ended October 31, 2009, these rate designs have stabilized our gas utility margin by providing fixed recovery of 70% of our utility margins, including margin decoupling in North Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 18% of our utility margins, including the rate stabilization mechanism in South Carolina and WNA in South Carolina and Tennessee; and volumetric or periodic renegotiation of 12% of our utility margins. For the nine months ended July 31, 2010, the margin decoupling mechanism in North Carolina

reduced margin by $15.1 million, and the WNA in South Carolina and Tennessee reduced margin by $9.2 million.

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 on-shore 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.

We have agreements with Progress Energy Carolinas, Inc., a subsidiary of Progress, to provide natural gas delivery service to their new power generation facilities to be built at their Wayne County, North Carolina power generation site and at their Sutton site near Wilmington, North Carolina. In addition to the environmental benefits associated with using natural gas at these new plants, the construction of the natural gas pipelines for these projects will also add to our natural gas infrastructure in the eastern part of North Carolina and enhance future opportunities for additional economic growth and development. In addition, we have agreements with Duke Energy Carolinas, LLC, a subsidiary of Duke Energy, to provide natural gas delivery service to their new power generation facilities to be built at their Rowan County, North Carolina power generation site and at their Rockingham County power generation site, which are scheduled to be in service no later than October 2010 and November 2011, respectively. We will continue to seek power generation project opportunities to provide long-term transportation service in our market area.

While we are continuing to see 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, specifically focusing on customer conversions to natural gas and power generation opportunities. We are forecasting gross customer addition growth for fiscal 2010 to be 1.0% – 1.2%.

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

In March 2010, President Obama signed the “Patient Protection and Affordable Care Act” and the “Health Care and Education Act of 2010” into law. These health care reform laws require regulatory agencies to issue new regulations implementing many provisions of the laws. While we are not able to assess the full impact of these laws until the implementing regulations have been adopted, based on the information available to us at this time, we do not expect these laws to have a material adverse impact on our financial position, results of operations or cash flows.

Results of Operations

We reported a net loss of $9.5 million for the three months ended July 31, 2010 as compared to a net loss of $7.3 million for the same period in 2009. The following table sets forth a comparison of the components of our consolidated statements of operations for the three months ended July 31, 2010 as compared with the three months ended July 31, 2009.

Operating Statement Components


	Three Months Ended July 31
In thousands, except per share amounts	2010			2009			Variance			Percent Change
Operating Revenues	$	211,603		$	180,201		$	31,402			17.4	%
Cost of Gas		133,706			99,362			34,344			34.6	%

Margin		77,897			80,839			(2,942	)		(3.6	)%

Operations and Maintenance		55,295			50,124			5,171			10.3	%
Depreciation		24,691			24,488			203			0.8	%
General Taxes		8,753			8,841			(88	)		(1.0	)%
Utility Income Taxes		(7,371	)		(4,199	)		(3,172	)		(75.5	)%

Total Operating Expenses		81,368			79,254			2,114			2.7	%

Operating Income (Loss)		(3,471	)		1,585			(5,056	)		(319.0	)%
Other Income (Expense), net of tax		1,791			2,162			(371	)		(17.2	)%
Utility Interest Charges		7,838			11,047			(3,209	)		(29.0	)%

Net Loss	$	(9,518	)	$	(7,300	)	$	(2,218	)		(30.4	)%


Average Shares of Common Stock:
Basic		71,968			72,983			(1,015	)		(1.4	)%
Diluted		71,968			72,983			(1,015	)		(1.4	)%


Loss Per Share of Common Stock:
Basic	$	(0.13	)	$	(0.10	)	$	(0.03	)		(30.0	)%
Diluted	$	(0.13	)	$	(0.10	)	$	(0.03	)		(30.0	)%

We reported a net income of $151.1 million for the nine months ended July 31, 2010 as compared to $127.1 million for the same period in 2009. The following table sets forth a comparison of the components of our consolidated statements of operations for the nine months ended July 31, 2010 as compared with the nine months ended July 31, 2009.

Operating Statement Components


	Nine Months Ended July 31
In thousands, except per share amounts	2010		2009		Variance			Percent Change
Operating Revenues	$	1,358,185	$	1,415,276	$	(57,091	)		(4.0	)%
Cost of Gas		888,667		943,802		(55,135	)		(5.8	)%

Margin		469,518		471,474		(1,956	)		(0.4	)%

Operations and Maintenance		164,838		154,200		10,638			6.9	%
Depreciation		73,529		72,937		592			0.8	%
General Taxes		26,096		26,235		(139	)		(0.5	)%
Utility Income Taxes		68,499		73,035		(4,536	)		(6.2	)%

Total Operating Expenses		332,962		326,407		6,555			2.0	%

Operating Income		136,556		145,067		(8,511	)		(5.9	)%
Other Income (Expense), net of tax		46,653		18,006		28,647			159.1	%
Utility Interest Charges		32,152		35,972		(3,820	)		(10.6	)%

Net Income	$	151,057	$	127,101	$	23,956			18.8	%


Average Shares of Common Stock:
Basic		72,315		73,180		(865	)		(1.2	)%
Diluted		72,668		73,476		(808	)		(1.1	)%


Earnings Per Share of Common Stock:
Basic	$	2.09	$	1.74	$	0.35			20.1	%
Diluted	$	2.08	$	1.73	$	0.35			20.2	%

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

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Three Months Ended
	July 31
	2010			2009			Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		9,395			9,946			(551	)		(5.5	)%
Transportation Volumes		43,502			26,949			16,553			61.4	%

Throughput		52,897			36,895			16,002			43.4	%

Secondary Market Volumes		14,660			9,344			5,316			56.9	%

Customers Billed (at period end)		955,069			941,564			13,505			1.4	%
Gross Customer Additions		2,679			2,774			(95	)		(3.4	)%

Degree Days
Actual		24			43			(19	)		(44.2	)%
Normal		51			51			—			—	%
Percent warmer than normal		52.9	%		15.7	%		n/a			n/a

Number of Employees (at period end)		1,803			1,828			(25	)		(1.4	)%

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

Gas Deliveries, Customers, Weather Statistics and Number of Employees


	Nine Months Ended
	July 31
	2010			2009			Variance			Percent Change

Deliveries in Dekatherms (in thousands):
Sales Volumes		96,260			97,192			(932	)		(1.0	)%
Transportation Volumes		108,046			73,687			34,359			46.6	%

Throughput		204,306			170,879			33,427			19.6	%

Secondary Market Volumes		35,001			32,312			2,689			8.3	%

Customers Billed (at period end)		955,069			941,564			13,505			1.4	%
Gross Customer Additions		8,107			9,024			(917	)		(10.2	)%

Degree Days
Actual		3,393			3,191			202			6.3	%
Normal		3,116			3,119			(3	)		(0.1	)%
Percent colder than normal		8.9	%		2.3	%		n/a			n/a

Number of Employees (at period end)		1,803			1,828			(25	)		(1.4	)%

Operating Revenues

Operating revenues increased $31.4 million for the three months ended July 31, 2010 compared with the same period in 2009 primarily due to the following increases:

	•		$33 million from revenues in secondary market transactions due to increased activity, primarily in the power generation market as a result of weather that was warmer than the same period in 2009. Secondary market transactions consist of off-system sales and capacity release arrangements and are a part of our gas supply management program with regulatory-approved sharing mechanisms between our utility customers and our shareholders.

	•		$3.2 million of gas costs, primarily from increased volume deliveries.

These increases were partially offset by $1.2 million from decreased revenues under the margin decoupling mechanism. As discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in North Carolina adjusts for variations in residential and commercial use per customer, including those due to conservation and weather.

Operating revenues decreased $57.1 million for the nine months ended July 31, 2010 compared with the same period in 2009 primarily due to the following decreases:

	•		$35.1 million primarily from lower gas costs passed through to sales customers.

	•		$15.6 million from decreased revenues under the margin decoupling mechanism.

	•		$8.4 million from decreased revenues under the WNA in South Carolina and Tennessee.

These decreases were partially offset by the following increases:

	•		$3.6 million from revenues in secondary market transactions due to increased activity.

	•		$2.2 million from increased volumes delivered to transportation customers other than power generation.

Cost of Gas

Cost of gas increased $34.3 million for the three months ended July 31, 2010 compared with the same period in 2009 primarily due to the following increases:

	•		$32.8 million from commodity gas costs in secondary market transactions due to increased activity.

	•		$4.2 million of commodity gas costs from increased volume deliveries.

These increases were partially offset by a decrease of $8.5 million of commodity gas costs from lower gas costs passed through to sales customers.

Cost of gas decreased $55.1 million for the nine months ended July 31, 2010 compared with the same period in 2009 primarily due to a decrease of $119.2 million primarily from lower gas costs passed through to sales customers, partially offset by the following increases:

	•		$46.4 million of commodity gas costs from increased volume deliveries.

	•		$4.4 million from commodity gas costs in secondary market transactions due to increased activity.

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

Margin

Margin decreased $2.9 million for the three months ended July 31, 2010 compared with the same period in 2009 primarily due to net adjustments to gas costs and lost and unaccounted for gas.

Margin decreased $2 million for the nine months ended July 31, 2010 compared with the same period in 2009 primarily due the following decreases:

	•		$2.2 million from net adjustments to gas costs, accounts payable and lost and unaccounted for gas.

	•		$.7 million from secondary market transactions.

These increases were partially offset by an increase of $1.1 million from residential growth.

Our utility margin is defined as natural gas revenues less natural gas commodity purchases and fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by management to evaluate utility operations due to the impact of the flow through of wholesale commodity costs, which accounted for 49% of revenues for the nine months ended July 31, 2010, and transportation and storage costs, which accounted for 7%.

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

Our utility margin is 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 $5.2 million for the three months ended July 31, 2010 compared with the same period in 2009 due to the following increases:

	•		$3 million of employee benefits expense increases due primarily to the regulatory deferral of the Tennessee portion of our funding of the pension plan which occurred in the first quarter of 2010 compared to the third quarter of 2009 and an increase in pension expense from a lower discount rate used to determine periodic benefit cost.

	•		$1.7 million in payroll expense primarily from increases in long-term incentive plan accruals priced at a higher current stock price and merit wage increases for non-officer employees.

Operations and maintenance expenses increased $10.6 million for the nine months ended July 31, 2010 compared with the same period in 2009 due to the following increases:

	•		$6.9 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 and merit wage increases for non-officer employees.

	•		$2.2 million in employee benefits due primarily to increases in pension and medical plan coverage expenses.

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, home warranty programs, subsidiary operations, interest income and other miscellaneous income. Non-operating expense is comprised of charitable contributions and other miscellaneous expenses.

The primary changes to Other Income (Expense) for the three months and nine months ended July 31, 2010 as compared with the same periods in 2009 were in income from equity method investments and the gain on the sale of half of our ownership interest in SouthStar in the current nine month period only. 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 $.42 per diluted earnings per share, for the nine months ended July 31, 2010.

Income from equity method investments decreased $1.2 million for the three months ended July 31, 2010 as

compared with the same period in 2009 due to a $1.3 million decrease in earnings from SouthStar primarily due to decreased average customer usage due to warmer weather and changes in the retail pricing mix chosen by SouthStar customers along with a decrease in the average number of customers, partially offset by higher operating margins in the Ohio market. Current quarter earnings are being recorded at the new 15% ownership interest as discussed in our Form 10-K for the year ended October 31, 2009, and SouthStar’s current quarter earnings were less than their prior period earnings.

Income from equity method investments decreased $3.7 million for the nine months ended July 31, 2010 as compared with the same period in 2009 due to a $3.6 million decrease in earnings from SouthStar primarily due to the recording of earnings at the new 15% ownership interest as of January 1, 2010 and a change in the retail pricing mix chosen by SouthStar customers, partially offset by increased average customer usage due to colder weather, favorable changes in the lower of cost or market storage inventory adjustment, higher retail price spreads and increased operating margins in the Ohio and Florida markets.

Utility Interest Charges

Utility interest charges decreased $3.2 million for the three months ended July 31, 2010 compared with the same period in 2009 primarily due to the following:

	•		$5.9 million decrease in interest expense due to an increase in the allowance for borrowed funds used during construction, which is recorded as income, primarily due to $4.1 million of additional allowance for funds used during construction on several major projects.

	•		$3.7 million increase in interest expense due to a decrease in interest charged on amounts due from customers (receivable) as those balances were lower in the current period. These receivable balances earn a carrying charge.

	•		$.5 million decrease in interest expense on long-term debt primarily due to lower amounts of debt outstanding.

Utility interest charges decreased $3.8 million for the nine months ended July 31, 2010 compared with the same period in 2009 primarily due to the following:

	•		$6.3 million increase in interest expense due to a decrease in interest charged on amounts due from customers (receivable), which earn a carrying charge, as those balances were lower in the current period.

	•		$6 million decrease in interest expense due to an increase in the allowance for borrowed funds used during construction as a result of the $4.1 million discussed above.

	•		$1.7 million decrease in interest expense on long-term debt primarily due to lower amounts of debt outstanding.

	•		$1.6 million decrease in interest expense on short-term debt primarily due to lower levels of borrowing in the current period combined with an average interest rate for the current period being approximately 40 basis points lower than the prior year period.

Financial Condition and Liquidity

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

We believe the amounts available to us under our existing and renewed credit facility and the issuance of debt and equity securities, together with cash provided by operating activities, will continue to allow us to meet our needs for working capital, construction expenditures, investments in joint ventures, anticipated debt redemptions, interest payments on debt obligations, dividend payments, pension plan contributions, common share repurchases and other cash needs.

Cash Flows from Operating Activities. The natural gas business is seasonal in nature. Operating cash flows may fluctuate significantly during the year and from year to year due to working capital changes within our utility and non-utility operations. The major factors that affect our working capital are weather, natural gas purchases and prices, natural gas storage activity, collections from customers and deferred gas cost recoveries. We rely on operating cash flows and short-term bank borrowings to meet seasonal working capital needs. During our first and second quarters, we generally experience overall positive cash flows from the sale of flowing gas and gas 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, including continued high unemployment, we may incur additional bad debt expense as a result of 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 $359.6 million and $306.1 million for the nine months ended July 31, 2010 and 2009, respectively. Net cash provided by operating activities reflects a $24 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 decreased $10.7 million in the current period primarily due to the decrease in unbilled volumes and amounts billed to customers reflecting lower gas

			costs in 2010 as compared with 2009, partially offset by weather in the nine months ended July 31, 2010 being 6.3% colder than the same prior period. Volumes sold to residential and commercial customers increased 6.5 million dekatherms primarily due to the colder weather. Total throughput increased 33.4 million dekatherms as compared with the same prior period.

	•		Net amounts due from customers decreased $160 million primarily due to the collection of deferred gas costs through rates.

	•		Gas in storage decreased $3.7 million in the current period primarily due to a decrease in the weighted average cost of gas purchased for injection, partially offset by an increased volume of gas in storage at period end.

	•		Prepaid gas costs decreased $15.3 million in the current period primarily due to gas being made available for sale for the past winter heating season, partially offset by purchases during the summer for the next winter heating season. Under some gas supply contracts, prepaid gas costs incurred during the summer months represent purchases of gas that are not available for sale, and therefore not recorded in inventory, until the start of the winter heating season.

	•		Trade accounts payable increased $4.6 million in the current period primarily due to gas purchases to meet customer demand for the next winter heating season.

Our three state regulatory commissions approve rates that are designed to give us the opportunity to generate revenues to cover our gas costs, fixed and variable non-gas costs and earn a fair return for our shareholders. We have a WNA mechanism in South Carolina and Tennessee that partially offsets the impact of colder- or warmer-than-normal winter 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 $9.2 million and $8.0 million in the nine months ended July 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 $15.1 million and increased margin by $.5 million in the nine months ended July 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 used in investing activities was $83.7 million and $83.9 million for the nine months ended July 31, 2010 and 2009, respectively. Net cash used in investing activities was primarily for utility construction expenditures. Gross utility construction expenditures for the nine months ended July 31, 2010 were $141.7 million as compared to $83.2 million in the same prior period due to $33 million to fund previously announced power generation projects, $16 million for a new operations center in Nashville, Tennessee and approximately $9 million in other infrastructure projects primarily related to major accounts services activities.

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. As of July 31, 2010, we have forecasted capital expenditures of $224 million for fiscal 2010, including $61 million for pipeline infrastructure to serve gas-fired power generation projects in North Carolina. Even though we continue 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, particularly in the power generation market, and are part of our long-range forecasts that are prepared at least annually and typically cover a forecast period of five years.

In October 2009, we reached an agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their Wayne County, North Carolina site. The agreement, approved by the NCUC in May 2010, calls for us to construct 38 miles of 20-inch transmission pipeline along with 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 $89 million and is supported by a long-term service agreement. 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 $53.1 million to expand its system. As a 22% equity venture partner of Cardinal, we will invest as much as $11.4 million in Cardinal’s system expansion.

In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural gas delivery service to a power generation facility to be built at their existing Sutton site near Wilmington, North Carolina. The agreement, approved by the NCUC in May 2010, calls for us to construct 133 miles of transmission pipeline along with compression facilities to provide natural gas delivery service to the plant by June 2013. Our investment in the pipeline and compression facilities is estimated at $224 million, and our service to Progress Energy Carolinas is supported by a long-term service agreement.

The Sutton facilities will also create cost effective expansion capacity that we will use to help serve the growing natural gas requirements of our customers in the eastern part of North Carolina. Since the timing and design scope of the Sutton facilities will serve our system requirements in a more cost effective manner, we suspended

indefinitely our work on our previously announced Robeson LNG peak storage project. We will re-evaluate the Robeson LNG storage project when our system infrastructure and supply capacity growth requirements in North Carolina dictate.

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

Cash Flows from Financing Activities. Net cash used in financing activities was $278.3 million and $215.9 million for the nine months ended July 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 July 31, 2010, our current assets were $275.6 million and our current liabilities were $356 million primarily due to seasonal requirements as discussed above.

As of July 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, capital expenditures and approved acquisitions. 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 $122 million as of July 31, 2010 primarily due to lower commodity gas costs and recovery of amounts due from customers. During the nine months ended July 31, 2010, short-term borrowings ranged from zero to $342.5 million, and interest rates ranged from .48% to .61% (weighted average of .52%).

As of July 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 July 31, 2010, unused lines of credit available under our syndicated five-year revolving credit facility, including the issuance of the letters of credit, totaled $325.3 million.

In July 2010, we began the process of replacing our existing credit facility. During the renewal process, we are evaluating bank participants, commitment size and maturity. Because of credit market conditions, we are anticipating that the costs of a renewed credit facility will be significantly higher and that the term could be significantly shorter than the five-year term of the current facility. It is our intention to have a new credit facility in place by the end of January 2011.

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.

In September 2010, the balance of $60 million of our 7.80% medium-term notes becomes due. In September 2011, the balance of $60 million of our 6.55% medium-term notes becomes due. At this time, we do not anticipate issuing long-term debt in fiscal 2010, but intend to issue $200 – $250 million of long-term debt in the first quarter of fiscal year 2012 for general corporate purposes. We will continue to monitor customer growth

trends in our markets along with the economic recovery from the recession in our service area for the timing of any infrastructure investments that would require the need for additional long-term debt.

During the nine months ended July 31, 2010, we issued $14.3 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 nine months ended July 31, 2010, we repurchased 1.8 million shares for $47.3 million under our Common Stock Open Market Purchase Program, leaving 4.5 million shares available for repurchase under the program.

We have paid quarterly dividends on our common stock since 1956. Provisions contained in certain note agreements under which long-term debt was issued restrict the amount of cash dividends that may be paid. As of July 31, 2010, our retained earnings were not restricted. On September 2, 2010, the Board of Directors declared a quarterly dividend on common stock of $.28 per share, payable October 15, 2010 to shareholders of record at the close of business on September 22, 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 July 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 July 31, 2010 and 2009, and October 31, 2009, are summarized in the table below.


	July 31					October 31					July 31
In thousands	2010		Percentage			2009		Percentage			2009		Percentage
Short-term debt	$	122,000		6	%	$	306,000		15	%	$	257,500		13	%
Current portion of long-term debt		60,000		3	%		60,000		3	%		30,000		1	%
Long-term debt		732,010		39	%		732,512		36	%		792,815		39	%

Total debt		914,010		48	%		1,098,512		54	%		1,080,315		53	%
Common stockholders’ equity		988,815		52	%		927,948		46	%		947,906		47	%

Total capitalization (including short-term debt)	$	1,902,825		100	%	$	2,026,460		100	%	$	2,028,221		100	%

Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financings. We believe our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable cost of funds. In determining our credit ratings, the rating agencies consider a number of quantitative 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 July 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 of our debt agreements. As of July 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 July 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, operating leases and the credit extended by our counterparty in OTC derivative contracts were discussed in Note 4, Note 7 and Note 6, respectively, to the consolidated financial statements in our Form 10-K for the year ended October 31, 2009.

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

required, these disclosures will not have a material impact on our financial position, results of operations or cash flows. These disclosures will be in our Form 10-K for 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 July 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 July 31, 2010, we had $122 million of short-term debt outstanding under our syndicated revolving credit facility at an interest rate of .56%. The carrying amount of our short-term debt approximates fair value. A change of 100 basis points in the underlying average interest rate for our short-term debt would have caused a change in interest expense of approximately $.1 million during the three months ended July 31, 2010 and $1.2 million during the nine months ended July 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 winter 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 third 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 nine months ended July 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.

None.

c) Issuer Purchases of Equity Securities.

The following table provides information with respect to repurchases of our common stock under the Common Stock Open Market Purchase Program and otherwise during the three months ended July 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 (1)
Beginning of the period									4,510,074
05/01/10 - 05/31/10		477	(2)	$	26.52		—		4,510,074
06/01/10 - 06/30/10		44	(2)	$	25.57		—		4,510,074
07/01/10 - 07/31/10		—		$	—		—		4,510,074

Total		521		$	26.44		—


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

(2)		These shares were repurchased from shareholders who rescinded shares under a registration statement which offered to rescind the purchase of certain shares, which is outside of the Common Stock Open Market Purchase Program.

The amount of cash dividends that may be paid on common stock is restricted by provisions contained in certain

note agreements under which long-term debt was issued, with those for the senior notes being the most restrictive. We cannot pay or declare any dividends or make any other distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary to do any of the above (all of the foregoing being “restricted payments”) except out of net earnings available for restricted payments. As of July 31, 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 Amendment No. 1 to Employment Agreement between Piedmont Natural Gas Company, Inc. and Thomas E. Skains, dated as of June 4, 2010 (Substantially identical agreements have been entered into as of the same date with David J. Dzuricky, Kevin M. O’Hara, Michael H. Yount and Franklin H. Yoho)

10.2		Employment Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010

10.3		Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010

		Other Contracts:

10.4		Credit Agreement dated as of April 25, 2006 among Piedmont Natural Gas Company, Inc. and Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, and The Other Lenders Party Hereto

10.5		Credit Agreement dated as of December 3, 2008 among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, and the Other Lenders Party Thereto

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

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

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

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

101.INS		XBRL Instance Document (1)

101.SCH		XBRL Taxonomy Extension Schema (1)

101.CAL		XBRL Taxonomy Calculation Linkbase (1)

101.LAB		XBRL Taxonomy Extension Label Linkbase (1)

101.PRE		XBRL Taxonomy Extension Presentation Linkbase (1)


(1)		Furnished, not filed.

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business

reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance Sheet at July 31, 2010 and October 31, 2009; (3) Consolidated Statements of Operations for the three and nine months ended July 31, 2010 and 2009; (4) Consolidated Statements of Cash Flows for the nine months ended July 31, 2010 and 2009; (5) Consolidated Statements of Comprehensive Income for the three and nine months ended July 31, 2010 and 2009; and (6) Notes to Consolidated Financial Statements.

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

SIGNATURES

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


	Piedmont Natural Gas Company, Inc. (Registrant)
Date September 9, 2010	/s/ David J. Dzuricky
	David J. Dzuricky
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)


Date September 9, 2010	/s/ Jose M. Simon
	Jose M. Simon
	Vice President and Controller (Principal Accounting Officer)

Piedmont Natural Gas Company, Inc.
Form 10-Q
For the Quarter Ended July 31, 2010

Exhibits

Compensatory Contracts:

	10.1		Form of Amendment No. 1 to Employment Agreement between Piedmont Natural Gas Company, Inc. and Thomas E. Skains, dated as of June 4, 2010 (Substantially identical agreements have been entered into as of the same date with David J. Dzuricky, Kevin M. O’Hara, Michael H. Yount and Franklin H. Yoho)

	10.2		Employment Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010

	10.3		Severance Agreement between Piedmont Natural Gas Company, Inc. and Karl W. Newlin, dated as of June 4, 2010

Other Contracts:

	10.4		Credit Agreement dated as of April 25, 2006 among Piedmont Natural Gas Company, Inc. and Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, and The Other Lenders Party Hereto

	10.5		Credit Agreement dated as of December 3, 2008 among Piedmont Natural Gas Company, Inc., Bank of America, N.A., as Administrative Agent, and the Other Lenders Party Thereto

	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